10-K

UNITED STATES
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, 2004

Commission file number 1-08246

Southwestern Energy Company

(Exact name of Registrant as specified in its charter)

Arkansas (State or other jurisdiction of incorporation or organization)		71-0205415 (I.R.S. Employer Identification No.)
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:
Title of each class Common Stock Par Value $0.10	Name of each exchange on which registered New York Stock Exchange
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 xNo 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 xNo 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.

SOUTHWESTERN ENERGY COMPANY
ANNUAL REPORT ON FORM 10-K
For Fiscal Year Ended December 31, 2004

TABLE OF CONTENTS

PART I

		Page
PART I
Item 1.	Business
	Overview	1
	Risk Factors	18
	Glossary of Certain Industry Terms	24
Item 2.	Properties	27
Item 3.	Legal Proceedings	28
Item 4.	Submission of Matters to a Vote of Security Holders	28
PART II
Item 5.	Market for Registrant's Common Equity, Related Shareholder Matters and Issuer Purchases of Equity Securities	30
Item 6.	Selected Financial Data	31
Item 7.	Management's Discussion and Analysis of Financial Condition and Results of Operations
	Overview	33
	Results of Operations	34
	Liquidity and Capital Resources	41
	Critical Accounting Policies	45
	Forward-Looking Information	47
Item 7A.	Quantitative and Qualitative Disclosures about Market Risk	49
Item 8.	Financial Statements and Supplementary Data	51
	Index to Consolidated Financial Statements	51
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	77
Item 9A.	Controls and Procedures	77
Item 9B.	Other Information	77
PART III
Item 10.	Directors and Executive Officers of the Registrant	78
Item 11.	Executive Compensation	78
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	78
Item 13.	Certain Relationships and Related Transactions	78
Item 14.	Principal Accounting Fees and Services	78
PART IV
Item 15.	Exhibits, Financial Statement Schedules	79

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, 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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PART I

ITEM 1. BUSINESS OVERVIEW

        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

        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.

Recent Developments

        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.

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. 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.

Areas of Operation

        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
		Fayetteville	East		Gulf	New
	Conventional	Shale Play	Texas	Permian	Coast	Ventures	Total
Estimated Proved Reserves:
Total Reserves (Bcfe)	239.5	7.5	299.1	60.8	38.6	-	645.5
Percent of Total	37%	1%	47%	9%	6%	-	100%
Percent Natural Gas	100%	100%	96%	45%	84%	-	92%
Percent Proved Developed	81%	47%	83%	90%	93%	-	83%
Production (Bcfe)	20.1	0.1	22.2	7.1	4.6	-	54.1
Capital Investments (millions)	$53.2	$27.9	$156.7	$27.0	$15.7	$1.5	$282.0
Total Gross Wells	890	10	199	388	64	-	1,551
Total Net Acreage	483,223	557,149	31,785	39,047	13,581	47,596	1,172,381
Net Undeveloped Acreage	293,896	552,689	14,850	13,505	2,161	47,596	924,697
PV-10:
Pre-tax (millions)	$492.8	$9.4	$503.9	$118.0	$94.3	-	$1,218.4
After-tax (millions)	$360.9	$6.9	$369.0	$86.4	$69.1	-	$892.3
Percent of Total	40%	1%	41%	10%	8%	-	100%
Percent Operated	80%	100%	89%	28%	45%	-	76%

        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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Acquisitions and Divestitures

        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.

Capital Expenditures

        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

        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.

Sales and Major Customers

        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.

Competition

        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.

Oil Price Controls and Transportation Rates

        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.  

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 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 and sales by producers of natural gas can be made at uncontrolled market prices. With respect to transportation, 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.  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. The implementation of these orders has not had a material adverse effect on our& nbsp;results of operations to date. 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 disproportionately as compared to other natural gas producers and marketers affected by any action taken. 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 can be 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 145,000 customers in northern Arkansas through our subsidiary, Arkansas Western Gas Company. Our utility is focused on capitalizing on the expanding economy and growth in its Northwest Arkansas service territory where approximately 66% of Arkansas Western's customers are located.  In 2001, the Fayetteville-Springdale-Rogers MSA was named by the U.S. Census Bureau as the 6^th fastest growing MSA in the United States. In November 2004, the Milken Institute named Northwest Arkansas as the 7^th "Best Performing City" in the United States, based upon job creation and local economic growth, attributable in part to the presence of Wal-Mart Stores, Inc., the largest public corporation in the world, and other large corporations such as Tyson Foods and J.B. Hunt Transportation.

        Operating income for our natural gas distribution business was $8.5 million in 2004, compared to $6.8 million in 2003 and $7.6 million in 2002. EBITDA generated by our utility segment was $15.6 million in 2004, compared to $13.3 million in 2003 and $14.0 million in 2002. 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. In 2004, our analysis indicated that current revenues in our utility segment were not sufficient to cover the cost of providing utility service and earn the rate of return authorized by the APSC. In December 2004, we filed a request with the Arkansas Public Service Commission, or the APSC, for an adjustment in the utility's rates totaling $9.7 million, or 5.2%, annually. The APSC has ten months to review the filing and reach a decision on the amount of the increase to be approved. Any rate increase allowed would likely be implemented in the fourth quarter of 2005.

        In September 2003, we received regulatory approval for a rate increase totaling $4.1 million annually, and were allowed to recover certain additional costs totaling $2.3 million over a two-year period. Operating income and EBITDA for 2003 include a gain of $1.0 million related to the recovery of these costs. The rate increase was effective on October 1, 2003. Prior to this, Arkansas Western had not had a rate increase since 1996.

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 2004, SEECO successfully bid on gas supply packages representing approximately 55% of the requirements for Arkansas Western for 2005 and 2004, compared to approximately 67% for 2003. The decrease in 2005 and 2004 compared to 2003 was primarily due to more favorable bid pricing on gas supply packages from third-party suppliers.

        Arkansas Western also purchases gas under its gas supply packages 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 4% of the utility's gas purchases are under take-or-pay contracts. 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.

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        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 a cost of gas rider whereby the actual cost of purchased gas above or below the projected level included in the rates is permitted to be billed or is required to be credited to customers. The difference between actual costs of purchased gas and gas costs recovered from customers is deferred each month and is billed or credited, as appropriate, to customers in subsequent months.

Markets and Customers

        Arkansas Western provides natural gas to approximately 128,000 residential, 17,000 commercial, and 175 industrial customers, while also providing gas transportation services to approximately 109 end-use and off-system customers. Total gas throughput in 2004 and 2003 was 25.0 Bcf, compared to 27.3 Bcf in 2002. The lower volumes in 2004 and 2003 were due to fewer volumes being transported off-system, the effects of weather, and customer conservation brought about by high gas prices. Weather in 2004 was 10% warmer than normal and 9% warmer than in 2003. Weather in 2003 was 1% warmer than normal and 1% warmer than the prior year. Weather in 2002 was 2% warmer than normal and 8% colder than the prior year.

        Residential and Commercial. Approximately 89% of the utility's revenues in 2004 were from residential and commercial markets. Residential and commercial customers combined accounted for 57% of total gas throughput for the gas distribution segment in 2004, compared to 60% in 2003 and 56% in 2002. Gas volumes sold to residential customers were 8.5 Bcf in 2004, compared to 9.0 Bcf in 2003 and 2002. Gas sold to commercial customers totaled 5.7 Bcf in 2004, 6.1 Bcf in 2003 and 6.2 Bcf in 2002. The fluctuations in gas volumes sold to both residential and commercial customers were driven primarily by variations in the weather and customer conservation. 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 as tariffs implemented contain a weather normalization clause to lessen the impact of revenue increases and decreases th at 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 9.8 Bcf in 2004, 9.6 Bcf in 2003 and 9.9 Bcf in 2002. 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. Off-system transportation volumes were 1.0 Bcf in 2004, 0.3 Bcf in 2003 and 2.2 Bcf in 2002. The level of off-system deliveries each year generally reflects the changes of on-system demands of our gas distribution systems for our gas production. As of December 31, 2004, a total of 109 customers used the transportation service.

Competition

        Arkansas Western has historically maintained a price advantage over alternative fuels such as electricity, fuel oil, and propane for most applications, enabling it to achieve excellent market penetration levels. However, 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, as well as increasing competition from alternative fuels that has eroded its price advantage. Arkansas Western also has the ability to enter into special contracts with larger commercial and industrial customers that contain lower pricing provisions than the approved tariffs. These contracts can be used to meet competition from alternate fuels or threats of bypass and must be approved by the APSC.

Regulation

        Arkansas Western's utility rates and operations are regulated by the APSC and it operates 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 actively controlling costs and constantly reviewing issues such as system capacity and reliability, obligation to serve, rate design and stranded or transition costs.

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        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. In 2003, the legislation requiring deregulation of the retail sale of electricity was repealed. During 2004, the APSC conducted collaborative meetings to study the feasibility of a large-user access program for electric service choice. On September 30, 2004, the APSC issued a report to the legislature stating that it would not be feasible to implement a large-user access program without shifting costs to other customer classes and recommended that no changes be made to the statutes which would affect access to competitive power supply by large users. To date, the legislature has not taken any action in response to this report. Although Arkansas Western already provides transportation service for its large users, any developments regarding large-user access programs for electricity could set regulatory precedents that would also affect natural gas utilities in the future. These effects may include protection of other customer classes against cost shifting and the regulatory treatment of stranded costs.

        In December 2004, Arkansas Western filed a request with the APSC for an adjustment in the utility's rates totaling $9.7 million, or 5.2%, annually. The APSC has ten months to review the filing and reach a decision on the amount of the increase to be approved. Any rate increase allowed would likely be implemented in the fourth quarter of 2005.

        In September 2003, Arkansas Western received regulatory approval of a rate increase totaling $4.1 million annually, exclusive of costs to be recovered through its cost of gas rider. The order issued by the APSC also entitled Arkansas Western to recover certain additional costs totaling $2.3 million through its purchased gas adjustment clause over a two-year period. The rate increase was effective for all customer bills rendered on or after October 1, 2003.

        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, 2004, Arkansas Western had over-recovered purchased gas costs of $1.4 million, compared to unde r-recovered purchase gas costs of $1.1 million in 2003 and over-recovered purchase gas costs of $5.7 million in 2002.

        Gas distribution revenues in future years will be impacted by customer growth, customer usage and rate increases allowed by the APSC. 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

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. 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 $3.2 million on revenues of $315.0 million in 2004, compared to $2.6 million on revenues of $202.0 million in 2003, and $2.7 million on revenues of $131.1 million in 2002. We marketed 57.0 Bcf of natural gas in 2004, compared to 42.7 Bcf in 2003 and 45.5 Bcf in 2002. The increase in revenues is largely attributable to increased volumes marketed and higher purchased gas costs, while operating income fluctuates depending on the margin we are able to generate between the purchase of the commod ity and the ultimate disposition of the commodity. 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 77% in 2004, 75% in 2003 and 67% in 2002. Our E&P subsidiaries have accounted for an increasing percentage of our total volumes marketed because of a shift in our focus to marketing our own production in order to reduce our credit risk.

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Transportation

        We hold a 25% interest in NOARK, a partnership that owns a 723-mile integrated interstate pipeline system with a total throughput capacity of 330.0 MMcf per day, known as Ozark Gas Transmission System, which became operational November 1, 1998. The remaining 75% interest in the NOARK partnership is owned by Enogex Inc., a subsidiary of OGE Energy Corp.

        Deliveries are 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 155.0 MMcf per day in 2004, compared to 115.0 MMcf per day in 2003 and 168.1 MMcf per day in 2002. The average daily throughput decreased in 2003 due primarily to a temporary curtailment by one of the interstate pipelines that connects with Ozark Gas Transmission System.

        In 2004, Arkansas Western renegotiated a new ten-year transportation contract with Ozark Gas Transmission System for 66.9 MMcf per day of firm capacity. Our share of NOARK's results of operations was a pre-tax loss of $0.4 million in 2004, compared to pre-tax income of $1.1 million in 2003, and a pre-tax loss of $0.3 million in 2002. The pre-tax loss in 2004 was due primarily to a $0.4 negative adjustment from the operator of the pipeline for prior period allocations of income and expenses to the partners. In the first quarter of 2003, NOARK sold a 28-mile portion of its pipeline located in Oklahoma that had limited strategic value to the overall system. Sales proceeds to NOARK were $10.0 million and our share of the proceeds was $2.5 million, resulting in a pre-tax gain to us of $1.3 million recorded in the first quarter of 2003. In addition to the gain recognized on the sale, the improvements experienced recently in operating results of NOARK result primarily from the ability to collect higher transportation rates on interruptible volumes.

Other Revenues

        Our wholly owned subsidiary, A. W. Realty Company, owns an interest in approximately 17 acres of undeveloped real estate at December 31, 2004. A.W. Realty's real estate development activities are concentrated on tracts of land located near our offices in a growing part of Fayetteville, Arkansas. During 2004, we sold 45.5 acres of commercial real estate located in Fayetteville, Arkansas for a pre-tax gain of $5.8 million. During the third quarter of 2003, we sold 18.5 acres of commercial real estate for a pre-tax gain of $1.7 million, and we sold certain fixed assets for a pre-tax gain of $1.3 million. These amounts were reflected in "Gas transportation and other" revenues in our income statement.

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.

        The Ozark Gas Transmission System competes with one interstate pipeline to obtain gas supplies for transportation to other markets. We believe that the Ozark Gas Transmission System will be able to obtain the additional future gas supplies necessary to compete effectively for the transportation of natural gas to end-users and markets served by the interstate pipelines.

Regulation

        The Ozark Gas Transmission System is an interstate pipeline system subject to FERC regulations and FERC-approved tariffs. The FERC has set the maximum transportation rate of Ozark Gas Transmission System 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

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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 net 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 net income, as derived from our audited financial information for the years-ended December 31, 2004, 2003 and 2002:

2004	E&P		Natural Gas Distribution		Marketing and Other		Total
Net income	$	96,307	$	2,617	$	$ 4,652	$	103,576
Depreciation, depletion and amortization (1)		68,794		7,080		191		76,065
Net interest expense		11,537		4,461		994		16,992
Provision for income taxes		55,197		1,471		3,110		59,778
EBITDA	$	231,835	$	15,629	$	$ 8,947	$	256,411
2003
Net income	$	43,713	$	1,423	$	$ 3,761	$	48,897
Depreciation, depletion and amortization (1)		50,922		6,668		172		57,762
Net interest expense		11,911		4,395		1,005		17,311
Provision for income taxes (2)		25,486		767		2,119		28,372
EBITDA	$	132,032	$	13,253	$	$ 7,057	$	152,342
2002
Net income	$	11,149	$	2,241	$	$ 921	$	14,311
Depreciation, depletion and amortization (1)		48,570		6,581		201		55,352
Net interest expense		16,597		3,868		1,001		21,466
Provision for income taxes		6,744		1,316		648		8,708
EBITDA	$	83,060	$	14,006	$	$ 2,771	$	99,837

(1)Depreciation, depletion and amortization includes the amortization of restricted stock issued under our incentive compensation plans.

(2)Provision for income taxes for 2003 includes the tax benefit associated with the cumulative effect of adoption of accounting principle.

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. Although we believe that we are in substantial compliance with applicable environmental laws and

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regulations and that continued compliance with existing requirements will not have a material adverse impact on us, there can be 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 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 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, a portion 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 b y 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 wa ters. 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.

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Employees

        At December 31, 2004, we had 595 total employees, including 347 employed by our natural gas utility, of which 26 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.

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;
   
• 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.

        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 and profitability would suffer.

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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 percent, 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, including the impact of derivatives qualifying as hedges. 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.

We may have difficulty financing our planned capital expenditures which could adversely affect our 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 particular, our planned capital expenditures for 2005 are expected to exceed the net cash generated by our operations by up to $85 million assuming NYMEX commodity prices of $6.00 per Mcf for natural gas and $36.00 per barrel for oil and that we achieve production results consistent with our forecasts. We expect to borrow under our credit facility to fund capital expenditures that are in excess of our net cash flow. Our ability to borrow under our credit facility is subject to certain conditions. At December 31, 2004, we were in compliance with the borrowing conditions of our credit facility and expect that we will be able to borrow under the facility throughout 2005. However, we cannot assure you that we will be able to borrow under our credit facility as necessary t o fund our capital expenditures. We also cannot be certain that other 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. Any such curtailment could have a material adverse effect on our results and future operations.

Although our estimated natural gas and oil reserve data is independently audited, our estimates may still prove to be inaccurate.

        Our reserve data represents the estimates of our reservoir engineers made under the supervision of our management. Our reserve estimates are audited each year by Netherland, Sewell & Associates, Inc., an independent petroleum engineering firm. In conducting its audit, the engineers and geologists of Netherland, Sewell & Associates study the Company's major properties in detail and independently develop reserve estimates. Minor properties (typically representing less than 20% of the total reserve estimates) are also audited, but less rigorously. In its report, Netherland, Sewell & Associates treats differences between estimates prepared by us and them that are within 10% in aggregate as immaterial.

        Reserve estimates are prepared for each of our properties annually by the reservoir engineers assigned to the asset management team in the geographic locations in which the property is located. These estimates are reviewed by senior engineers who are not part of the asset management teams and by the executive vice president of our E&P subsidiaries. Finally, the estimates of our proved reserves together with the audit report of Netherland, Sewell & Associates, Inc. are reviewed by our Audit Committee. We cannot assure you that our internal controls sufficiently address the numerous uncertainties and risks that are inherent in estimating quantities of natural gas and oil reserves and projecting future rates of production and timing of development expenditures as many factors are beyond our control. We incorporate many factors and assumptions into our estimates including:

• Expected reservoir characteristics based on geological, geophysical and engineering assessments;

 
• Future production rates based on historical performance and expected future operating and investment activities;

 
• Future oil and gas prices and quality and locational differentials; and

 
• Future development and operating costs.

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        Although we believe our assumptions are reasonable based on the information available to us at the time we prepare our estimates, our actual results could vary considerably which could cause material variances in the estimated quantities of proved natural gas and oil reserves in the aggregate and for a particular geographic location or future net revenues, including production, revenues, taxes and development and operating expenditures. 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. In 2002, these reserve revisions resulted in a 2.5 Bcfe upward change in our proved reserve s in the aggregate. In 2003, reserves were revised downward by 15.5 Bcfe due to poorer-than-expected well performance related to our South Louisiana properties. In 2004, the reserves were also revised downward by 12.7 Bcfe due primarily to slightly higher decline rates related to some of the well in our Overton Field in East Texas. These revisions represented no greater than 3% of our total reserve estimates in each of these years, which we believe is indicative of the effectiveness of our internal controls. Because we review our reserve projections for every property at the end of every year, any material change in a reserve estimate is included in subsequent reserve reports.

        Finally, recovery of undeveloped reserves generally requires significant capital expenditures and successful drilling operations. At December 31, 2004, approximately 17% of our estimated proved reserves were undeveloped. Our reserve data assume that we can and will make these expenditures and conduct these operations successfully, which may not occur.

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

        At December 31, 2004, we had long-term indebtedness of $325.0 million, excluding our several guarantee of NOARK's debt obligation. Of this amount, $100.0 million was bank indebtedness under our then in effect revolving credit facility. As of March 3, 2005, we had approximately $80 million outstanding under our existing $500 million revolving credit facility. As indicated in the risk factor headed "We may have difficulty financing our planned capital expenditures which could adversely affect our growth" above, we also expect to incur significant additional indebtedness in order to fund a portion of capital expenditures in 2005.

        The terms of the indenture relating to our outstanding senior notes and our revolving credit facilities 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;

 
• redeeming stock or redeeming 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

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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. 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 or, if completed, that the terms will be favorable to us.

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.

Our drilling plans for the Fayetteville Shale play are subject to change.

        As of December 31, 2004, we have only drilled 21 wells relating to our Fayetteville Shale play. The wells were drilled in areas that represent a very small sample of our large acreage position. Our drilling plans with respect to our Fayetteville Shale play are flexible and are dependent upon a number of factors, including 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. The determination as to whether we continue to drill prospects in the Fayetteville Shale may depend on any of the following factors:

• receipt of additional seismic or other geologic data or reprocessing of existing data;

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

 
• material changes in natural gas prices;

 
• changes in the estimates of costs to drill or complete wells;

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

 
• our ability to reduce our exposure to costs and drilling risks;

 
• the costs and availability of drilling equipment; success or failure of wells drilled in similar formations or which would use the same production facilities; or

 
• availability and cost of capital.

        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.

Our exploration, development and drilling efforts and our operations of our wells may not be profitable or achieve our targeted returns.

        We require significant amounts of undeveloped leasehold acreage in order to further our development efforts. Exploration, development, drilling and production activities are subject to many risks, including the risk that no commercially productive reservoirs will be discovered. We invest in property, including undeveloped leasehold acreage that we believe will result in projects that will add value over time. However, we cannot assure you that all prospects will result in viable projects or that we will not abandon our initial investments. Additionally, there can be no assurance that leasehold acreage acquired by us will be profitably developed, that new wells drilled by us in prospects that we pursue will be productive or that we will recover all or any portion of our investment in such leasehold acreage or wells. Drilling for natural gas and oil may involve unprofitable efforts, not only from dry wells but also from wells that are product ive but do not produce sufficient net reserves to return a profit after deducting drilling, operating and other costs. In addition, wells

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that are profitable may not achieve our targeted rate of return. Our ability to achieve our target PVI results are dependent upon the current and future market prices for natural gas and crude oil, costs associated with producing natural gas and crude oil and our ability to add reserves at an acceptable cost. We rely to a significant extent on seismic data and other advanced technologies in identifying leasehold acreage prospects and in conducting our exploration activities. The seismic data and other technologies we use do not allow us to know conclusively prior to acquisition of leasehold acreage or drilling a well whether 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.

        In addition, we may not be successful in implementing our business strategy of controlling and reducing our drilling and production costs in order to improve our overall return. 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.

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, production, development and gas distribution and marketing 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 regulations, including environmental regulation. The natural gas and oil regulatory environment could change in ways that might substantially increase these costs. Hydrocarbon-producing states regulate conservation practices and the protection of correlative rights. These regulations affect our operations and limit the quantity of hydrocarbons we may produce and sell. In addition, at the U.S. federal level, the Federal Energy Regulatory Commission regulates interstate transportation of natural gas under the Natural Gas Act. 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, and an owner of gas gathering, transmission and distribution systems, we are subject to various federal, state and local regulations relating to discharge of materials into, and protection of, the environment. These 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 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 were 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.

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

        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.

        We do not 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. Approximately 24% of our gas and oil properties, based on PV10 value, are operated by other companies. Our dependence on the operator and other working interest owners

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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 are beyond our control, including the operator's expertise and financial resources, approval of other participants for drilling wells and utilization 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.

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 some of 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 key 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 hedging activities may prevent us from benefiting from price increases 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. As of December 31, 2004, we had hedges on approximately 70% to 80% of our targeted 2005 natural gas production and approximately 60% to 70% of our targeted 2005 oil production. Our price risk management activities reduced revenues by $35.6 million in 2004, $37.4 million in 2003 and $6.1 million in 2002. 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;

23

• 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 recorded on our financial statements. We refer you to "Quantitative and Qualitative Disclosures about Market Risk."

A decline in the condition of the capital markets or a substantial rise in interest rates could harm us.

        If the condition of the capital markets utilized by us to finance our operations materially declines, we might not be able to finance our operations on terms we consider acceptable. In addition, a substantial rise in interest rates would increase the cost of borrowing under our credit facility and decrease our net cash flows.

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.

"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 heating 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. 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.

"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

24

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.

"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. For additional information, see the SEC's definition in Rule 4-10(a)(3) of Regulation S-X, which is available at the SEC's website, http://www.sec. gov/divisions/corpfin/forms/regsx.htm#gas.

"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. For additional information, see the SEC's definition in Rule 4-10(a)(2)(i) through (iii) of Regulation S-X, which is available at the SEC's website, http://www.sec. gov/divisions/corpfin/forms/regsx.htm#gas.

"Proved undeveloped reserves"  Proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those drilling units that offset productive units and that are reasonably certain of production when drilled. For additional information, see the SEC's definition in Rule 4-10(a)(4) of Regulation S-X, which is available at the SEC's website, http://www.sec. gov/divisions/corpfin/forms/regsx.htm#gas.

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"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." After-tax PV-10 is also referred to as "standardized measure" and is net of future income tax expense.

"PVI" A measure that is computed for projects by dividing the dollars invested into the PV-10 resulting from the investment.

"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 an oil or gas reservoir, as a conservation measure. Well spacing is normally accomplished by order of the regulatory conservation commission. The order may be statewide in its application (subject to change for local conditions) or it may be entered for each field after its discovery.

"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.

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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 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 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 Overview -- Exploration and Production."

Leasehold acreage as of December 31, 2004:

	Undeveloped		Developed
	Gross	Net	Gross	Net
Conventional Arkoma	362,447	293,896	285,323	189,327
Fayetteville Shale Play(1)	673,705	552,689	4,480	4,460
East Texas	18,986	14,850	19,380	16,935
Permian Basin	21,603	13,505	88,936	25,542
Gulf Coast	3,619	2,161	29,601	11,420
Exploration and New Ventures	82,688	47,596	-	-
	1,163,048	924,697	427,720	247,684

(1) Assuming that the Company does not drill successful wells to develop the acreage or does not attempt to extend the leases in our undeveloped acreage, 29,298 net acres will expire in 2007 in the Fayetteville Shale play.

Producing wells as of December 31, 2004:

	Gas		Oil		Total		Gross Wells Operated
	Gross	Net	Gross	Net	Gross	Net
Conventional Arkoma	890	446.4	-	-	890	446.4	401
Fayetteville Shale Play	10	9.9	-	-	10	9.9	10
East Texas	197	187.6	2	2.0	199	189.6	178
Permian Basin	123	21.8	265	118.9	388	140.7	33
Gulf Coast	46	22.0	18	11.5	64	33.5	25
	1,266	687.7	285	132.4	1,551	820.1	647

Wells drilled during the year:

	Exploratory
	Productive Wells		Dry Holes		Total
Year	Gross	Net	Gross	Net	Gross	Net
2004	16.0	15.2	5.0	3.7	21.0	18.9
2003	9.0	5.6	1.0	0.6	10.0	6.2
2002	9.0	4.2	6.0	2.7	15.0	6.9
	Development
	Productive Wells		Dry Holes		Total
Year	Gross	Net	Gross	Net	Gross	Net
2004	150.0	113.0	9.0	2.8	159.0	115.8
2003	101.0	74.6	15.0	5.2	116.0	79.8
2002	36.0	27.5	10.0	5.1	46.0	32.6

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Wells in progress as of December 31, 2004:

	Gross	Net
Exploratory	2.0	2.0
Development	22.0	15.3
Total	24.0	17.3

        During 2004, 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.

Miles of Pipe:

        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 Overview -- Natural Gas Distribution."

	Total
Gathering	392
Transmission	1,032
Distribution	3,992
	5,416

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 condu ct 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, 2004, to a vote of security holders, through the solicitation of proxies or otherwise.

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Executive Officers of the Registrant

Name	Officer Position	Age	Years Served as Officer
Harold M. Korell	President, Chief Executive Officer and Chairman of the Board	60	8
Greg D. Kerley	Executive Vice President and Chief Financial Officer	49	15
Richard F. Lane	Executive Vice President, Southwestern Energy Production Company and SEECO, Inc.	47	6
Mark K. Boling	Executive Vice President, General Counsel and Secretary	47	3
Alan N. Stewart	Executive Vice President, Arkansas Western Gas Company	60	1

        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. Stewart was appointed to his current position effective March 2004. Prior to joining the Company, he provided professional consulting services for clients in the energy and LNG industries in California. Previously, Mr. Stewart was employed with San Diego Gas and Electric Company and Southern California Gas Company where he served in a wide range of managerial and leadership positions during a 31-year career.

        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, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

        Our common stock is traded on the New York Stock Exchange under the symbol "SWN." At December 31, 2004, we had 2,022 shareholders of record. The following prices represent closing market transactions on the New York Stock Exchange.

	Range of Market Prices
Quarter Ended	2004		2003
March 31	$24.45	$19.35	$13.23	$10.91
June 30	$28.67	$23.86	$16.35	$12.70
September 30	$42.38	$29.67	$18.55	$14.24
December 31	$54.90	$41.30	$25.48	$18.13

        We have indefinitely suspended payment of quarterly cash dividends on our common stock.

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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 five-year period ended December 31, 2004. This information and the notes thereto are 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."

		2004		2003		2002		2001		2000
	(in thousands except share, per share, shareholder data and percentages)
Financial Review Operating revenues Exploration and production	$	286,924	$	176,245	$	122,207	$	153,937	$	110,920
Gas distribution		152,449		137,356		115,850		147,282		151,234
Gas marketing and other		321,226		205,449		131,514		190,773		208,196
Intersegment revenues		(283,462)		(191,649)		(108,069)		(147,065)		(106,467)
		477,137		327,401		261,502		344,927		363,883
Operating costs and expenses Gas purchases - utility		64,311		52,585		48,388		68,161		58,669
Gas purchases - marketing		60,804		39,428		37,927		68,010		133,221
Operating and general		78,231		70,479		64,600		64,108		59,790
Unusual items		--		--		--		--		111,288
Depreciation, depletion and amortization		73,674		55,948		53,992		52,899		45,869
Taxes, other than income taxes		17,830		11,619		10,090		9,080		8,515
		294,850		230,059		214,997		262,258		417,352
Operating income (loss)		182,287		97,342		46,505		82,669		(53,469)
Interest expense, net		(16,992)		(17,311)		(21,466)		(23,699)		(24,689)
Other income (expense)		(362)		797		(566)		(799)		1,997
Minority interest in partnership		(1,579)		(2,180)		(1,454)		(930)		--
Income (loss) before income taxes and accounting    change		163,354		78,648		23,019		57,241		(76,161)
Income taxes Current		--		--		--		--		--
Deferred		59,778		28,896		8,708		21,917		(29,474)
		59,778		28,896		8,708		21,917		(29,474)
Income before accounting change		103,576		49,752		14,311		35,324		(46,687)
Cumulative effect of adoption of accounting    principle		--		(855)		--		--		--
Net income (loss)	$	103,576	$	48,897	$	14,311	$	35,324	$	(46,687)
Net cash provided by operating activities	$	237,897	$	109,099	$	77,574	$	144,583	$	(53,203)	(1)
Return on equity		23.1%		14.3%		8.1%		19.3%		n/a
Common Stock Statistics Earnings (loss) per share:
Basic	$	2.90	$	1.46	$	.57	$	1.40	$	(1.86)
Diluted	$	2.80	$	1.43	$	.55	$	1.38	$	(1.86)
Cash dividends declared and paid per share	$	--	$	--	$	--	$	--	$	.12
Book value per average diluted share	$	12.11	$	9.98	$	6.81	$	7.15	$	5.64
Market price at year-end	$	50.69	$	23.90	$	11.45	$	10.40	$	10.38
Number of shareholders of record at year-end		2,022		2,026		2,079		2,124		2,192
Average diluted shares outstanding		36,962,772		34,237,934		26,052,238		25,601,110		25,043,586

        (1) Net cash provided by operating activities for 2000 would have been $58.1 million excluding the effects of unusual items for the Hales judgment and other litigation.

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	2004		2003		2002		2001		2000
Capitalization (in thousands)
Total debt, including current portion	$	325,000	$	278,800	$	342,400	$	350,000	$	396,000
Common shareholders' equity(1)		447,677		341,561		177,488		183,086		141,291
Total capitalization	$	772,677	$	620,361	$	519,888	$	533,086	$	537,291
Total assets	$	1,146,144	$	890,710	$	740,162	$	743,123	$	705,378
Capitalization ratios:
Debt		42.1%		44.9%		65.9%		65.7%		73.7%
Equity		57.9%		55.1%		34.1%		34.3%		26.3%
Capital Expenditures (in millions) (2)
Exploration and production	$	282.0	$	170.9	$	85.2	$	99.0	$	69.2
Gas distribution		7.3		8.2		6.1		5.3		6.0
Other		5.7		1.1		0.8		1.8		0.5
	$	295.0	$	180.2	$	92.1	$	106.1	$	75.7
Exploration and Production
Natural gas:
Production, Bcf		50.4		38.0		36.0		35.5		31.6
Average price per Mcf, including hedges	$	5.21	$	4.20	$	3.00	$	3.85	$	2.88
Average price per Mcf, excluding hedges	$	5.80	$	5.15	$	3.11	$	4.16	$	3.92
Oil:
Production, MBbls		618		531		682		719		676
Average price per barrel, including hedges	$	31.47	$	26.72	$	21.02	$	23.55	$	22.99
Average price per barrel, excluding hedges	$	40.55	$	29.66	$	23.94	$	23.58	$	29.38
Total gas and oil production, Bcfe		54.1		41.2		40.1		39.8		35.7
Lease operating expenses per Mcfe	$	.38	$	.39	$	.45	$	.45	$	.40
Taxes other than income taxes per Mcfe	$	.28	$	.22	$	.19	$	.17	$	.16
Proved reserves at year-end:
Natural gas, Bcf		594.5		457.0		374.6		355.8		331.8
Oil, MBbls		8,508		7,675		6,784		7,704		8,130
Total reserves, Bcfe		645.5		503.1		415.3		402.0		380.6
Gas Distribution(3)
Sales and transportation volumes, Bcf:
Residential		8.5		9.0		9.0		8.4		7.9
Commercial		5.7		6.1		6.2		6.1		6.0
Industrial		1.3		1.2		1.5		2.5		2.9
End-use transportation		8.5		8.4		8.4		7.0		6.3
		24.0		24.7		25.1		24.0		23.1
Off-system transportation		1.0		0.3		2.2		3.1		3.1
		25.0		25.0		27.3		27.1		26.2
Customers at year-end:
Residential		127,622		124,776		122,906		119,856		119,024
Commercial		16,815		16,623		16,448		16,177		16,282
Industrial		175		174		189		209		228
		144,612		141,573		139,543		136,242		135,534
Degree days		3,678		3,969		3,950		3,654		3,994
Percent of normal		90%		99%		98%		91%		100%

(1) Shareholders' equity included accumulated other comprehensive losses of $19.8 million in 2004 ($18.8 million related to our cash flow hedges and $1.0 million related to our pension plan), $12.5 million in 2003 ($12.0 million related to our cash flow hedges and $0.5 million related to our pension plan), and $17.4 million in 2002 ($14.0 million related to our cash flow hedges and $3.4 million related to our pension plan), and accumulated other comprehensive income of $5.8 million in 2001 related to our cash flow hedges.

(2) Capital expenditures for 2004 and 2003 included $3.9 million and $12.0 million, respectively, related to the change in accrued expenditures between years.

(3) Gas distribution statistics for 2000 exclude the operations of Missouri properties which were sold May 31, 2000.

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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

        This Form 10-K contains forward-looking statements that involve risks and uncertainties. Our actual results could differ materially from those anticipated in forward-looking statements for many reasons, including the risks described in "Risk Factors" and elsewhere in this annual report. You should read the following discussion with the "Selected Financial Data" and our financial statements and related notes included elsewhere in this Form 10-K.

OVERVIEW

        Southwestern Energy Company is an integrated energy company primarily focused on natural gas. Our primary business is the exploration, development and production of natural gas and crude oil, with operations principally located in Arkansas, Oklahoma, Texas, New Mexico and Louisiana. We also operate integrated natural gas distribution systems in northern Arkansas. As a complement to our other businesses, we provide marketing services in each of our core areas of operation. We operate our business in three segments: Exploration and Production, Natural Gas Distribution and Natural Gas Marketing.

        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 creating at least $1.30 of discounted pre-tax PVI for each dollar we invest in our Exploration and Production, or 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.

        In 2004, our gas and oil production continued to increase, reaching 54.1 Bcfe, up from 41.2 Bcfe in 2003 and 40.1 Bcfe in 2002. The 31% increase in 2004 production resulted from an increase in production from our Overton Field in East Texas due to accelerated development, increased production in the Arkoma Basin and production from our River Ridge discovery in New Mexico.

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

        We reported net income of $103.6 million in 2004, or $2.80 per share on a fully diluted basis, up from $48.9 million, or $1.43 per share in 2003. In 2002, we reported net income of $14.3 million, or $0.55 per share on a fully diluted basis. The increases in net income in 2004 and 2003 were a result of increased production volumes and higher realized natural gas and oil prices in our E&P segment with higher gas prices being the primary factor in 2003. Operating income for our E&P segment was $164.6 million in 2004, up from $84.7 million in 2003 and $36.0 million in 2002. The increases in operating income for our E&P segment in 2004 and 2003 were also due to increased production volumes and higher realized prices. Operating income for our gas distribution segment was $8.5 million in 2004, compared to $6.8 million in 2003 and $7.6 million in 2002. The increase in operating income for our gas distribution segment in 2004 resulted primarily from increased rates implemented in October 2003. Our cash flow from operating activities was $237.9 million in 2004, compared to $109.1 million in 2003 and $77.6 million in 2002.

        In our E&P segment, we achieved a reserve replacement ratio of 365% in 2004 at a finding and development cost of $1.43 per Mcfe, including reserve revisions. Our year-end reserves grew 28% to 645.5 Bcfe, up from 503.1 Bcfe at the end of 2003. Our results were primarily fueled by our continued drilling success in our Overton Field in East Texas as well as our continued successful conventional drilling program in the Arkoma Basin.

        Our capital investments totaled $295.0 million in 2004, up from $180.2 million in 2003 and $92.1 million in 2002. We invested $282.0 million in our E&P segment in 2004, compared to $170.9 million in 2003 and $85.2 million in 2002. Funds for our 2004 capital investments were provided by cash flow from operations and borrowings under our unsecured revolving line of credit.

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        Our cash flow and earnings provided by operating results in 2004 helped us to decrease our total debt-to-capitalization ratio to 42% at December 31, 2004, compared to 45% at December 31, 2003.

        Capital investments for 2005 are planned to be up to $352.7 million, including up to $339.0 million for our E&P segment, which is an increase of 20% over our E&P capital investments in 2004. The $339.0 million of exploration and production investments includes up to $100.2 million for the accelerated development of our Fayetteville Shale play that was announced during 2004, assuming that we continue to be encouraged by our drilling results. 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. In addition to the planned investments in the Fayetteville Shale play, our E&P investments in 2005 will primarily be focused on our lower-risk development drilling programs in East Texas and other conventional drilling in the Arkoma Basin. In 2005, we are targeting production to be approximately 61.0 Bcfe to 63.0 Bcfe, compared to 54.1 Bcfe in 2004, an increase of approximately 13% to 17%. We expect our capital investments in 2005 will be funded by cash flow from operations and borrowings under our revolving credit facility.

        With today's commodity price environment, our current capital program and our inventory of projects for the future, we believe we are well-positioned to continue to build upon the momentum achieved in recent years.

RESULTS OF OPERATIONS

Exploration and Production

	Year Ended December 31,
	2004		2003		2002
Revenues (in thousands)	$	286,924	$	176,245	$	122,207
Operating income (in thousands)	$	164,585	$	84,737	$	36,048
Gas production (Bcf)		50.4		38.0		36.0
Oil production (MBbls)		618		531		682
Total production (Bcfe)		54.1		41.2		40.1
Average gas price per Mcf, including hedges	$	5.21	$	4.20	$	3.00
Average gas price per Mcf, excluding hedges	$	5.80	$	5.15	$	3.11
Average oil price per Bbl, including hedges	$	31.47	$	26.72	$	21.02
Average oil price per Bbl, excluding hedges	$	40.55	$	29.66	$	23.94
Average unit costs per Mcfe
Lease operating expenses	$	0.38	$	0.39	$	0.45
General & administrative expenses	$	0.36	$	0.41	$	0.32
Taxes other than income taxes	$	0.28	$	0.22	$	0.19
Full cost pool amortization	$	1.20	$	1.17	$	1.16

Revenues, Operating Income and Production

        Revenues. Our E&P revenues increased 63% in 2004 to $286.9 million compared to $176.2 million in 2003. Increased gas production volumes and higher prices received for our natural gas and oil production contributed equally to the increased revenues. Revenues increased 44% in 2003 from $122.2 million in 2002. The increase was primarily due to higher prices received for our natural gas and oil production. Future changes in revenue can not be predicted reliably due to the market volatility of natural gas and crude oil prices.

        Operating Income. Operating income from our E&P segment was $164.6 million in 2004, up from $84.7 million in 2003 and $36.0 million in 2002. The increases in 2004 and 2003 were due to the increases in revenues, partially offset by increases in operating costs and expenditures.

        Production. Gas and oil production totaled 54.1 Bcfe in 2004, 41.2 Bcfe in 2003 and 40.1 Bcfe in 2002. The increase in 2004 production resulted primarily from an 8.2 Bcfe increase in production from our Overton Field in East Texas, a 1.3 Bcfe increase in our Arkoma Basin production, and 3.2 Bcfe from our River Ridge discovery in New Mexico. The increase in 2003 production resulted from a 7.7 Bcfe increase in production from our Overton Field, partially offset by a 3.3 Bcfe decline experienced in our South Louisiana properties and a loss of production resulting from the November 2002 sale of our non-strategic Mid-Continent properties that contributed approximately 2.5 Bcfe of production annually.

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Although we expect production volumes in the near-term to increase, we cannot guarantee our longer-term success in discovering, developing, and producing reserves. Our ability to discover, develop and produce reserves is dependent upon a number of factors, many of which are beyond our control, including the availability of capital, the timing and extent of changes in natural gas and oil prices and competition. There are also many risks inherent to the discovery, development and production of natural gas and oil. We refer you to "Risk Factors" in Item 1 of Part I of this Form 10-K for a discussion of these risks and the impact they could have on our financial condition and results of operations.

        Gas sales to unaffiliated purchasers were 45.0 Bcf in 2004, up from 32.1 Bcf in 2003 and 30.6 Bcf in 2002. Sales to unaffiliated purchasers are primarily made under contracts that reflect current short-term prices and are subject to seasonal price swings. Intersegment sales to Arkansas Western were 5.4 Bcf in 2004, 5.9 Bcf in 2003 and 5.4 Bcf in 2002. The changes in intersegment sales volumes reflect both the effects of weather and the ability of our E&P segment to obtain gas supply contracts that are periodically placed out for bids. Weather in 2004, as measured in degree days, was 10% warmer than normal and 9% warmer than the prior year. Weather in 2003 was 1% warmer than normal and slightly above the prior year. Our gas production provided approximately 40% of the utility's requirements in 2004, 41% in 2003 and 37% in 2002.

        We expect future increases in demand for our gas production to come primarily from sales to unaffiliated purchasers. Future sales to Arkansas Western's gas distribution systems will be dependent upon our success in obtaining gas supply contracts with the utility systems. We expect to continue to bid to obtain these gas supply contracts, however there can be no assurance that we 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 also sell gas directly to industrial and commercial transportation customers located on Arkansas Western's gas distribution systems. 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. Additionally, we hold a large amount of undeveloped leasehold acreage and pro ducing acreage, and have an inventory of drilling leads, prospects and seismic data that will continue to be evaluated and developed in the future. Our exploration programs have been directed primarily toward natural gas in recent years.

Commodity Prices

        In order to ensure certain levels of cash flow, 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 (we refer you to Item 7A of this Form 10-K and Note 8 to the consolidated financial statements for additional discussion). The average price realized for our gas production, including the effects of hedges, was $5.21 per Mcf in 2004, $4.20 per Mcf in 2003 and $3.00 per Mcf in 2002. The changes in the average price realized primarily reflect changes in average annual spot market prices and the effects of our price hedging activities. Our hedging activities lowered the average gas price $0.59 per Mcf in 2004, $0.95 per Mcf in 2003 and $0.11 per Mcf in 2002. Additionally, we have historically received demand charges re lated to sales made to our utility segment, which has increased our average gas price realized. Disregarding the impact of hedges, we would normally 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 received under the contracts covering our intersegment sales to our utility systems.

        We realized an average price of $31.47 per barrel, including the effects of hedges, for our oil production for the year ended December 31, 2004, up from $26.72 per barrel for 2003 and $21.02 per barrel for 2002. Our hedging activities lowered the average oil price $9.08 per barrel in 2004, $2.94 per barrel in 2003 and $2.92 per barrel in 2002. Disregarding the impact of hedges, we expect the average price received for our oil production to be approximately $1.25 lower than posted spot market prices.

        At December 31, 2004, we had hedges in place on 71.6 Bcf of 2005 and 2006 gas production. At December 31, 2004 we had hedges in place on 480,000 barrels of 2005 and 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 March 3, 2005, we have hedged approximately 70% to 80% of our 2005 anticipated gas production level and 60% to 70% of our 2005 anticipated oil production level.

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Operating Costs and Expenses

        Lease operating expenses per Mcfe for the E&P segment were $0.38 in 2004, down from $0.39 in 2003 and $0.45 in 2002. Lease operating expenses per unit of production decreased in 2004 due primarily to a 31% increase in our production volumes. In 2004, lease operating expenses per unit averaged $0.18 per Mcfe for Overton Field and $0.31 per Mcfe for our conventional Arkoma Basin production. These two areas accounted for 78% of our total production in 2004. Although the per unit operating costs for these areas will continue to remain low compared to other operating areas, they will increase over time due to the natural maturing of the fields and inflationary pressures on total costs. We do not have sufficient operating history for our Fayetteville Shale play to forecast with accuracy the future operating costs that we may incur assuming the successful development of this play.

        Taxes other than income taxes per Mcfe were $0.28 in 2004, compared to $0.22 in 2003 and $0.19 in 2002. The increase in 2004 taxes other than income taxes per Mcfe was due to increased severance and ad valorem taxes that resulted from increases in commodity prices and from the changing mix of our production among taxing jurisdictions.

        General and administrative expenses per Mcfe for this segment were $0.36 in 2004, compared to $0.41 in 2003 and $0.32 in 2002. The decrease in general and administrative costs per Mcfe in 2004 from 2003 was due primarily to the 31% increase in production volumes, partially offset by an 18% increase in general and administrative expenses for this segment.Increased payroll and incentive compensation costs, partially offset by decreased pension expense and an increase in costs capitalized to the full cost pool under full cost accounting rules, accounted for the increase in general and administrative costs.

        We expect our cost per Mcfe for operating and general and administrative expenses to increase in 2005 primarily due to anticipated increases in oil field service costs and an increase in our staffing levels to accommodate our future expected growth. Future changes in our general and administrative expenses for this segment are primarily dependent upon our salary costs, level of pension expense and the amount of incentive compensation paid to our employees. Incentive compensation is based on operating and performance results. See "Critical Accounting Policies" below for further discussion of pension expense.

        Our full cost pool amortization rate averaged $1.20 per Mcfe for 2004, compared to $1.17 in 2003 and $1.16 in 2002. The amortization rate is impacted by reserve additions and the costs incurred for those additions, revisions of previous reserve estimates due to both price and well performance, and the level of unevaluated costs excluded from amortization. Although we expect our amortization rate to continue to increase in the near term as a result of increased costs in finding and developing gas and oil reserves (see discussion on inflation below), we cannot predict our future full cost pool amortization rate with accuracy due to the variability of each of the factors discussed above, as well as the uncertainty of the future success of our Fayetteville Shale play. Unevaluated costs excluded from amortization were $47.2 million at the end of 2004, compared to $39.0 million at the end of 2003 and $25.5 million at the end of 2002. The increase in une valuated costs since December 31, 2002 primarily resulted from an increase in our undeveloped leasehold acreage related to our Fayetteville Shale play.

        We utilize the full cost method of accounting for costs related to our natural gas and oil properties. Under this method, all such costs (productive and nonproductive) are capitalized and amortized on an aggregate basis over the estimated lives of the properties using the units-of-production method. These capitalized costs are subject to a ceiling test, however, which limits such pooled costs to the aggregate of the present value of future net revenues attributable to proved gas and oil reserves discounted at 10 percent (standardized measure) plus the lower of cost or market value of unproved properties. Any costs in excess of this ceiling are written off as a non-cash expense. The expense may not be reversed in future periods, even though higher natural gas and oil prices may subsequently increase the ceiling. Full cost companies must use the prices in effect at the end of each accounting quarter, including the impact of derivatives qualifying as hedges, to calculate the ceiling value of their reserves. At December 31, 2004, 2003 and 2002, our unamortized costs of natural gas and oil properties did not exceed this ceiling amount. At December 31, 2004, our standardized measure was calculated based upon quoted market prices of $6.18 per Mcf for Henry Hub gas and $43.45 per barrel for West Texas Intermediate oil, adjusted for market differentials. A decline in natural gas and oil prices from year-end 2004 levels or other factors, without other mitigating circumstances, could cause a future write-down of capitalized costs and a non-cash charge against future earnings.

        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. This divestiture, along with increased production from the Overton Field, resulted in a

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decrease in our average production costs per unit of production in 2003.

        Inflation impacts our E&P operations by generally increasing our operating costs and the costs of our capital additions. The effects of inflation on our operations prior to 2000 have been minimal due to low inflation rates. However, since 2001, the impact of inflation has intensified in certain areas of our exploration and production segment as shortages in drilling rigs, third-party services and qualified labor developed due to an overall increase in the activity level of the domestic natural gas and oil industry. We feel this impact increased in 2004 and 2003 with increases in the industry activity level caused by higher commodity prices. We have mitigated rising costs in certain situations by obtaining vendor commitments to multiple projects and by offering performance bonuses related to increased efficiencies.

Natural Gas Distribution

	Year Ended December 31,
	2004		2003		2002
	($ in thousands except for per Mcf amounts)
Revenues	$	152,449	$	137,356	$	115,850
Gas purchases	$	97,274	$	84,926	$	66,486
Operating costs and expenses	$	46,659	$	45,664	$	41,801
Operating income	$	8,516	$	6,766	$	$7,563
Deliveries (Bcf)
Sales and end-use transportation		24.0		24.7		25.1
Off-system transportation		1.0		0.3		2.2
Customers at year-end		144,612		141,573		139,543
Average sales rate per Mcf	$	9.39	$	7.93	$	6.49
Heating weather - degree days		3,678		3,969		3,950
Percent of normal		90%		99%		98%

Revenues and Operating Income

        Gas distribution revenues fluctuate due to the effects of warm weather on demand for natural gas and the pass-through of gas supply cost changes. Because of the corresponding changes in purchased gas costs, the revenue effect of the pass-through of gas cost changes has not materially affected operating income.

        Gas distribution revenues increased 11% in 2004 and 19% in 2003. The increase in 2004 gas distribution revenues was primarily due to higher average sales rates as a result of higher gas prices and to the effects of a $4.1 million annual rate increase implemented in October 2003. The increase in 2003 gas distribution revenues was primarily due to a higher average sales rate caused by higher gas prices. Weather during 2004 in the utility's service territory was 10% warmer than normal and 9% warmer than the prior year. Weather during 2003 was 1% warmer than normal and slightly above the prior year.

        Operating income for our utility systems increased 26% in 2004 and decreased 11% in 2003. The increase in 2004 operating income for this segment resulted primarily from rate increases implemented in late 2003 partially offset by increased operating costs and expenses. The decrease in 2003 operating income for this segment resulted from increased operating costs and expenses and reduced usage per customer due to customer conservation brought about by high gas prices. In October 2003, we implemented a rate increase that increased revenue and operating income by $4.1 million annually (see "Regulatory Matters" below for a discussion of the rate increase) and were also allowed to recover certain additional costs totaling $2.3 million over a two-year period. Gas distribution revenues in future years will be impacted by the utility's gas purchase costs, customer growth, usage per customer and rate increases allowed by the Arkansas Public Service Commission, or APSC. In recent years, Arkansas Western has experienced customer growth of approximately 2% annually in its Northwest Arkansas service territory, while it has experienced little or no customer growth in its service territory in Northeast Arkansas. Based on current economic conditions in our service territories, we expect this trend in customer growth to continue. While our utility segment's results have improved since last year, we do not believe that it is earning its authorized rate of return. As a result, and as discussed below in "Regulatory Matters," on December 29, 2004, we filed a rate increase request for $9.7 million with the APSC.

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Deliveries and Rates

        In 2004, Arkansas Western sold 15.5 Bcf to its customers at an average rate of $9.39 per Mcf, compared to 16.3 Bcf at $7.93 per Mcf in 2003 and 16.7 Bcf at $6.49 per Mcf in 2002. Additionally, Arkansas Western transported 8.5 Bcf in 2004 and 8.4 Bcf in 2003 and 2002 for its end-use customers. The decreases in volumes sold in 2004 and 2003 primarily resulted from variations in weather and customer conservation brought about by high gas prices in recent years. Arkansas Western's tariffs contain a weather normalization clause to lessen the impact of revenue increases and decreases which might result from weather variations during the winter heating season. The increase in the utility segment's average sales rate for 2004 reflected changes in the average cost of gas purchased for delivery to our customers, which are passed through to customers under automatic adjustment clauses.

        Total deliveries to industrial customers of the utility segment, including transportation volumes, were 9.8 Bcf in 2004, 9.6 Bcf in 2003 and 9.9 Bcf in 2002. Changes in deliveries to industrial customers were impacted by customer conservation caused by high gas prices partially offset by continued industrial growth in the region. Arkansas Western also transported 1.0 Bcf of gas through its gathering system in 2004 compared to 0.3 Bcf in 2003 and 2.2 Bcf in 2002 for off-system deliveries, all to the Ozark Gas Transmission System. The level of off-system deliveries each year generally reflects the impact of weather changing the on-system demands of our gas distribution systems for our gas production. The average off-system transportation rate was approximately $0.13 per Mcf, exclusive of fuel, in 2004, 2003 and 2002.

        Future volumes delivered to customers will be impacted by customer growth, weather and the effect that gas prices will continue to have on customer conservation.

Operating Costs and Expenses

        The changes in purchased gas costs for the gas distribution segment reflect volumes purchased, prices paid for supplies and the mix of purchases from various gas supply contracts (base load, swing and no-notice). Operating costs and expenses, net of purchased gas costs, increased in 2004 to $46.7 million from $45.7 million in 2003. The increase was primarily due to a $0.6 million increase in transmission expense as a result of higher fuel costs and a $0.3 million increase in depreciation expense as a result of increases in property, plant and equipment. Operating costs and expenses, net of purchased gas costs, for 2003 increased to $45.7 million from $41.8 million in 2002 due primarily to a $2.6 million increase in general and administrative expenses and a $0.8 million increase in transmission expense. The increase in 2003 general and administrative expenses resulted from increased pension, insurance and incentive compensation costs. The incre ase in 2003 transmission expense resulted from higher fuel costs. Future changes in our general and administrative expenses for this segment are primarily dependent upon our salary costs, level of pension expense and the amount of incentive compensation paid to our employees. See "Critical Accounting Policies" below for further discussion of pension expense.

        In October 1998, Arkansas Western instituted a competitive bidding process for its gas supply. Additionally, Arkansas Western annually submits its gas supply plan to the general staff of the APSC. As a result of the bidding process under the plan filed for the 2004-2005 gas purchase year, SEECO successfully bid on gas supply packages representing approximately 55% of the requirements for Arkansas Western for 2005. The contracts awarded to SEECO expire through 2006. Arkansas Western enters into hedging activities from time to time with respect to its gas purchases to protect against the inherent price risks of adverse price fluctuations. Our utility segment hedged 4.5 Bcf of gas purchases in 2004 which had the effect of decreasing its total gas supply costs by $1.1 million. In 2003, our utility hedged 4.6 Bcf of its gas supply which decreased its total gas supply cost by $6.1 million.In 2002 , our utility hedged 4.7 Bcf of its gas supply which increased its total gas supply cost by $5.7 million.At December 31, 2004, Arkansas Western had 2.9 Bcf of future gas purchases hedged at an average purchase price of $6.54 per Mcf. We refer you to "Quantitative and Qualitative Disclosures About Market Risk" and Note 8 to the consolidated financial statements for additional information.

        Inflation impacts our gas distribution segment by generally increasing our operating costs and the costs of our capital additions. The effects of inflation on the utility's operations in recent years have been minimal due to low inflation rates. Additionally, delays inherent in the rate-making process prevent us from obtaining immediate recovery of increased operating costs of our gas distribution segment.

Regulatory Matters

        Arkansas Western's rates and operations are regulated by the APSC. Arkansas Western operates through municipal franchises that are perpetual by virtue of state law, but may not be exclusive within a geographic area. Although its rates for gas delivered to its retail customers are not regulated by the FERC, its transmission and gathering pipeline

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systems are subject to the FERC's regulations concerning open access transportation. As the regulatory focus of the natural gas industry has shifted from the federal level to the state level, some utilities across the nation have unbundled residential sales services from transportation services in an effort to promote greater competition. No such legislation or regulatory directives related to natural gas are presently pending in Arkansas and we have not unbundled our residential sales services.

        In 2003, Arkansas Act 1556 for the deregulation of the retail sale of electricity was repealed. During 2004, the APSC conducted collaborative meetings to study the feasibility of a large-user access program for electric service choice. On September 30, 2004, the APSC issued a report to the legislature finding that it would not be feasible to implement a large-user access program without shifting costs to other customer classes and recommending that no changes be made to the statutes which would affect access to competitive power supply by large users. We do not know what action the legislature may take in response to this report. Although Arkansas Western already provides transportation service for its large users, any developments regarding large-user access programs for electricity could set regulatory precedents that would also affect natural gas utilities in the future. These effects may include protection of other customer classes against cost shifting and the regulatory treatment of stranded costs.

        In 2004, our analysis indicated that current revenues in our utility segment were not sufficient to cover the cost of providing utility service and earn the rate of return authorized by the APSC. Arkansas Western's northwest Arkansas service area includes one of the fastest growing areas of the United States. However, declining consumption per residential customer has offset much of the revenue benefit of strong customer growth. Arkansas Western believes this declining consumption is a trend attributable to rising natural gas prices resulting in energy conservation in existing homes such as reducing thermostat settings, caulking, adding insulation and the replacement of older natural gas equipment with high efficiency equipment. As a result of the decline in consumption coupled with increases in operating cost and capital investments, on December 29, 2004, the gas distribution subsidiary filed a request with the APSC for an adjustment in its ra tes totaling $9.7 million, or 5.2%, annually. The APSC has ten months to review the filing and determine the amount of the increase to be approved, if any. Any rate increase allowed would likely be implemented in the fourth quarter of 2005.

        In September 2003, in response to our request for an $11.0 million rate increase, Arkansas Western received regulatory approval from the APSC of a rate increase totaling $4.1 million annually, exclusive of costs to be recovered through Arkansas Western's purchase gas adjustment clause. The order also entitled Arkansas Western to recover certain additional costs totaling $2.3 million through its purchase gas adjustment clause over a two-year period. The rate increase was effective for all customer bills rendered on or after October 1, 2003.

        In the rate increase request relating to the 2003 increase, we assumed an allowed return on equity of 12.9% and a capital structure of 48% debt and 52% equity. The final order provided for an allowed return on equity of 9.9% and an assumed capital structure of 52% debt and 48% equity. In our 2004 filing, we assumed a rate of return of 11.5% and a capital structure of 50% debt and 50% equity. Rate increase requests, which may be filed in the future, will depend on customer growth, increases in operating expenses, and additional investment in property, plant and equipment.

        In February 2001, the APSC approved a 90-day temporary tariff to collect additional gas costs not yet billed to customers through the utility's normal purchased gas adjustment clause in its approved tariffs. We had significant under-recovered purchased gas costs as a result of the high prices paid for gas supply in the 2000-2001 heating season. The temporary tariff allowed the utility accelerated recovery of these gas costs. 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 and it is still in effect.

        In April 2002, the APSC adopted Natural Gas Procurement Plan Rules for utilities. These rules require utilities to take all reasonable and prudent steps necessary to develop a diversified gas supply portfolio. The portfolio should consist of an appropriate combination of different types of gas purchase contracts and/or financial hedging instruments that are designed to yield an optimum balance of reliability, reduced volatility and reasonable price. Utilities are also required to submit on an annual basis their gas supply plan, along with their contracting and/or hedging objectives, to the staff of the APSC for review and determination as to whether it is consistent with these policy principles. In May 2004, Arkansas Western submitted its annual gas supply plan for the 2004-2005 heating season to the staff of the APSC.

        Arkansas Western also purchases gas from unaffiliated producers under take-or-pay contracts. We believe that we do not have significant exposure to liabilities resulting from these contracts and expect to be able to continue to satisfactorily manage our exposure to take-or-pay liabilities.

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Marketing

	Year Ended December 31,
	2004		2003		2002
Revenues (in millions)	$	315.0	$	202.0	$	131.1
Operating income (in millions)	$	3.2	$	2.6	$	2.7
Gas volumes marketed (Bcf)		57.0		42.7		45.5

        Our operating income from natural gas marketing was $3.2 million on revenues of $315.0 million in 2004, compared to $2.6 million on revenues of $202.0 million in 2003 and $2.7 million on revenues of $131.1 million in 2002. The increase in revenues in 2004 resulted from increased volumes marketed and higher prices received for gas sold. The increase in revenues from higher prices was largely offset by a corresponding increase in gas purchase expense. We marketed 57.0 Bcf in 2004, compared to 42.7 Bcf in 2003 and 45.5 Bcf in 2002. The increase in volumes marketed in 2004 resulted from marketing our increased production volumes, largely related to our Overton Field in East Texas. The decline in total volumes marketed between 2003 and 2002 resulted primarily from a shift in our focus to marketing our own production in order to reduce our credit risk. Of the total volumes marketed, production from our exploration and production subsidiaries accounted f or 77% in 2004, 75% in 2003 and 67% in 2002. We enter into hedging activities from time to time with respect to our gas marketing activities to provide margin protection. We refer you to "Quantitative and Qualitative Disclosures About Market Risk" and Note 8 to the financial statements for additional discussion.

Transportation

        Our marketing group also manages our 25% interest in the Ozark Gas Transmission System. Additionally, our gas distribution subsidiary has a transportation contract with Ozark Gas Transmission System for 66.9 MMcf per day of firm capacity that expires in 2014. We recorded a pre-tax loss from operations related to our investment of $0.4 million in 2004, compared to pre-tax income of $1.1 million in 2003 and a pre-tax loss of $0.3 million in 2002. These amounts are recorded in other income (expense) in our income statement. The pre-tax loss in 2004 was primarily due to a $0.4 million negative adjustment from the operator of the pipeline for prior period allocations of income and expenses to the partners. The pre-tax gain in 2003 included a gain of $1.3 million recognized on the sale of a 28-mile portion of Ozark Gas Transmission System's pipeline located in Oklahoma that had limited strategic value to the overall system. We refer you to Note 7 to the financial statements for additional discussion.

        We have severally guaranteed the partnership's outstanding debt which was $67.0 million at December 31, 2004. Our share of the guarantee equaled $40.2 million. This debt financed a portion of the original construction costs. We advanced $2.1 million to NOARK in 2004 as an adjustment to prior period cash disbursements. No advances to NOARK were required in 2003 and 2002. We refer you to "Management's Discussion and Analysis of Financial Condition and Results of Operations-Liquidity and Capital Resources-Off-Balance Sheet Arrangements" and Note 11 to the consolidated financial statements for further discussion of our guarantee of NOARK debt.

Other Revenues

        In 2004 and 2003, other revenues included gains of $5.8 million and $3.0 million, respectively, related to sales of undeveloped real estate and certain property and equipment. Other revenues 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.

Interest Expense

        Interest costs, net of capitalization, were down 2% in 2004 and down 19% in 2003, both as compared to prior years. In 2004, higher interest costs that resulted from increased average borrowings were offset by an increase in capitalized interest in the E&P segment. The decrease in 2003 interest costs compared to 2002 was due to both comparatively lower average borrowings and lower average interest rates. In 2003, our average borrowings decreased as net proceeds of $103.1 million from the sale of our common stock in the first quarter of 2003 were initially used to pay down our revolving credit facility. Interest capitalized increased 56% in 2004 and increased 21% in 2003. Changes in capitalized interest are primarily due to the level of costs excluded from amortization in our E&P segment. These costs increased in 2004 and 2003 due primarily to initial leasehold investments in our Fayetteville Shale play and increased drilling activity.

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Income Taxes

        Our provision for deferred income taxes was an effective rate of 36.6% in 2004, 36.7% in 2003 and 37.8% in 2002. The changes in the provision for deferred income taxes recorded each year result primarily from the level of taxable income, adjusted for permanent differences.

Pension Expense

        We recorded pension expense of $2.2 million in 2004, $3.3 million in 2003 and $0.9 million in 2002. The amount of pension expense recorded by us is determined by actuarial calculations and is also impacted by the funded status of our plans. During 2004, we funded our pension plan with contributions of $1.9 million. At December 31, 2004, our pension plans were underfunded and a liability of $1.5 million was recorded on the balance sheet. As a result of the underfunded status and actuarial data to be completed in early 2005, we expect to record pension expense of $2.0 million to $2.5 million in 2005. For further discussion of our pension plans, we refer you to Note 4 to the financial statements and "Critical Accounting Policies" below.

Adoption of Accounting Principles

        In September 2004, the staff of the SEC issued Staff Accounting Bulletin No. 106 (SAB 106) to express the staff's views regarding application of FAS 143, "Accounting for Asset Retirement Obligations," by oil and gas producing companies following the full cost accounting method. SAB 106 addressed the computation of the full cost ceiling test to avoid double-counting asset retirement costs, the disclosures a full cost accounting company is expected to make regarding the impacts of FAS 143, and the amortization of estimated dismantlement and abandonment costs that are expected to result from future development activities. The accounting and disclosures described in SAB 106 have been adopted by the Company as of the third quarter of 2004 and did not have a material impact on the financial position of the Company, or on its results of operations.

        Statement of Financial Accounting Standards No. 143, "Accounting for Asset Retirement Obligations" (FAS 143), was adopted by the Company on January 1, 2003. FAS 143 addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. FAS 143 requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made, and that the associated asset retirement costs be capitalized as part of the carrying amount of the long-lived asset. The effect of this standard on our results of operations and financial condition at adoption was an increase in current and long-term liabilities of $1.2 million and $5.5 million, respectively; a net increase in property, plant and equipment of $5.3 million; a cumulative effect of adoption expense of $0.9 million and a d eferred tax asset of $0.5 million. As of December 31, 2004, we had $0.5 million of current liabilities and $8.1 million of long-term liabilities associated with our asset retirement obligations.

        See Note 14 to the consolidated financial statements for the impact of newly issued accounting pronouncements.

LIQUIDITY AND CAPITAL RESOURCES

        We depend on internally-generated funds and our unsecured revolving credit facility (discussed below under "Financing Requirements") as our primary sources of liquidity. We may borrow up to $500 million under our new revolving credit facility from time to time. As of March 3, 2005, we had approximately $80 million of indebtedness outstanding under our revolving credit facility. During 2005 we expect to draw on a portion of the funds available under our credit facility to fund our planned capital expenditures (discussed below under "Capital Expenditures"), which are expected to exceed the net cash generated by our operations.

        Net cash provided by operating activities was $237.9 million in 2004, compared to $109.1 million in 2003 and $77.6 million in 2002. The primary components of cash generated from operations are net income, depreciation, depletion and amortization, the provision for deferred income taxes and changes in operating assets and liabilities. Cash from operating activities increased in 2004 and 2003 due primarily to increased net income and the related increases in deferred income taxes generated by our E&P segment. Net cash from operating activities provided 81% of our cash requirements for capital expenditures in 2004, 65% in 2003 and over 84% in 2002.

        We believe that our operating cash flow and our credit facility will be adequate to meet our capital, debt repayment and operating requirements for 2005. We fund our day-to-day operating expenses and capital expenditures from operating cash flows, supplemented as needed by borrowings under our credit facility. We may choose to refinance certain portions of these borrowings by issuing long-term debt in the public or private debt markets. We may utilize our existing

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shelf registration statement or we may file a new shelf registration statement with the SEC in order to facilitate such financings.

Capital Expenditures

        Capital expenditures totaled $295.0 million in 2004, $180.2 million in 2003 and $92.1 million in 2002. Capital expenditures for our E&P segment included $3.9 million in 2004, $12.0 million in 2003 and a negative $0.3 million in 2002 related to the change in the amount of accrued expenditures. Additionally, our E&P segment expenditures included acquisitions of interests in natural gas and oil producing properties totaling $14.2 million in 2004, $3.0 million in 2003 and $3.5 million in 2002.

	2004		2003		2002
	(in thousands)
Exploration and production	$	281,988	$	170,886	$	85,201
Gas distribution		7,298		8,178		6,115
Other		5,704		1,139		746
	$	294,990	$	180,203	$	92,062

        Our capital investments for 2005 are planned to be up to $352.7 million, consisting of up to $339.0 million for exploration and production, $10.4 million for gas distribution system improvements and $3.3 million for general purposes. Based on the results achieved to date and assuming that the 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 Fayetteville Shale play. We expect that our planned level of capital investments in 2005 will allow us to continue the development of our Overton Field properties in East Texas, continue our conventional drilling in the Arkoma Basin, maintain our present markets, explore and develop other existing gas and oil properties, generate new drilling prospects, and provide for improvements necessary due to normal customer growth in our gas distribution segment. As discussed above, our 2005 capital investment program is expected to be funded through cash flow from operations and our revolving credit facility. We may adjust the level of 2005 capital investments dependent upon our level of cash flow generated from operations and our ability to borrow under our credit facility.

Financing Requirements

        Our total debt outstanding was $325.0 million at December 31, 2004 and $278.8 million at December 31, 2003. The balance at December 31, 2004 includes $125.0 million of notes which are due December 2005. Our intent is to repay the notes using borrowings under our revolving credit facility, however we may seek to re-finance these notes by issuing long-term debt in the public or private markets. In January 2005, we amended and restated our previous $300 million revolving credit facility due to expire in January 2007, increasing the borrowing capacity to $500 million and extending the expiration to January 2010. The amended and restated revolving credit facility replaced the $300 million credit facility and another smaller credit facility. At December 31, 2004, we had $100.0 million of outstanding debt under our prior revolving credit facility. The interest rate on the new facility is calculated based upon our public debt rating and is currently 1 25 basis points over LIBOR. Our publicly traded notes were downgraded in January 2005 by Standard and Poor's to BBB- from BBB, and continue to be rated Ba2 by Moody's. Any future downgrades in our public debt ratings could increase the cost of funds under our revolving credit facility.

        Our revolving credit facility contains covenants which impose certain restrictions on us. Under the credit agreements, we may not issue total debt in excess of 60% of our total capital, must maintain a certain level of shareholders' equity, and must maintain a ratio of EBITDA to interest expense of 3.5 or above. Additionally, there are certain limitations on the amount of indebtedness that may be incurred by our subsidiaries. We were in compliance with the covenants of our credit agreements at December 31, 2004. Although we do not anticipate debt covenant violations, our ability to comply with our credit agreement is dependent upon the success of our exploration and development program and upon factors beyond our control, such as the market prices for natural gas and oil. If we are unable to borrow under our credit facility, we would have to decrease our capital expenditure plans.

        In 1997, we publicly issued $60.0 million of 7.625% Medium-Term Notes due 2027 and $40.0 million of 7.21% Medium-Term Notes due 2017. In 1995, we publicly issued $125.0 million of 6.7% Notes due in December 2005. In December 2002, we filed a shelf registration statement with the SEC for the purpose of qualifying the potential sale from time to time of up to an aggregate $300 million of equity, debt and other securities. During the first quarter of 2003, we completed the sale of 9,487,500 shares of our common stock under the shelf registration statement. Aggregate net proceeds from the equity offering of $103.1 million were used to repay borrowings under our credit facility.

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        In June 1998, the NOARK partnership issued $80.0 million of 7.15% Notes due 2018. The notes require semi-annual principal payments of $1.0 million that began in December 1998. We account for our investment in NOARK under the equity method of accounting and do not consolidate the results of NOARK. We and Enogex, the other general partner of NOARK, have severally guaranteed the principal and interest payments on the NOARK debt. Our share of the several guarantee is 60% and amounted to $40.2 million at December 31, 2004. We advanced $2.1 million to NOARK in 2004 as an adjustment to prior period cash disbursements and were not required to advance any funds in 2003 or 2002. If NOARK is unable to generate sufficient cash in the future on a sustainable basis to service its debt and we are continually required to contribute cash to fund our share of the debt service guarantee, we could be required to record our share of the NOARK debt commitment under cur rent accounting rules.

        At the end of 2004, our capital structure consisted of 42% debt (excluding our several guarantee of NOARK's obligations) and 58% equity, with a ratio of EBITDA to interest expense of 15.1. EBITDA is a measure required by our debt covenants and is defined as net income plus interest expense, income tax expense, and depreciation, depletion and amortization. Shareholders' equity in the December 31, 2004 balance sheet includes an accumulated other comprehensive loss of $18.8 million related to our hedging activities that is required to be recorded under the provisions of Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities" (FAS 133). This amount is based on current market values of our hedges at December 31, 2004, and does not necessarily reflect the value that we will receive or pay when the hedges ultimately are settled, nor does it take into account revenues to be received associated wi th the physical delivery of sales volumes hedged. Our debt covenants as to capitalization percentages exclude the effects of non-cash entries that result from FAS 133 as well as the non-cash impact of any full cost ceiling write-downs, and include the guarantee of NOARK's obligations. Our capital structure, including our several guarantee of NOARK's obligations of $40.2 million, would be 44% debt and 56% equity at December 31, 2004, without consideration of the accumulated other comprehensive loss related to FAS 133 of $18.8 million. As part of our strategy to insure a certain level of cash flow to fund our operations, we have hedged approximately 70% to 80% of our expected 2005 gas production and 60% to 70% of our expected 2005 oil production. The amount of long-term debt we incur will be dependent upon commodity prices and our capital expenditure plans. If commodity prices remain at or near current levels throughout 2005 and our capital expenditure plans do not change from current expectations, we will increase our long-term debt in 2005. If commodity prices significantly decrease, we may decrease and/or reallocate our planned capital expenditures significantly.

        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.

Off-Balance Sheet Arrangements

        As discussed above in "Results of Operations-Transportation," we hold a 25% general partnership interest in NOARK, which owns the Ozark Gas Transmission System that is utilized to transport our gas production and the gas production of others. We account for our investment under the equity method of accounting. We and the other general partner of NOARK have severally guaranteed the principal and interest payments on NOARK's 7.15% Notes due 2018, issued to finance a portion of the original construction costs. Our share of the guarantee is 60% and we are allocated 60% of the interest expense. At December 31, 2004 and 2003, the outstanding principal amount of these notes was $67.0 million and $69.0 million, respectively. Our share of the guarantee was $40.2 million and $41.4 million, respectively. The notes were issued in June 1998 and require semi-annual principal payments of $1.0 million. Under the several guarantee, we are required to fund our share of NOARK's debt service which is not funded by operations of the pipeline. We advanced $2.1 million to NOARK in 2004 as an adjustment to prior period cash disbursements and were not required to advance any funds in 2003 or 2002. We do not derive any liquidity, capital resources, market risk support or credit risk support from our investment in NOARK.

        Our share of the results of operations included in other income (expense) related to our NOARK investment was a pre-tax loss of $0.4 million in 2004, pre-tax income of $1.1 million in 2003 and a pre-tax loss of $0.3 million in 2002. The pre-tax loss in 2004 was primarily due to a $0.4 million negative adjustment from the operator of the pipeline for prior period allocations of income and expenses to the partners. In 2003, our share of pre-tax income included a gain of $1.3 million related to the sale of a 28-mile portion of the pipeline located in Oklahoma. We believe that we will be able to continue to improve the operating results of the NOARK project and expect our investment in NOARK to be realized over the life of the system (see Note 7 of the financial statements for additional discussion).

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        NOARK's assets and liabilities as of December 31, 2004 and 2003 are as follows:

	2004		2003
	(in thousands)
Current assets	$	11,375	$	20,642
Noncurrent assets		158,149		161,994
	$	169,524	$	182,636
Current liabilities	$	9,610	$	7,537
Long-term debt		65,000		67,000
Partners' capital		94,914		108,099
	$	169,524	$	182,636

        NOARK's results of operations for 2004, 2003 and 2002 are summarized below:

	2004		2003		2002
	(in thousands)
Operating revenues	$	77,347	$	72,038	$	75,959
Pre-tax income	$	8,756	$	9,030	$	3,011

Contractual Obligations and Contingent Liabilities and Commitments

        We have various contractual obligations in the normal course of our operations and financing activities. Significant contractual obligations at December 31, 2004 were as follows:

Contractual Obligations:

	Payments Due by Period
	Total		Less than 1 Year		1 to 3 Years		3 to 5 Years		More than 5 Years
	(in thousands)
Long-term debt	$	325,000	$	125,000	$	--	$	60,000	$	140,000
Operating leases(1)		10,204		1,691		3,056		2,980		2,477
Unconditional purchase obligations(2)		--		--		--		--		--
Demand charges(3)		103,163		11,613		19,468		20,025		52,057
Other obligations(4)		6,305		6,179		101		25		--
	$	444,672	$	144,483	$	22,625	$	83,030	$	194,534

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

(2) Our utility segment has volumetric commitments for the purchase of gas under non-cancelable competitive bid packages and non-cancelable wellhead contracts. Volumetric purchase commitments at December 31, 2004 totaled 1.7 Bcf, comprised of 1.4 Bcf in less than one year, 0.2 Bcf in one to three years and 0.1 Bcf in three to five years. Our volumetric purchase commitments are priced primarily at regional gas indices set at the first of each future month. These costs are recoverable from the utility's end-use customers.

(3) Our utility segment has commitments for approximately $97.5 million of demand charges on non-cancelable firm gas purchase and firm transportation agreements. These costs are recoverable from the utility's end-use customers. Our E&P segment has a commitment for approximately $5.7 million of demand transportation charges.

(4) Our other significant contractual obligations include approximately $2.4 million for funding of benefit plans, approximately $0.4 million of land leases, approximately $2.1 million for drilling rig commitments and approximately $1.0 million of various information technology support and data subscription agreements.

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

Contingent Liabilities and Commitments

    We have the following commitments and contingencies that could create, increase or accelerate our liabilities. Substantially all of our employees are covered by defined benefit and postretirement benefit plans. Our return on the assets of these plans in 2002 was negative which, when combined with other factors, resulted in an increase in pension expense and our required funding of the plans for 2004 and 2003. At December 31, 2004, we recorded an accrued pension benefit liability of $1.5 million. As a result of the underfunded status and actuarial data to be completed in early 2005, we expect to record pension expense of $2.0 million to $2.5 million in 2005. See Note 4 to the financial statements and "Critical Accounting Policies" below for additional information.

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        As discussed above in "Off-Balance Sheet Arrangements," we have guaranteed 60% of the principal and interest payments on NOARK's 7.15% Notes due 2018. At December 31, 2004, the outstanding principal of these notes was $67.0 million. The notes require semi-annual principal payments of $1.0 million. See Note 11 to the financial statements for additional information.

Working Capital

        We maintain access to funds that may be needed to meet capital requirements through our credit facility described above. We had negative working capital of $2.7 million at the end of 2004 and positive working capital of $5.2 million at the end of 2003. Current assets increased by 31% in 2004 and current liabilities increased 41%. The change in working capital from 2003 to 2004 primarily relates to the increase in our current hedging liability at December 31, 2004.

CRITICAL ACCOUNTING POLICIES

Natural Gas and Oil Properties

        We utilize the full cost method of accounting for costs related to our natural gas and oil properties. Under the full cost accounting rules of the SEC, all such costs (productive and nonproductive) are capitalized and amortized on an aggregate basis over the estimated lives of the properties using the units-of-production method. Unevaluated costs are reviewed twice a year for individual impairment. Capitalized costs within the full cost pool are subjected quarterly to a ceiling test, which limits such pooled costs to the aggregate of the present value of future net revenues attributable to proved gas and oil reserves discounted at 10 percent plus the lower of cost or market value of unproved properties. If the net capitalized costs of natural gas and oil properties exceed the ceiling, we will record a ceiling test write-down to the extent of such excess. A ceiling test write-down is a non-cash charge to earnings. If required, it reduces earnin gs and impacts shareholders' equity in the period of occurrence and results in lower depreciation, depletion and amortization expense in future periods. The write-down may not be reversed in future periods, even though higher natural gas and oil prices may subsequently increase the ceiling.

        The risk that we will be required to write-down the carrying value of our natural gas and oil properties increases when natural gas and oil prices are depressed or if there are substantial downward revisions in estimated proved reserves. Under the SEC's full cost accounting rules, our reserves are required to be priced using prices in effect at the end of the reporting period. Application of these rules during periods of relatively low natural gas or oil prices due to seasonality or other reasons, even if temporary, increases the probability of a ceiling test write-down. Based on natural gas and oil prices in effect on December 31, 2004, the unamortized cost of our natural gas and oil properties did not exceed the ceiling of proved natural gas and oil reserves. Natural gas pricing has historically been unpredictable and any significant declines could result in a ceiling test write-down in subsequent quarterly or annual reporting periods.

        Natural gas and oil reserves used in the full cost method of accounting cannot be measured exactly. Our estimate of natural gas and oil reserves requires extensive judgments of reservoir engineering data and is generally less precise than other estimates made in connection with financial disclosures. Our reservoir engineers prepare our reserve estimates under the supervision of our management. Reserve estimates are prepared for each of our properties annually by the reservoir engineers assigned to the asset management team in the geographic locations in which the property is located. These estimates are reviewed by senior engineers who are not part of the asset management teams and the executive vice president of our E&P subsidiaries. Finally, the estimates of our proved reserves together with the audit report of Netherland Sewell & Associates, Inc. (discussed below) are reviewed by our Audit Committee. In each of the past three years, revisions to our proved reserve estimates represented no greater than 3% of our total proved reserve estimates, which we believe is indicative of the effectiveness of our internal controls. Proved developed reserves generally have a higher degree of accuracy in this estimation process, when compared to proved undeveloped and proved non-producing reserves, as production history and pressure data over time is available for the majority of our proved developed properties. Proved developed reserves account for 83% of our total reserve base. Assigning monetary values to such estimates does not reduce the subjectivity and changing nature of such reserve estimates. The uncertainties inherent in the reserve estimates are compounded by applying additional estimates of the rates and timing of production and the costs that will be incurred in developing and producing the reserves. We cannot assure you that our internal controls sufficiently address the numerous uncertainties and risks that are inherent in estimating quantities of natural gas and oil reserves and projecting future rates of production and timing of development expenditures as many factors are beyond our control. We refer you to "The natural gas and oil reserves data we report are only estimates and may prove to be inaccurate." under the heading "Risk Factors" in Item 1 of Part I of this Form 10-K for a more detailed discussion of these uncertainties, risks and other factors.

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        We engage the services of Netherland Sewell & Associates, Inc., an independent petroleum engineering firm, to audit our reserves as estimated by our reservoir engineers. Netherland, Sewell & Associates, Inc. reports the results of the reserves audit to the Audit Committee of our Board of Directors. In conducting its audit, the engineers and geologists of Netherland, Sewell & Associates study the Company's major properties in detail and independently develop reserve estimates. Minor properties (typically representing less then 20% of the total) are also audited, but less rigorously. For the year-ended December 31, 2004, Netherland, Sewell & Associates issued its audit opinion as to the reasonableness of our reserve estimates, stating that our estimated proved oil and gas reserves are, in the aggregate, reasonable and have been prepared in accordance with generally accepted petroleum engineering and evaluation principles.

        A decline in gas and oil prices used to calculate the discounted future net revenues of our reserves affects both the present value of cash flows and the quantity of reserves reported. Our reserve base is 92% natural gas, therefore changes in oil prices used do not have as significant an impact as gas prices on cash flows and reported reserve quantities. Reported discounted cash flows and reserve quantities at December 31, 2004 were $892 million and 645.5 Bcfe. An assumed decrease of $1.00 per Mcf in the December 31, 2004 gas price used to price our reserves would have resulted in an approximate $150 million to $175 million decline in our future cash flows discounted at 10% and an approximate decrease of 10 Bcfe of our reported reserves. Under this assumption, our unamortized costs remained below the ceiling of proved natural gas and oil reserves. The decline in reserve quantities, assuming this decrease in gas price, would have the impact of incr easing our unit of production amortization of the full cost pool. The unit of production rate for amortization is adjusted quarterly based on changes in reserve estimates.

Hedging

        We use natural gas and crude oil swap agreements and options and interest rate swaps to reduce the volatility of earnings and cash flow due to fluctuations in the prices of natural gas and oil and in interest rates. Our policies prohibit speculation with derivatives and limit swap agreements to counterparties with appropriate credit standings to minimize the risk of uncollectability. In recent years, we have hedged 70% to 80% of our annual production. The primary market risks related to our derivative contracts are the volatility in market prices and basis differentials for natural gas and crude oil. However, the market price risk is offset by the gain or loss recognized upon the related sale or purchase of the natural gas or sale of the oil that is hedged.

        Our derivative instruments are accounted for under FAS 133 and are recorded at fair value in our financial statements. We have established the fair value of derivative instruments using estimates determined by our counterparties, with such estimates evaluated internally using established index prices and other sources. These valuations are recognized as assets or liabilities in our balance sheet and, to the extent an open position is an effective cash flow hedge on equity production or interest rates, the offset is recorded in other comprehensive income. Results of settled commodity hedging transactions are reflected in natural gas and oil sales or in gas purchases. Results of settled interest rate hedges are reflected in interest expense. Any ineffective hedge, derivative not qualifying for accounting treatment as a hedge, or ineffective portion of a hedge is recognized immediately in earnings. We recorded a loss in revenues of $2.6 million in 20 04, a gain of $0.6 million in 2003 and a loss of $1.1 million in 2002 related to the changes in ineffectiveness of our commodity hedges. Future market price volatility could create significant changes to the hedge positions recorded in our financial statements. We refer you to "Quantitative and Qualitative Disclosures about Market Risk" in this Form 10-K for additional information regarding our hedging activities.

Regulated Utility Operations

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

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

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Pension and Other Postretirement Benefits

        We record our prepaid or accrued benefit cost, as well as our periodic benefit cost, for our pension and other postretirement benefit plans using measurement assumptions that we consider reasonable at the time of calculation (see Note 4 to the financial statements for further discussion and disclosures regarding these benefit plans). Two of the assumptions that affect the amounts recorded are the discount rate, which estimates the rate at which benefits could be effectively settled, and the expected return on plan assets, which reflects the average rate of earnings expected on the funds invested. For the December 31, 2004 benefit obligation and the periodic benefit cost to be recorded in 2005, the discount rate assumed is 6.0% and the expected return assumed is 9.0%. This compares to a discount rate of 6.25% and an expected return of 9.0% used in the prior year.

        Using the assumed rates discussed above, we recorded pension expense of $2.2 million in 2004 and $3.3 million in 2003. We reflected a pension liability of $1.5 million at December 31, 2004 and $0.9 million at December 31, 2003. During 2004, we also funded $1.9 million to our pension plans. In 2005, we expect to fund $2.0 million to our pension plans. Assuming a 1% change in the 2004 rates (lower discount rate and lower rate of return), we would have recorded pension expense of $3.3 million in 2004.

Gas in Underground Storage

        We record our gas stored in inventory that is owned by the E&P segment at the lower of weighted average cost or market. Gas expected to be cycled within the next 12 months is recorded in current assets with the remaining stored gas reflected as a long-term asset. The quantity and average cost of gas in storage was 9.3 Bcf at $3.49 per Mcf at December 31, 2004, compared to 10.4 Bcf at $3.33 per Mcf at December 31, 2003.

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

        See further discussion of our significant accounting policies in Note 1 to the financial statements.

FORWARD-LOOKING INFORMATION

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

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

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

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

  47

• the timing and extent of our success in discovering, developing, producing and estimating reserves;
   
• the extent to which the Fayetteville Shale play can replicate the results of other productive shale gas plays;
   
• the potential for significant variability in reservoir characteristics of the Fayetteville Shale over such a large acreage position;
   
• our ability to fund our planned capital expenditures;
   
• our future property acquisition or divestiture activities;
   
• the effects of weather and regulation on our gas distribution segment;
   
• increased competition;
   
• the impact of federal, state and local government regulation;
   
• the financial impact of accounting regulations and critical accounting policies;
   
• changing market conditions and prices (including regional basis differentials);
   
• the comparative cost of alternative fuels;
   
• conditions in capital markets and changes in interest rates;
   
• the availability of oil field personnel, services, drilling rigs and other equipment; and
   
• any other factors listed in the reports we have filed and may file with the SEC.

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

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

        Should one or more of the risks or uncertainties described above or elsewhere in this Form 10-K occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements. We specifically disclaim all responsibility to publicly update any information contained in a forward-looking statement or any forward-looking statement in its entirety and therefore disclaim any resulting liability for potentially related damages.

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

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

Credit Risks

        Our financial instruments that are exposed to concentrations of credit risk consist primarily of trade receivables and derivative contracts associated with commodities trading. Concentrations of credit risk with respect to receivables are limited due to the large number of customers and their dispersion across geographic areas. No single customer accounts for greater than 3% of accounts receivable at December 31, 2004. In addition, please see the discussion of credit risk associated with commodities trading below.

Interest Rate Risk

        The following table provides information on our financial instruments that are sensitive to changes in interest rates. The table presents our debt obligations, principal cash flows and related weighted-average interest rates by expected maturity dates. Variable average interest rates reflect the rates in effect at December 31, 2004 for borrowings under our credit facility. Our policy is to manage interest rates through use of a combination of fixed and floating rate debt. Interest rate swaps may be used to adjust interest rate exposures when appropriate.

	Expected Maturity Date							Fair Value
	2005	2006	2007	2008	2009	Thereafter	Total	12/31/04
	($ in millions)
Fixed Rate	$ 125.0	$ --	$ --	$ --	$  60.0	$ 40.0	$ 225.0	$ 235.4
Average Interest Rate	6.70%	--	--	--	7.63%	7.21%	7.04%	--
Variable Rate	$ --	$ --	$ --	$ --	$ --	$ 100.0	$ 100.0	$ 100.0
Average Interest Rate	--	--	--	--	--	3.66%	3.66%	--

Commodities Risk

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

        The primary market risks relating to our derivative contracts are the volatility in market prices and basis differentials for natural gas and crude oil. However, the market price risk is offset by the gain or loss recognized upon the related sale or purchase of the natural gas or sale of the oil that is hedged. Credit risk relates to the risk of loss as a result of non-performance by our counterparties. The counterparties are primarily major investment and commercial banks which management believes present minimal credit risks. The credit quality of each counterparty and the level of financial exposure we have to each counterparty are periodically reviewed to ensure limited credit risk exposure.

        The following table provides information about our financial instruments that are sensitive to changes in commodity prices and that are used to hedge prices for gas and oil production, gas purchases and marketing volumes. The table presents the notional amount in Bcf and MBbls, the weighted average contract prices and the fair value by expected maturity dates. At December 31, 2004, the fair value of these financial instruments was a $34.5 million liability.

49

	Expected Maturity  Date
	2005	2006
Production and Marketing
Natural Gas
Swaps with a fixed-price receipt
Contract volume (Bcf)	12.9	5.0
Weighted average price per Mcf	$ 5.11	$ 5.89
Fair value (in millions)	$ (15.0)	$ (1.6)
Price collars
Contract volume (Bcf)	33.4	22.0
Weighted average floor price per Mcf	$ 4.68	$ 4.64
Fair value of floor (in millions)	$ 3.5	$ 5.0
Weighted average ceiling price per Mcf	$ 8.30	$ 8.69
Fair value of ceiling (in millions)	$ (12.3)	$ (8.8)
Swaps with a fixed-price payment
Contract volume (Bcf)	0.2	--
Weighted average price per Mcf	$ 6.07	$  --
Fair value (in millions)	$  --	$  --
Oil
Swaps with a fixed-price receipt
Contract volume (MBbls)	360	120
Weighted average price per Bbl	$ 33.17	$ 37.30
Fair value (in millions)	$ (3.4)	$ (0.4)
Natural Gas Purchases
Swaps with a fixed-price payment
Contract volume (Bcf)	2.9	--
Weighted average price per Mcf	$ 6.54	$  --
Fair value (in millions)	$ (1.4)	$  --

        At December 31, 2004, the Company had outstanding fixed-price basis differential swaps on 4.1 Bcf of 2005 gas production that did not qualify for hedge accounting treatment. The fair value of these differential swaps was a liability of $0.1 million at December 31, 2004.

        At December 31, 2003, the Company had outstanding natural gas price swaps on total notional volumes of 8.0 Bcf at a weighted average price of $4.21 per Mcf in 2004 and 6.0 Bcf at a weighted average price of $4.67 per Mcf in 2005. Outstanding oil price swaps on 426 MBbls were in place that yielded the Company an average price of $28.39 per barrel during 2004. At December 31, 2003, the Company also had outstanding natural gas price swaps on total notional gas purchase volumes of 3.8 Bcf in 2004 for which the Company paid an average fixed price of $5.34 per Mcf.

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

        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.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

	Page
Management's Report on Internal Control Over Financial Reporting	52
Report of Independent Registered Public Accounting Firm	52
Statements of Operations for the years ended December 31, 2004, 2003 and 2002	54
Balance Sheets as of December 31, 2004 and 2003	55
Statements of Cash Flows for the years ended December 31, 2004, 2003 and 2002	56
Statements of Changes in Shareholders' Equity and Comprehensive Income (Loss) for the years ended December 31, 2004, 2003 and 2002	57
Notes to Consolidated Financial Statements, December 31, 2004, 2003 and 2002	59

51

Management's Report on Internal Control Over Financial Reporting

        Our management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rule 13a-15(f) under the Exchange Act.  We have performed an evaluation under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of our internal control over financial reporting. Our management assessed the effectiveness of our internal control over financial reporting as of December 31, 2004. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies and procedures may deteriorate.

        Our management used the criteria set forth in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) to perform its assessment. Based on this assessment, our management, including our Chief Executive Officer and our Chief Financial Officer, concluded, that as of December 31, 2004, our internal control over financial reporting was effective based on those criteria.  

        Our management's assessment of the effectiveness of our internal control over financial reporting as of December 31, 2004 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report below.

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Shareholders of

Southwestern Energy Company:

        We have completed an integrated audit of Southwestern Energy Company's 2004 consolidated financial statements and of its internal control over financial reporting as of December 31, 2004 and audits of its 2003 and 2002consolidated financial statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Our opinions, based on our audits, are presented below.

Consolidated Financial Statements

        In our opinion, the consolidated financial statements listed in the accompanying index present fairly, in all material respects, the financial position of Southwestern Energy Company and its subsidiaries atDecember 31, 2004 and 2003, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2004 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit of financial statements includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

        As discussed in Note 1 to the consolidated financial statements, effective January 1, 2003, the Company adopted the requirements of Statement of Financial Accounting Standards No. 143, "Accounting for Asset Retirement Obligations."

Internal Control over Financial Reporting

        Also, in our opinion, management's assessment, included in the accompanying "Management's Report on Internal Control Over Financial Reporting," that the Company maintained effective internal control over financial reporting as of December 31, 2004based on criteria established in Internal Control --Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), is fairly stated, in all material respects, based on those criteria. Furthermore, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control --Integrated Framework issued by the COSO. The Company's management is responsible for maintaining effective internal control over

52

financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express opinions on management's assessment and on the effectiveness of the Company's internal control over financial reporting based on our audit. We conducted our audit of internal control over financial reporting in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. An audit of internal control over financial reporting includes obtaining an understanding of internal control over financial reporting, evaluating management's assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we consider necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.

        A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or tim ely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

        Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

PricewaterhouseCoopers LLP

Tulsa, Oklahoma

March 4, 2005

53

STATEMENTS OF OPERATIONS

Southwestern Energy Company and Subsidiaries

	For the years ended December 31,
	2004		2003		2002
	(in thousands, except share/per share amounts)
Operating revenues:
Gas sales	$	375,460	$	256,467	$	198,108
Gas marketing		65,127		43,313		41,709
Oil sales		19,461		14,180		14,340
Gas transportation and other		17,089		13,441		7,345
		477,137		327,401		261,502
Operating costs and expenses:
Gas purchases - utility		64,311		52,585		48,388
Gas purchases - marketing		60,804		39,428		37,927
Operating expenses		42,157		37,377		38,154
General and administrative expenses		36,074		33,102		26,446
Depreciation, depletion and amortization		73,674		55,948		53,992
Taxes, other than income taxes		17,830		11,619		10,090
		294,850		230,059		214,997
Operating income		182,287		97,342		46,505
Interest expense:
Interest on long-term debt		18,335		17,722		21,664
Other interest charges		1,461		1,381		1,285
Interest capitalized		(2,804)		(1,792)		(1,483)
		16,992		17,311		21,466
Other income (expense)		(362)		797		(566)
Income before income taxes, minority interest and accounting change		164,933		80,828		24,473
Minority interest in partnership		(1,579)		(2,180)		(1,454)
Income before income taxes and accounting change		163,354		78,648		23,019
Provision for income taxes
Current		--		--		--
Deferred		59,778		28,896		8,708
		59,778		28,896		8,708
Income before accounting change		103,576		49,752		14,311
Cumulative effect of adoption of accounting principle		--		(855)		--
Net Income	$	103,576	$	48,897	$	14,311
Basic Earnings per share:
Income before accounting change	$	2.90	$	1.49	$	0.57
Cumulative effect of adoption of accounting principle		--		(0.03)		--
Net Income	$	2.90	$	1.46	$	0.57
Diluted Earnings per share:
Income before accounting change	$	2.80	$	1.45	$	0.55
Cumulative effect of adoption of accounting principle		--		(0.02)		--
Net Income	$	2.80	$	1.43	$	0.55
Weighted average common shares outstanding:
Basic		35,725,601		33,396,052		25,226,580
Diluted		36,962,772		34,237,934		26,052,238

The accompanying notes are an integral part of these consolidated financial statements.

54

BALANCE SHEETS

Southwestern Energy Company and Subsidiaries

	December 31,
	2004		2003
	(in thousands)
ASSETS
Current assets
Cash	$	1,235	$	1,277
Accounts receivable		86,268		58,543
Inventories, at average cost		32,248		31,418
Under-recovered purchased gas costs		--		1,107
Hedging asset - FAS 133		1,205		3,693
Other		10,029		4,272
Total current assets		130,985		100,310
Investments		15,465		13,840
Property, plant and equipment, at cost
Gas and oil properties, using the full cost method, including $47,239,000         in 2004 and $38,958,000 in 2003 excluded from amortization		1,483,824		1,201,917
Gas distribution systems		207,447		203,793
Gas in underground storage		32,254		33,256
Other		37,820		30,038
		1,761,345		1,469,004
Less: Accumulated depreciation, and amortization		777,189		706,720
		984,156		762,284
Other assets		15,538		14,276
	$	1,146,144	$	$ 890,710
LIABILITIES AND SHAREHOLDERS' EQUITY Current liabilities
Accounts payable	$	81,586	$	$ 54,186
Taxes payable		9,333		5,692
Interest payable		2,334		2,338
Customer deposits		5,903		5,277
Hedging liability - FAS 133		29,886		20,997
Regulatory liability - hedges		--		2,137
Other		4,658		4,441
Total current liabilities		133,700		95,068
Long-term debt		325,000		278,800
Other liabilities
Deferred income taxes		203,996		147,295
Other		23,912		15,859
		227,908		163,154
Commitments and contingencies Minority interest in partnership		11,859		12,127
Shareholders' equity Common stock, $0.10 par value; authorized 75,000,000 shares, issued 37,225,584 shares		3,723		3,723
Additional paid-in capital		128,753		123,519
Retained earnings		350,461		246,885
Accumulated other comprehensive income (loss)		(19,816)		(12,520)
Common stock in treasury, at cost, 821,576 shares in 2004 and 1,307,995 shares in 2003		(9,156)		(14,571)
Unamortized cost of restricted shares issued under stock incentive plan, 320,288 shares in 2004 and 421,617 shares in 2003		(6,288)		(5,475)
		447,677		341,561
	$	1,146,144	$	890,710

The accompanying notes are an integral part of these consolidated financial statements.

55

STATEMENTS OF CASH FLOWS

Southwestern Energy Company and Subsidiaries

	For the years ended December 31,
	2004		2003		2002
	(in thousands)
Cash flows from operating activities
Net income	$	103,576	$	48,897	$	14,311
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization		77,350		58,788		56,399
Deferred income taxes		59,778		28,896		8,708
Ineffectiveness of cash flow hedges		2,639		(636)		1,121
Equity in (income) loss of NOARK partnership		433		(1,053)		251
Gain on sale of other property, plant and equipment		(5,802)		(2,991)		--
Minority interest in partnership		(268)		(429)		(1,015)
Cumulative effect of adoption of accounting principle		--		855		--
Change in assets and liabilities:
Accounts receivable		(27,725)		(16,427)		648
Under/over-recovered gas costs		2,519		(6,804)		(2,487)
Inventories		(2,741)		(6,683)		1,871
Accounts payable		26,052		4,693		(2,883)
Other current assets and liabilities		2,086		1,993		650
Net cash provided by operating activities		237,897		109,099		77,574
Cash flows from investing activities
Capital expenditures		(291,101)		(168,172)		(92,062)
Sale of natural gas and oil properties		--		--		26,415
Distribution from (investment in) NOARK partnership		(2,059)		2,500		--
Proceeds from the sale of property, plant and equipment		7,121		3,649		--
Increase in gas stored underground		--		(860)		(349)
Other items		591		1,227		1,527
Net cash used in investing activities		(285,448)		(161,656)		(64,469)
Cash flows from financing activities
Issuance of common stock		--		103,085		--
Payments on revolving long-term debt		(395,100)		(273,000)		(204,100)
Borrowings under revolving long-term debt		441,300		209,400		196,500
Change in bank drafts outstanding		(2,347)		7,988		(9,880)
Proceeds from exercise of common stock options		5,170		4,671		1,955
Debt issuance costs		(1,514)		--		--
Contribution from minority interest owner in partnership		--		--		469
Net cash provided by (used in) financing activities		47,509		52,144		(15,056)
Decrease in cash		(42)		(413)		(1,951)
Cash at beginning of year		1,277		1,690		3,641
Cash at end of year	$	1,235	$	1,277	$	1,690

The accompanying notes are an integral part of these consolidated financial statements.

56

STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY AND COMPREHENSIVE INCOME (LOSS)

Southwestern Energy Company and Subsidiaries

								Accumulated				Unamortized
				Additional				Other				Restricted
				Paid-In			Retained	Comprehensive		Common Stock		Stock
	Common Stock			Capital			Earnings	Income (Loss)		In Treasury		Awards		Total
	Shares Issued	Amount
	(in thousands)
Balance at December 31, 2001	27,738	$	2,774	$	19,764	$	183,677	$	5,763	$	(25,196)	$	(3,696)	$	183,086
Comprehensive income Net income	--		--		--		14,311		--		--		--		14,311
Change in value of derivatives	--		--		--		--		(19,763)		--		--		(19,763)
Change in value of pension liability	--		--		--		--		(3,358)		--		--		(3,358)
Total comprehensive loss	--		--		--		--		--		--		--		(8,810)
Exercise of stock options	--		--		(728)		--		--		2,683		--		1,955
Issuance of restricted stock	--		--		77		--		--		2,601		(2,678)		--
Cancellation of restricted stock	--		--		17		--		--		(69)		52		--
Amortization of restricted stock and other	--		--		--		--		--		--		1,257		1,257
Balance at December 31, 2002	27,738	$	2,774	$	19,130	$	197,988	$	(17,358)	$	(19,981)	$	(5,065)	$	177,488
Comprehensive income: Net income	--		--		--		48,897		--		--		--		48,897
Change in value of derivatives	--		--		--		--		2,027		--		--		2,027
Change in value of pension liability	--		--		--		--		2,811		--		--		2,811
Total comprehensive income	--		--		--		--		--		--		--		53,735
Issuance of common stock	9,488		949		102,136		--		--		--		--		103,085
Exercise of stock options	--		--		1,202		--		--		4,308		--		5,510
Issuance of restricted stock	--		--		1,031		--		--		1,199		(2,230)		--
Cancellation of restricted stock	--		--		10		--		--		(119)		109		--
Amortization of restricted stock and other	--		--		10		--		--		22		1,711		1,743
Balance at December 31, 2003	37,226	$	3,723	$	123,519	$	246,885	$	(12,520)	$	(14,571)	$	(5,475)	$	341,561
Comprehensive income: Net income	--		--		--		103,576		--		--		--		103,576
Change in value of derivatives	--		--		--		--		(6,797)		--		--		(6,797)
Change in value of pension liability	--		--		--		--		(499)		--		--		(499)
Total comprehensive income	--		--		--		--		--		--		--		96,280
Exercise of stock options	--		--		3,078		--		--		4,786		--		7,864
Issuance of restricted stock	--		--		2,166		--		--		665		(2,831)		--
Cancellation of restricted stock	--		--		(10)		--		--		(36)		46		--
Amortization of restricted stock and other	--		--		--		--		--		--		1,972		1,972
Balance at December 31, 2004	37,226	$	3,723	$	128,753	$	350,461	$	(19,816)	$	(9,156)	$	(6,288)	$	447,677

The accompanying notes are an integral part of these consolidated financial statements.

57

STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY AND COMPREHENSIVE INCOME (LOSS)

Southwestern Energy Company and Subsidiaries

RECONCILIATION OF ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

	For the years ended December 31,
		2004	2003		2002
	(in thousands)
Balance, beginning of year	$	(12,520)	$	(17,358)	$	5,763
Current period reclassification to earnings		21,699		24,667		4,735
Current period change in derivative instruments		(28,496)		(22,640)		(24,498)
Current period change in pension liability		(499)		2,811		(3,358)
Balance, end of year	$	(19,816)	$	(12,520)	$	(17,358)

The accompanying notes are an integral part of these consolidated financial statements.

58

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Southwestern Energy Company and Subsidiaries

December 31, 2004, 2003 and 2002

(1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Nature of Operations and Consolidation

        Southwestern Energy Company (Southwestern or the Company) is an integrated energy company primarily focused on natural gas. Through its wholly-owned subsidiaries, the Company is engaged in natural gas and oil exploration and production, natural gas gathering, transmission and marketing, and natural gas distribution. Southwestern's exploration and production activities are concentrated in Arkansas, Texas, Louisiana, New Mexico and Oklahoma. The gas distribution segment operates in northern Arkansas and, depending upon weather conditions and current supply contracts, can obtain greater than 50% of its gas supply from one of the Company's exploration and production subsidiaries. The customers of the gas distribution segment consist of residential, commercial and industrial users of natural gas. Southwestern's marketing and transportation business is concentrated in its core areas of operations.

        The consolidated financial statements include the accounts of Southwestern Energy Company and its wholly-owned subsidiaries, including Southwestern Energy Production Company (SEPCO), SEECO, Inc., Arkansas Western Gas Company, Southwestern Energy Services Company, Diamond "M" Production Company, Southwestern Energy Pipeline Company, and A.W. Realty Company. The consolidated financial statements also include the results for a limited partnership, Overton Partners, L.P., in which SEPCO is the sole general partner. All significant intercompany accounts and transactions have been eliminated. The Company accounts for its general partnership interest in the NOARK Pipeline System, Limited Partnership (NOARK) using the equity method of accounting. In accordance with Statement of Financial Accounting Standards No. 71, "Accounting for the Effects of Certain Types of Regulation," the Company recognizes profit on intercompany sales of gas delivered to storage by its utility subsidiary.

        The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities, if any, at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Minority Interest in Partnership

        In 2001, SEPCO formed a limited partnership, Overton Partners, L.P., with an investor to drill and complete 14 development wells in SEPCO's Overton Field located in Smith County, Texas. Because SEPCO is the sole general partner and owns a majority interest in the partnership, the operating and financial results are consolidated with the Company's exploration and production results and the investor's share of the partnership activity is reported as a minority interest item in the financial statements. SEPCO contributed 50% of the capital required to drill the 14 wells. Revenues and expenses are allocated 65% to SEPCO prior to payout of the investor's initial investment and 85% thereafter. Under the terms of the partnership agreement, the partnership has a maximum life of 50 years. At December 31, 2004 the estimated fair value of the minority ownership position of the partnership does not exceed the minority interest of $11.9 million reflected in t he accompanying balance sheet.

Property, Depreciation, Depletion and Amortization

        Gas and Oil Properties. The Company follows the full cost method of accounting for the exploration, development, and acquisition of gas and oil reserves. Under this method, all such costs (productive and nonproductive) including salaries, benefits, and other internal costs directly attributable to these activities are capitalized and amortized on an aggregate basis over the estimated lives of the properties using the units-of-production method. The Company excludes all costs of unevaluated properties from immediate amortization. The Company's unamortized costs of natural gas and oil properties are limited to the sum of the future net revenues attributable to proved natural gas and oil reserves discounted at 10 percent plus the lower of cost or market value of any unproved properties. If the Company's unamortized costs in natural gas and oil properties exceed this ceiling amount, a provision for additional depreciation, depletion and amortiz ation is required. At December 31, 2004, the Company's net book value of natural gas and oil properties did not exceed the ceiling amount. Decreases in market prices from December 31, 2004 levels, as well as changes in production rates, levels of reserves, and the evaluation of costs excluded from amortization, could result in future ceiling test impairments.

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        In November 2002, the Company sold oil and gas properties for net proceeds of $26.4 million; the proceeds of the sale were reflected as a reduction of oil and gas properties with no gain or loss recognized.

        The Company's adoption of Statement of Financial Accounting Standards No. 143 "Accounting for Asset Retirement Obligations" (FAS 143), in January 2003 impacted its accounting for gas and oil properties principally by (1) recognizing future asset retirement obligations as a cost of its oil and gas properties and (2) subjecting to depreciation, depletion and amortization the recorded asset retirement costs as well as estimated future retirement costs associated with future development activities on proved properties, net of salvage value associated with the retirement of the properties.

        The adoption of FAS 143, as well as the adoption of Staff Accounting Bulletin No. 106 in September 2004, did not have a material impact upon the Company's calculation of its ceiling test. Additionally, the impact of adoption of FAS 143 did not have a material effect on the Company's financial position or results of operations.

        Statement of Financial Accounting Standards No. 141, "Business Combinations" (FAS 141), and Statement of Financial Accounting Standards No. 142, "Goodwill and Other Intangible Assets" (FAS 142), were issued in June 2001 and became effective for the Company on July 1, 2001, and January 1, 2002, respectively. The Company previously reported that an interpretation of FAS 141 and 142 was being considered as to whether mineral interest use rights in gas and oil properties are intangible assets and would be classified as such, separate from gas and oil properties. In September 2004, the Financial Accounting Standards Board (FASB) issued FASB Staff Position No. 142-2 which clarified that the classification and disclosure provisions of FAS 142 are not applicable to drilling and mineral rights of oil and gas producing entities. Therefore, the Company is not required to reclassify or disclose information regarding its oil and gas mineral interests in acc ordance with FAS 141 and FAS 142.

        Gas Distribution Systems. Costs applicable to construction activities, including overhead items, are capitalized. Depreciation and amortization of the gas distribution system is provided using the straight-line method with average annual rates for plant functions ranging from 2.1% to 6.6%.

        Other property, plant and equipment is depreciated using the straight-line method over estimated useful lives ranging from 7 to 45 years.

        The Company charges to maintenance or operations the cost of labor, materials and other expenses incurred in maintaining the operating efficiency of its properties. Betterments are added to property accounts at cost. Retirements are credited to property, plant and equipment at cost and charged to accumulated depreciation, depletion and amortization with no gain or loss recognized, except for abnormal retirements.

        Gas in Underground Storage. The Company has two gas storage facilities with the gas in storage stated at average cost, a portion of which is carried as current inventory. The storage facility owned by the gas distribution segment is used for supply to the utility's customers. The cost of the gas withdrawn from this storage facility is passed on to the consumer. The E&P segment primarily uses its storage facility to supplement production in meeting contractual commitments and records revenue on storage withdrawals when such gas is sold. The carrying value of this gas in storage is assessed based on current and future market prices for gas that the Company expects to realize.

        Capitalized Interest. Interest is capitalized on the cost of unevaluated gas and oil properties excluded from amortization. In accordance with established utility regulatory practice, an allowance for funds used during construction of major projects is capitalized and amortized over the estimated lives of the related facilities.

        Asset Retirement Obligations. As discussed above, FAS 143, "Accounting for Asset Retirement Obligations," was adopted by the Company on January 1, 2003. FAS 143 requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made, and that the associated asset retirement costs be capitalized as part of the carrying amount of the long-lived asset. The Company owns natural gas and oil properties which require expenditures to plug and abandon the wells when reserves in the wells are depleted. These expenditures under FAS 143 are recorded in the period the liability is incurred (at the time the wells are drilled or acquired). The effect of this standard on the Company's results of operations and financial condition at adoption was an increase in current and long-term liabilities of $1.2 million and $5.5 million, respectively; a net i ncrease in property, plant and equipment of $5.3 million; a cumulative effect of adoption expense of $0.9 million and a deferred tax asset of $0.5 million. The new standard had no material impact on income before the cumulative effect of adoption in the year ended December 31, 2003, nor would it have had a material impact, on a pro forma basis, in 2002 assuming that this accounting standard had been adopted at such time. The following table summarizes the Company's 2004 and 2003 activity related to asset retirement obligations:

60

	2004		2003
	(in thousands)
Asset retirement obligation at January 1	$	7,544	$	7,700
Accretion of discount		314		303
Obligations incurred		804		803
Obligations settled		(134)		(852)
Revisions of estimates		37		(410)
Asset retirement obligation at December 31	$	8,565	$	7,544
Current liability		473		184
Long-term liability		8,092		7,360
Total asset retirement obligation at December 31	$	8,565	$	7,544

Gas Distribution Revenues and Receivables

        Customer receivables arise from the sale or transportation of gas by the Company's gas distribution subsidiary. The Company's gas distribution customers are located in northern Arkansas and represent a diversified base of residential, commercial and industrial users. The Company records gas distribution revenues on an accrual basis, as gas volumes are used, to provide a proper matching of revenues with expenses.

        The gas distribution subsidiary's rate schedules include purchased gas adjustment clauses whereby the actual cost of purchased gas above or below the projected level included in the 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. Rate schedules include a weather normalization clause to lessen the impact of revenue increases and decreases which might result from weather variations during the winter heating season. The pass-through of gas costs to customers is not affected by this normalization clause.

        In the third quarter of 2003, the gas distribution subsidiary received regulatory approval from the Arkansas Public Service Commission (APSC) of a rate increase totaling $4.1 million annually, exclusive of costs to be recovered through the utility's purchase gas adjustment clause. The order also entitled the gas distribution subsidiary to recover certain additional costs totaling $2.3 million through its purchase gas adjustment clause over a two-year period. The gas distribution subsidiary recorded a $1.0 gain in 2003 associated with the future recovery of these costs. The rate increase was effective for all customer bills rendered on or after October 1, 2003.

Gas Production Revenue and Imbalances

        The exploration and production subsidiaries record gas sales using the entitlement method. The entitlement method requires revenue recognition of the Company's revenue interest share of gas production from properties in which gas sales are disproportionately allocated to owners because of marketing or other contractual arrangements. At December 31, 2004, the Company had overproduction of 1.3 Bcf valued at $3.7 million and underproduction of 1.5 Bcf valued at $4.4 million. At December 31, 2003, the Company had overproduction of 1.2 Bcf valued at $3.5 million and underproduction of 1.5 Bcf valued at $4.2 million.

Income Taxes

        Deferred income taxes are provided to recognize the income tax effect of reporting certain transactions in different years for income tax and financial reporting purposes. The Company's net operating loss carryforward at December 31, 2004 was $128.4 million with expiration dates in 2020 through 2024.

Derivative Financial Instruments

        The Company uses derivative financial instruments to manage defined commodity price risks and interest rate risks and does not use them for trading purposes. The Company uses commodity swap agreements and options to hedge sales and purchases of natural gas and sales of crude oil. Gains and losses resulting from hedging activities have been recognized in gas and oil sales in the statements of operations when the related physical transactions of commodities were recognized. Changes in fair value of derivative instruments designated as cash flow hedges are reported in other

61

comprehensive income (loss). Gains or losses from commodity swap agreements and options that do not qualify for accounting treatment as hedges are recognized currently as oil and gas sales. See Note 8 for a discussion of the Company's hedging activities and the effects of FAS 133.

Earnings Per Share

        Basic earnings per common share is computed by dividing net income by the weighted average number of common shares outstanding during each year. The diluted earnings per share calculation adds to the weighted average number of common shares outstanding the incremental shares that would have been outstanding assuming the exercise of dilutive stock options and the vesting of unvested restricted shares of common stock. For its diluted earnings per share calculation, the Company had no options outstanding at December 31, 2004, that were not included in the calculation of diluted shares. The Company had options for 222,030 shares of common stock with a weighted average exercise price of $21.93 per share at December 31, 2003, and options for 1,228,744 shares of common stock with a weighted average exercise price of $13.36 per share at December 31, 2002, that were not included in the calculation of diluted shares because they would have had an anti-dilutive effect. The remaining 2,221,128 options at December 31, 2004, with a weighted average exercise price of $12.71, 2,304,880 options at December 31, 2003, with a weighted average exercise price of $9.79, and 1,481,074 options at December 31, 2002, with a weighted average exercise price of $7.53 were included in the calculation of diluted shares. Restricted stock shares included in the calculation of diluted shares were 222,070, 175,364 and 498,123 for 2004, 2003 and 2002, respectively.

Guarantees

        The Company follows the disclosure provisions of Financial Accounting Standards Board Interpretation No. 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others." The nature of the Company's guarantee of debt associated with its investment in NOARK is included in Note 7 and Note 11 to the financial statements. This accounting standard also requires that upon the issuance or modification of guarantees, the guarantor must recognize a liability for the fair value of the obligations it assumes under the guarantee. Liability recognition is required on a prospective basis for guarantees that are made or modified after December 31, 2002.

Accounting for Stock-Based Compensation

        At December 31, 2004, the Company has a stock-based employee compensation plan, which is described more fully in Note 9. The Company accounts for this plan under the recognition and measurement principles of APB Opinion No. 25, "Accounting for Stock Issued to Employees," and related Interpretations. No stock-based employee compensation cost related to stock options is reflected in net income, as all options granted under the plan had an exercise price equal to the market value of the underlying common stock on the date of grant. The Company does record compensation cost for the amortization of restricted stock shares issued to employees. The following table illustrates the effect on net income and earnings per share if the Company had applied the fair value recognition provisions of Statement of Financial Accounting Standards No. 123, "Accounting for Stock-Based Compensation" (FAS 123), to stock-based employee compensation:

	For the years ended December 31,
	2004		2003		2002
	(in thousands, except share/per share amounts)
Net income, as reported	$	103,576	$	48,897	$	14,311
Add back: Amortization of restricted stock, net of related tax effects		1,251		1,083		781
Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effects		(2,433)		(2,245)		(1,798)
Pro forma net income	$	102,394	$	47,735	$	13,294
Earnings per share:
Basic-as reported	$	2.90	$	1.46	$	0.57
Basic-pro forma		2.87		1.43		0.53
Diluted-as reported		2.80		1.43		0.55
Diluted-pro forma		2.77		1.40		0.51

        The fair value of each option grant is estimated on the date of grant using the Black-Scholes option pricing model with the following weighted-average assumptions: no dividend yield for all years; expected volatility of 44.3% for 2004, 47.1% for 2003 and 45.6% for 2002; risk-free interest rate of 3.5% for 2004, 3.7% for 2003 and 3.4% for 2002; and expected lives of 5 to 6 years for all option grants. The fair values of the option grants for each of the years 2004, 2003 and 2002 were $2.6 million, $2.4 million and $1.9 million, respectively.

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        As discussed further in Note 14 below, "New Accounting Standards," the Company will adopt the provisions of FAS 123 (Revised 2004) in the third quarter of 2005. This standard will require the recognition of the fair value cost of equity awards, including stock options, as an expense over the service period provided by employees and directors.

(2) DEBT

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

	2004		2003
	(in thousands)
Senior notes:
6.70% Series due 2005	$	125,000	$	125,000
7.625% Series due 2027, putable at the holders' option in 2009		60,000		60,000
7.21% Series due 2017		40,000		40,000
		225,000		225,000
Other:
Variable rate (3.66% at December 31, 2004) unsecured revolving credit arrangements		100,000		53,800
Total long-term debt	$	325,000	$	278,800

        In January 2005, the Company arranged a new $500 million five-year unsecured revolving credit facility that amended and restated its existing $300 million three-year credit facility that would have expired in January 2007 and replaced a smaller unsecured credit facility that would have matured at the same time. The interest rate on the new credit facility is calculated based upon our debt rating and is currently 125 basis points over LIBOR. The revolving credit facility contains covenants which impose certain restrictions on the Company. Under the credit agreement, the Company may not issue total debt in excess of 60% of its total capital, must maintain a certain level of shareholders' equity, and must maintain a ratio of earnings before interest, taxes, depreciation and amortization (EBITDA) to interest expense of 3.5 or above. There are also restrictions on the ability of the Company's subsidiaries to incur debt. At December 31, 2004, the Compa ny's capital structure consisted of 42% debt (excluding its several guarantee of NOARK's obligations) and 58% equity, with a ratio of EBITDA to interest expense of 15.1, and the Company was in compliance with its debt agreements.

        The 6.70% senior notes in the table above are due December 2005. The Company currently intends to use its credit facility to repay these notes and, accordingly, these notes are classified as long-term based upon the Company's ability to fund them on a long-term basis. The 7.625% senior notes are putable at the holders' option beginning in 2009. Other than these two series of senior notes, there are no other aggregate maturities of long-term debt for each of the years ending December 31, 2005 through 2009. Total interest payments were $18.3 million in 2004, $17.3 million in 2003 and $21.5 million in 2002.

(3) INCOME TAXES

        The provision for income taxes included the following components:

	2004		2003		2002
	(in thousands)
Federal:
Current	$	--	$	--	$	--
Deferred		55,995		26,507		8,048
State:
Current		--		--		--
Deferred		3,899		2,506		779
Investment tax credit amortization		(116)		(117)		(119)
Provision for income taxes	$	59,778	$	28,896	$	8,708

        The provision for income taxes was an effective rate of 36.6% in 2004, 36.7% in 2003 and 37.8% in 2002. The following reconciles the provision for income taxes included in the consolidated statements of operations with the provision which would result from application of the statutory federal tax rate to pre-tax financial income:

63

	2004		2003		2002
	(in thousands)
Expected provision at federal statutory rate of 35%	$	57,174	$	27,527	$	8,055
Increase (decrease) resulting from: State income taxes, net of federal income tax effect		2,534		1,629		506
Other		70		(260)		147
Provision for income taxes	$	59,778	$	28,896	$	8,708

The components of the Company's net deferred tax liability as of December 31, 2004 and 2003 were as follows:

	2004		2003
	(in thousands)
Deferred tax liabilities:
Differences between book and tax basis of property	$	241,364	$	182,081
Stored gas		6,405		6,448
Book over tax basis in partnerships		12,452		12,851
Other		9,164		8,458
		269,385		209,838
Deferred tax assets:
Accrued compensation	$	1,566	$	556
Alternative minimum tax credit carryforward		3,026		3,026
Accrued pension costs		604		318
Cash flow hedges - FAS 133		11,024		7,338
Asset retirement obligations - FAS 143		3,034		2,525
Net operating loss carryforward		46,943		46,456
Other		3,635		3,282
		69,832		63,501
Net deferred tax liability	$	199,553	$	146,337

        The net deferred tax liability at December 31, 2004 consisted of a current deferred income tax asset of $3.6 million and long-term deferred income tax liabilities of $204.0 million including unamortized deferred investment tax credits of $0.8 million. There were no income tax payments in 2004, 2003 and 2002. The Company's net operating loss carryforward at December 31, 2004, was $128.4 million with expiration dates in 2020 through 2024. The Company also had an alternative minimum tax credit carryforward of $3.0 million and a statutory depletion carryforward of $5.6 million at December 31, 2004.

(4) PENSION PLAN AND OTHER POSTRETIREMENT BENEFITS

        The Company applies Statement of Financial Accounting Standards No. 132, "Employers' Disclosures about Pensions and Other Postretirement Benefits" (FAS 132). Substantially all employees are covered by the Company's defined benefit pension and postretirement benefit plans. The following provides a reconciliation of the changes in the plans' benefit obligations, fair value of assets, and funded status as of December 31, 2004 and 2003:

	Pension Benefits				Other Postretirement Benefits
	2004		2003		2004		2003
	(in thousands)
Change in benefit obligations:
Benefit obligation at January 1	$	60,665	$	54,694	$	4,049	$	3,156
Service cost		2,404		2,170		174		139
Interest cost		3,692		3,659		252		238
Participant contributions		--		--		88		82
Actuarial loss		1,755		3,820		178		668
Benefits paid		(4,716)		(3,678)		(237)		(234)
Benefit obligation at December 31	$	63,800	$	60,665	$	4,504	$	4,049

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	Pension Benefits				Other Postretirement Benefits
	2004		2003		2004		2003
	(in thousands)
Change in plan assets:
Fair value of plan assets at January 1	$	51,956	$	41,973	$	838	$	732
Actual return on plan assets		4,994		10,659		(21)		(24)
Employer contributions		1,931		3,002		446		282
Participant contributions		--		--		88		82
Benefit payments		(4,716)		(3,678)		(237)		(234)
Amount transferred		--		--		--		--
Fair value of plan assets at December 31	$	54,165	$	51,956	$	1,114	$	838
Funded status:
Funded status at December 31	$	(9,635)	$	(8,709)	$	(3,390)	$	(3,211)
Unrecognized net actuarial loss		9,819		8,747		2,030		1,891
Unrecognized prior service cost		3,166		3,610		--		--
Unrecognized transition obligation		--		--		688		774
Net amount recognized	$	3,350	$	3,648	$	(672)	$	(546)

        The Company uses a December 31 measurement date for all of its plans. Amounts recognized in the balance sheets as of December 31, 2004 and 2003 consist of the following:

	Pension Benefits				Other Postretirement Benefits
	2004		2003		2004		2003
	(in thousands)
Accrued pension cost	$	(1,518)	$	(884)	$	(672)	$	(546)
Intangible asset		3,218		3,668		--		--
Accumulated other comprehensive loss (pre-tax)		1,650		864		--		--
Net amount recognized	$	3,350	$	3,648	$	(672)	$	(546)

        The change in accumulated other comprehensive loss related to the pension plans was income of $0.8 million ($0.5 million after tax) for the year ended December 31, 2004, and income of $4.5 million ($2.8 million after tax) for the year ended December 31, 2003. Included in accumulated other comprehensive loss at December 31, 2004 and 2003 was a $1.6 million loss ($1.0 million net of tax), and a $0.9 million loss ($0.5 million net of tax), respectively, related to the Company's pension plans.

        The Company's pension plans have an accumulated benefit obligation in excess of plan assets as of December 31, 2004 and 2003 as follows:

	2004		2003
	(in thousands)
Projected benefit obligation	$	63,800	$	60,665
Accumulated benefit obligation		55,683		52,766
Fair value of plan assets		54,165		51,956

        Net periodic pension and other postretirement benefit costs include the following components for 2004, 2003 and 2002:

	Pension Benefits						Other Postretirement Benefits
	2004		2003		2002		2004		2003		2002
	(in thousands)
Service cost	$	2,404	$	2,171	$	1,967	$	174	$	139	$	90
Interest cost		3,692		3,659		3,655		252		238		170
Expected return on plan assets		(4,543)		(3,608)		(5,165)		(42)		(36)		(41)
Amortization of transition obligation		--		--		--		86		86		86
Recognized net actuarial loss		233		664		7		102		87		79
Amortization of prior service cost		444		446		457		--		--		--
	$	2,230	$	3,332	$	921	$	572	$	514	$	384

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        Prior to January 1, 1998, the Company maintained a traditional defined benefit plan with benefits payable based upon average final compensation and years of service. Effective January 1, 1998, the Company amended its pension plan to become a "cash balance" plan on a prospective basis for its non-bargaining employees. A cash balance plan provides benefits based upon a fixed percentage of an employee's annual compensation. The Company's funding policy is to contribute amounts which are actuarially determined to provide the plans with sufficient assets to meet future benefit payment requirements and which are tax deductible.

        The postretirement benefit plans provide contributory health care and life insurance benefits. Employees become eligible for these benefits if they meet age and service requirements. Generally, the benefits paid are a stated percentage of medical expenses reduced by deductibles and other coverages. The Company has established trusts to partially fund its postretirement benefit obligations.

        The weighted average assumptions used in the measurement of the Company's benefit obligations at December 31, 2004 and 2003 are as follows:

	Pension Benefits		Other Postretirement Benefits
	2004	2003	2004	2003
Discount rate	6.00%	6.25%	6.00%	6.25%
Rate of compensation increase	4.00%	4.00%	n/a	n/a

        The weighted average assumptions used in the measurement of the Company's net periodic benefit cost for 2004 and 2003 are as follows:

	Pension Benefits		Other Postretirement Benefits
	2004	2003	2004	2003
Discount rate	6.25%	6.75%	6.25%	6.75%
Expected return on plan assets	9.00%	9.00%	5.00%	5.00%
Rate of compensation increase	4.00%	4.00%	n/a	n/a

        The expected return on plan assets for the various benefit plans is based upon a review of the historical returns experienced, combined with the future expected returns based upon the asset allocation strategy employed. The plans seek to achieve an adequate return to fund the obligations in a manner consistent with the federal standards of ERISA and with a prudent level of diversification.

        For measurement purposes, the following trend rates were assumed for 2004 and 2003:

	2004	2003
Health care cost trend assumed for next year	10%	11%
Rate to which the cost trend is assumed to decline	5%	5%
Year that the rate reaches the ultimate trend rate	2010	2010

        Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. A one percentage point change in assumed health care cost trend rates would have the following effects:

	1% Increase	1% Decrease
	(in thousands)
Effect on the total service and interest cost components	$   60	$   (50)
Effect on postretirement benefit obligation	$ 586	$ (492)

        The Company's pension plan weighted-average asset allocations at December 31, 2004, and 2003, by asset category are as follows:

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	2004	2003
Asset category:
Equity securities	65%	65%
Debt securities	33%	33%
Cash equivalents	2%	2%
Total	100%	100%

        Assets of the postretirement benefit plans were invested 100% in debt securities for 2004 and 2003.

        The investment objective of the benefit plans is to ensure, over the long-term life of the plans, an adequate pool of assets to support the benefit obligations to participants, retirees and beneficiaries. As of December 31, 2004, the defined benefit pension plan had a diversified asset allocation strategy of 60%-70% equity securities and 30%-40% debt (fixed income) securities. Within the equity allocation, the plan invests in small cap, international, large cap growth, large cap value and large cap core securities. Plan assets are periodically balanced whenever the allocation to any asset class falls outside of the specified range.

        In 2004, the Company contributed $1.9 million to its pension plans and $0.4 million to its other postretirement benefit plans. The Company expects to contribute $2.0 million to its pension plan and $0.4 million to its other postretirement benefit plans in 2005.

        The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid:

	Pension Benefits	Other Benefits
	(in thousands)
2005	$ 2,987	$ 188
2006	3,624	183
2007	4,336	199
2008	4,025	238
2009	4,491	275
Years 2010-2014	26,511	1,504

(5) NATURAL GAS AND OIL PRODUCING ACTIVITIES (UNAUDITED)

        All of the Company's gas and oil properties are located in the United States. The table below sets forth the results of operations from gas and oil producing activities:

	2004		2003		2002
	(in thousands)
Sales	$	286,924	$	176,245	$	122,207
Production (lifting) costs		(35,501)		(24,993)		(25,514)
Depreciation, depletion and amortization		(66,924)		(49,553)		(47,680)
		184,499		101,699		49,013
Income tax expense		(67,031)		(37,306)		(18,474)
Results of operations	$	117,468	$	64,393	$	30,539

        The results of operations shown above exclude general and administrative expenses and interest costs. Income tax expense is calculated by applying the statutory tax rates to the revenues less costs, including depreciation, depletion and amortization, and after giving effect to permanent differences and tax credits.

        The table below sets forth capitalized costs incurred in gas and oil property acquisition, exploration and development activities during 2004, 2003 and 2002:

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	2004		2003		2002
	(in thousands)
Proved property acquisition costs	$	15,384	$	3,240	$	3,481
Unproved property acquisition costs		21,830		17,484		4,984
Exploration costs		24,526		20,862		24,552
Development costs		219,455		129,028		51,818
Capitalized costs incurred	$	281,195	$	170,614	$	84,835
Full cost pool amortization per Mcf equivalent	$	1.20	$	1.17	$	1.16

        Capitalized interest is included as part of the cost of natural gas and oil properties. The Company capitalized $2.8 million, $1.8 million and $1.5 million during 2004, 2003 and 2002, respectively, based on the Company's weighted average cost of borrowings used to finance the expenditures.

        In addition to capitalized interest, the Company also capitalized internal costs of $14.3 million, $10.6 million and $9.5 million during 2004, 2003 and 2002, respectively. These internal costs were directly related to acquisition, exploration and development activities and are included as part of the cost of natural gas and oil properties.

        The following table shows the capitalized costs of gas and oil properties and the related accumulated depreciation, depletion and amortization at December 31, 2004 and 2003:

	2004		2003
	(in thousands)
Proved properties	$	1,436,585	$	1,162,959
Unproved properties		47,239		38,958
Total capitalized costs		1,483,824		1,201,917
Less: Accumulated depreciation, depletion and amortization		658,445		593,017
Net capitalized costs	$	825,379	$	608,900

        The table below sets forth the composition of net unevaluated costs excluded from amortization as of December 31, 2004. Of the total, approximately $10.5 million represents costs of wells in progress at December 31, 2004, and approximately $25.0 million is related to undeveloped leasehold costs in the Company's Fayetteville Shale play. The remaining costs excluded from amortization are related to properties which are not individually significant and on which the evaluation process has not been completed. The Company is, therefore, unable to estimate when these costs will be included in the amortization computation.

	2004		2003		2002		Prior		Total
	(in thousands)
Property acquisition costs	$	19,855	$	11,361	$	484	$	1,609	$	33,309
Exploration and development costs		9,721		34		743		437		10,935
Capitalized interest		864		1,204		198		729		2,995
	$	30,440	$	12,599	$	1,425	$	2,775	$	47,239

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(6) NATURAL GAS AND OIL RESERVES (UNAUDITED)

        The following table summarizes the changes in the Company's proved natural gas and oil reserves for 2004, 2003 and 2002:

	2004		2003		2002
	Gas (MMcf)	Oil (MBbls)	Gas (MMcf)	Oil (MBbls)	Gas (MMcf)	Oil (MBbls)
Proved reserves, beginning of year	457,016	7,675	374,614	6,784	355,813	7,704
Revisions of previous estimates	(13,832)	199	(16,668)	186	1,110	234
Extensions, discoveries and other additions	196,398	1,274	136,261	1,193	73,803	553
Production	(50,425)	(618)	(37,967)	(531)	(35,972)	(682)
Acquisition of reserves in place	5,634	30	808	48	6,538	15
Disposition of reserves in place	(308)	(52)	(32)	(5)	(26,678)	(1,040)
Proved reserves, end of year	594,483	8,508	457,016	7,675	374,614	6,784
Proved developed reserves:
Beginning of year	369,867	6,719	286,276	5,633	281,461	6,429
End of year	491,697	7,767	369,867	6,719	286,276	5,633

        The "Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Natural Gas and Oil Reserves" (standardized measure) is a disclosure required by Statement of Financial Accounting Standards No. 69, "Disclosures About Oil and Gas Producing Activities" (FAS 69). The standardized measure does not purport to present the fair market value of a company's proved gas and oil reserves. In addition, there are uncertainties inherent in estimating quantities of proved reserves. The gas and oil reserve quantities owned by the Company were audited by the independent petroleum engineering firm of Netherland, Sewell & Associates, Inc.

        Following is the standardized measure relating to proved gas and oil reserves at December 31, 2004, 2003 and 2002:

	2004		2003		2002
	(in thousands)
Future cash inflows	$	3,857,623	$	2,914,824	$	1,951,454
Future production costs		(983,654)		(644,014)		(466,742)
Future development costs		(108,911)		(69,668)		(62,206)
Future income tax expense		(779,386)		(647,605)		(420,336)
Future net cash flows		1,985,672		1,553,537		1,002,170
10% annual discount for estimated timing of cash flows		(1,093,364)		(837,185)		(500,571)
Standardized measure of discounted future net cash flows	$	892,308	$	716,352	$	501,599

        Under the standardized measure, future cash inflows were estimated by applying year-end prices, adjusted for known contractual changes, to the estimated future production of year-end proved reserves. Year-end market prices used for the standardized measures above were $6.18 per Mcf for gas and $43.45 per barrel for oil in 2004, $5.97 per Mcf for gas and $32.52 per barrel for oil in 2003, and $4.74 per Mcf for gas and $31.20 per barrel for oil in 2002. Future cash inflows were reduced by estimated future production and development costs based on year-end costs to determine pre-tax cash inflows. Future income taxes were computed by applying the year-end statutory rate, after consideration of permanent differences, to the excess of pre-tax cash inflows over the Company's tax basis in the associated proved gas and oil properties. Future net cash inflows after income taxes were discounted using a 10% annual discount rate to arrive at the standardized measure.

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        Following is an analysis of changes in the standardized measure during 2004, 2003 and 2002:

	2004		2003		2002
	(in thousands)
Standardized measure, beginning of year	$	716,352	$	501,599	$	308,160
Sales and transfers of gas and oil produced, net of production costs		(252,241)		(151,793)		(96,693)
Net changes in prices and production costs		28,009		182,019		284,277
Extensions, discoveries, and other additions, net of future production and development costs		367,892		338,374		137,105
Acquisition of reserves in place		20,771		1,759		11,269
Revisions of previous quantity estimates		(26,481)		(34,637)		4,870
Accretion of discount		99,432		69,413		39,451
Net change in income taxes		(48,091)		(85,441)		(106,177)
Changes in estimated future development costs		(70,005)		(29,399)		(16,533)
Previously estimated development costs incurred during the year		42,143		29,921		16,032
Changes in production rates (timing) and other		14,527		(105,463)		(80,162)
Standardized measure, end of year	$	892,308	$	716,352	$	501,599

(7) INVESTMENT IN UNCONSOLIDATED PARTNERSHIP

        The Company holds a 25% general partnership interest in NOARK. NOARK Pipeline was formerly a 258-mile intrastate gas transmission system, which extended across northern Arkansas. In January 1998, the Company entered into an agreement with Enogex Inc. (Enogex) that resulted in the expansion of the NOARK Pipeline and provided the pipeline with access to Oklahoma gas supplies through an integration of NOARK with the Ozark Gas Transmission System (Ozark). Enogex is a subsidiary of OGE Energy Corp. Ozark was a 437-mile interstate pipeline system which began in eastern Oklahoma and terminated in eastern Arkansas. Enogex acquired the Ozark system and contributed it to NOARK. Enogex also acquired the NOARK partnership interests not owned by Southwestern. The acquisition of Ozark and its integration with NOARK Pipeline was approved by the Federal Energy Regulatory Commission in late 1998 at which time NOARK Pipeline was converted to an interstate pipel ine and operated in combination with Ozark. The combined pipeline systems are now collectively called the Ozark Gas Transmission System. Enogex funded the acquisition of Ozark and the expansion and integration with NOARK Pipeline, which resulted in the Company's ownership interest in the partnership decreasing to 25% from 48%. The Company is responsible for 60% of debt principal and interest payments in accordance with its several guarantee of NOARK's debt.

        The Company's investment in the NOARK partnership totaled $15.4 million at December 31, 2004, and $13.8 million at December 31, 2003. See Note 11 for further discussion of NOARK's funding requirements and the Company's investment in NOARK.

        The Company recorded a pre-tax loss of $0.4 million in 2004, pre-tax income of $1.1 million in 2003, and a pre-tax loss of $0.3 million for 2002, for its share of NOARK's results of operations. The pre-tax income in 2003 included a gain of $1.3 million recognized on the sale of a 28-mile portion of Ozark Gas Transmission System located in Oklahoma that had limited strategic value to the overall system. The Company records its share of NOARK's results of operations in other income (expense) on the consolidated statements of operations.

(8) FINANCIAL INSTRUMENTS AND RISK MANAGEMENT

Fair Value of Financial Instruments

        The following methods and assumptions were used to estimate the fair value of each class of financial instruments for which it is practicable to estimate the value:

        Cash, Customer Deposits and Short-Term Debt: The carrying amount is a reasonable estimate of fair value.

        Long-Term Debt: The fair value of the Company's long-term debt is estimated based on the expected current rates which would be offered to the Company for debt of the same maturities.

        Commodity and Interest Hedges: The fair value of all hedging financial instruments is the amount at which they could be settled, based on quoted market prices or estimates obtained from dealers.

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        The carrying amounts and estimated fair values of the Company's financial instruments as of December 31, 2004 and 2003 were as follows:

	2004				2003
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(in thousands)
Cash	$	1,235	$	1,235	$	1,276	$	1,276
Customer deposits	$	5,903	$	5,903	$	5,277	$	5,277
Long-term debt	$	325,000	$	335,440	$	278,800	$	290,040
Commodity and interest hedges asset (liability)	$	(34,477)	$	(34,477)	$	(17,778)	$	(17,778)

Derivatives and Risk Management

        Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities" (FAS 133), as amended by FAS 137, FAS 138 and FAS 149, was adopted by the Company on January 1, 2001. FAS 133 requires that all derivatives be recognized in the balance sheet as either an asset or liability measured at its fair value. Special accounting for qualifying hedges allows a derivative's gains and losses to offset related results on the hedged item in the income statement.

        At December 31, 2004, the Company recorded hedging assets of $1.2 million, hedging liabilities of $35.7 million, a regulatory asset of $1.4 million related to its utility gas purchase hedges, and a net of tax loss to other comprehensive income (loss) of $18.8 million. The amount recorded in other comprehensive income (loss) will be relieved over time and taken to the income statement as the physical transactions being hedged occur. At December 31, 2003, the Company recorded hedging assets of $3.7 million, hedging liabilities of $21.5 million, a regulatory liability of $2.1 million related to its utility gas purchase hedges, and a net of tax loss to other comprehensive income (loss) of $12.0 million. The change in accumulated other comprehensive loss related to derivatives was a loss of $10.7 million ($6.8 million after tax) for the year ended December 31, 2004, income of $3.2 million ($2.0 million after tax) for the year ended December 31, 2003, a nd a loss of $31.9 million ($19.8 million after tax) for the year ended December 31, 2002. Assuming the market prices of futures as of December 31, 2004 remain unchanged, we would expect to transfer a loss of approximately $16.2 million from accumulated other comprehensive income to earnings during the next 12 months when the transactions actually close. All transactions hedged as of December 31, 2004 are expected to mature by December 31, 2006.

        The Company recorded a $1.5 million loss in 2004, a $0.5 million loss in 2003 and a $1.1 million loss in 2002 related to basis differential ineffectiveness associated with the Company's cash flow hedges. Additionally, the Company recorded a $1.1 million loss in 2004 and a $1.1 million gain in 2003 related to mark-to-market adjustments on basis differential swaps which did not qualify for hedge treatment. In early 2003, the Company discontinued an interest hedge when it paid down its revolving credit facility with proceeds from an equity issuance. There were no discontinued hedges in 2002. Additional volatility in earnings and other comprehensive income (loss) may occur in the future as a result of the adoption of FAS 133.

        The Company uses natural gas and crude oil swap agreements and options and interest rate swaps to reduce the volatility of earnings and cash flow due to fluctuations in the prices of natural gas and oil and in interest rates. The Board of Directors has approved risk management policies and procedures to utilize financial products for the reduction of defined commodity price and interest rate risks. These policies prohibit speculation with derivatives and limit swap agreements to counterparties with appropriate credit standings.

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

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        At December 31, 2004, the Company had outstanding natural gas price swaps on total notional volumes of 12.9 Bcf in 2005 and 5.0 Bcf in 2006 for which the Company will receive fixed prices ranging from $4.49 to $6.89 per MMBtu. Outstanding oil price swaps on 480 MBbls were in place that will yield the Company an average price of $34.20 per barrel. At December 31, 2004, the Company also had outstanding natural gas price swaps on total notional volumes of 3.1 Bcf in 2005 for which the Company will pay an average fixed price of $6.50 per Mcf. At December 31, 2004, the Company had outstanding fixed price basis differential swaps on 4.1 Bcf of 2005 gas production that did not qualify for hedge treatment.

        At December 31, 2004, the Company had collars in place on notional volumes of 33.4 Bcf in 2005 and 22.0 Bcf in 2006. The 33.4 Bcf in 2005 had an average floor and ceiling price of $4.68 and $8.30 per MMBtu, respectively. The 22.0 Bcf in 2006 had an average floor and ceiling price of $4.64 and $8.69 per MMBtu, respectively. The Company's price risk management activities reduced revenues by $35.6 million in 2004, $37.4 million in 2003 and $6.1 million in 2002.

        The primary market risks related to the Company's derivative contracts are the volatility in commodity prices, basis differentials and interest rates. However these market risks are offset by the gain or loss recognized upon the related sale or purchase of the natural gas or sale of oil that is hedged, and payment of variable rate interest. Credit risk relates to the risk of loss as a result of non-performance by the Company's counterparties. The counterparties are primarily major investment and commercial banks which management believes present minimal credit risks. The credit quality of each counterparty and the level of financial exposure the Company has to each counterparty are periodically reviewed to ensure limited credit risk exposure.

(9) STOCK OPTIONS AND RESTRICTED STOCK GRANTS

        The Southwestern Energy Company 2004 Stock Incentive Plan (2004 Plan) was adopted in February 2004 and provides for the compensation of officers, key employees and eligible non-employee directors of the Company and its subsidiaries. The 2004 Plan replaced the Southwestern Energy Company 2000 Stock Incentive Plan (2000 Plan) and the Southwestern Energy Company 2002 Employee Stock Incentive Plan (2002 Plan). The Company also has awards outstanding related to the Southwestern Energy Company 1993 Stock Incentive Plan (1993 Plan) and the Southwestern Energy Company 1993 Stock Incentive Plan for Outside Directors (1993 Director Plan). The 2004 Plan provides for grants of options, stock appreciation rights, and shares of restricted stock and restricted stock units that in the aggregate do not exceed 2,100,000 shares. The types of incentives which may be awarded are comprehensive and are intended to enable the Board of Directors to structure the most appropriate incentives and to address changes in income tax laws which may be enacted over the term of the 2004 Plan.

        The 2000 Plan provided for the grant of options, stock appreciation rights, shares of phantom stock, and shares of restricted stock that in the aggregate did not exceed 1,250,000 shares. The 2002 Plan provided for the compensation of employees who are not officers or directors of the Company under provisions of Section 16 of the Securities Exchange Act of 1934. The 2002 Plan provided for grants of options, stock appreciation rights, shares of phantom stock and shares of restricted stock that in the aggregate did not exceed 300,000 shares.

        The 1993 Plan provided for the compensation of officers and key employees of the Company and its subsidiaries through grants of options, shares of restricted stock, and stock bonuses that in the aggregate did not exceed 1,700,000 shares, the grant of stand-alone stock appreciation rights (SARs), shares of phantom stock and cash awards, the shares related to which in the aggregate did not exceed 1,700,000 shares, and the grant of limited and tandem SARs (all terms as defined in the 1993 Plan). The Company has also awarded stock option grants outside the various stock incentive plans to certain non-officer employees and to certain officers at the time of their hire.

        The 2004 Plan does not specify a specific award to the non-employee directors who are eligible to participate in the plan. Previously, the 2000 Plan awarded each non-employee director an annual Director's Option with respect to 8,000 shares of common stock, and the 1993 Director Plan provided for annual stock option grants of 12,000 shares (with 12,000 limited SARs) to each non-employee director.

        The following tables summarize stock option activity for the years 2004, 2003 and 2002 and provide information for options outstanding at December 31, 2004:

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	2004			2003			2002
	Number of Shares	Weighted Average Exercise Price		Number of Shares	Weighted Average Exercise Price		Number of Shares	Weighted Average Exercise Price
Options outstanding at January 1	2,526,910	$	10.86	2,709,818	$	10.17	2,672,186	$	9.84
Granted	125,010		47.95	222,030		21.93	346,010		11.43
Exercised	429,626		12.07	401,605		12.38	247,464		8.39
Canceled	1,166		12.54	3,333		7.44	60,914		10.09
Options outstanding at December 31	2,221,128	$	12.71	2,526,910	$	10.86	2,709,818	$	10.17

	Options Outstanding				Options Exercisable
Range of Exercise Prices	Options Outstanding at Year End	Weighted Average Exercise Price		Weighted Average Remaining Contractual Life (Years)	Options Exercisable at Year End	Weighted Average Exercise Price
$6.00 - $7.00	377,883	$	6.21	4.8	377,883	$	6.21
$7.01 - $10.00	758,530		7.86	5.7	758,530		7.86
$10.01 - $13.00	560,189		11.72	6.1	429,851		11.83
$13.01 - $18.00	178,000		14.09	1.8	177,167		14.10
$18.01 - $30.00	228,516		21.95	9.0	69,500		21.77
$30.01 - $49.80	118,010		49.46	6.9	--		--
	2,221,128	$	12.71	5.7	1,812,931	$	9.60

        All options are issued at fair market value at the date of grant and expire seven years from the date of grant for awards under the 2004 Plan and ten years from the date of grant for awards under all other plans. Options generally vest to employees and directors over a three- to four-year period from the date of grant.

        As disclosed in Note 1, the Company applies the disclosure-only provisions of FAS 123, "Accounting for Stock-Based Compensation." Accordingly, no compensation cost has been recognized for the stock option plans. As discussed further in Note 14 below, "New Accounting Standards," the Company will adopt the provisions of FAS 123 (Revised 2004) in the third quarter of 2005. This standard will require the recognition of the fair value cost of equity awards as an expense over the service period provided by employees and directors.

        The Company granted 59,690 shares, 110,038 shares and 233,460 shares of restricted stock in 2004, 2003 and 2002, respectively. The fair values of the grants were $2.8 million for 2004, $2.3 million for 2003 and $2.7 million for 2002. Of the 1,156,203 shares granted to date, 433,715 shares vest over a three-year period, 679,938 shares vest over a four-year period and the remaining shares vest over a five-year period. The related compensation expense is being amortized over the vesting periods. Compensation expense related to the amortization of restricted stock grants was $2.0 million for 2004, $1.7 million for 2003 and $1.3 million for 2002. As of December 31, 2004, 772,542 shares have vested to employees. Restricted shares cancelled in 2004, 2003 and 2002 were 3,210 shares, 13,142 shares and 6,739 shares, respectively.

(10) COMMON STOCK PURCHASE RIGHTS

        In 1999, the Company's Common Share Purchase Rights Plan was amended and extended for an additional ten years. Per the terms of the amended plan, one common share purchase right is attached to each outstanding share of the Company's common stock. Each right entitles the holder to purchase one share of common stock at an exercise price of $40.00, subject to adjustment. These rights will become exercisable in the event that a person or group acquires or commences a tender or exchange offer for 15% or more of the Company's outstanding shares or the Board determines that a holder of 10% or more of the Company's outstanding shares presents a threat to the best interests of the Company. At no time will these rights have any voting power.

        If any person or entity actually acquires 15% of the common stock (10% or more if the Board determines such acquiror is adverse), rightholders (other than the 15% or 10% stockholder) will be entitled to buy, at the right's then current exercise price, the Company's common stock with a market value of twice the exercise price. Similarly, if the Company is

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acquired in a merger or other business combination, each right will entitle its holder to purchase, at the right's then current exercise price, a number of the surviving company's common shares having a market value at that time of twice the right's exercise price.

        The rights may be redeemed by the Board for $0.01 per right or exchanged for common shares on a one-for-one basis prior to the time that they become exercisable. In the event, however, that redemption of the rights is considered in connection with a proposed acquisition of the Company, the Board may redeem the rights only on the recommendation of its independent directors (non-management directors who are not affiliated with the proposed acquiror). These rights expire in 2009.

(11) CONTINGENCIES AND COMMITMENTS

        The Company and the other general partner of NOARK have severally guaranteed the principal and interest payments on NOARK's 7.15% Notes due 2018. The Company's share of the several guarantee is 60%. At December 31, 2004 and 2003, the principal outstanding for these Notes was $67.0 million and $69.0 million, respectively. The Notes were issued in June 1998 and require semi-annual principal payments of $1.0 million. Under the several guarantee, the Company is required to fund its share of NOARK's debt service which is not funded by operations of the pipeline. The Company advanced $2.1 million to NOARK in 2004 and did not advance any funds to NOARK in 2003 or 2002. As a result of the integration of NOARK Pipeline with the Ozark Gas Transmission System, as discussed further in Note 7, management of the Company believes that it will realize its investment in NOARK over the life of the system. Therefore, no provision for any loss has been made in th e accompanying financial statements. Additionally, our gas distribution subsidiary has a transportation contract with Ozark Pipeline for 66.9 MMcf per day of firm capacity that expires in 2014.

        The Company leases certain office space and equipment under non-cancelable operating leases expiring through 2013. Under certain of these leases the Company is required to pay property taxes, insurance, repairs and other costs related to the leased property. At December 31, 2004, future minimum payments under non-cancelable leases accounted for as operating leases are approximately $1,691,000 in 2005, $1,547,000 in 2006, $1,509,000 in 2007, $1,484,000 in 2008, $1,496,000 in 2009 and $2,477,000 thereafter. Total rent expense for all operating leases was $1,175,000, $1,196,000 and $811,000 in 2004, 2003 and 2002, respectively.

        The Company's utility segment has entered into various non-cancelable agreements related to demand charges for the transportation and purchase of natural gas with third parties. These costs are recoverable from the utility's end-use customers. At December 31, 2004, future payments under these non-cancelable demand contracts are $9,687,000 in 2005, $8,566,000 in 2006, $8,815,000 in 2007, $9,202,000 in 2008, $9,588,000 in 2009 and $51,645,000 thereafter. Additionally, the E&P segment has a commitment to a third party for demand transportation charges. At December 31, 2004, future payments under these non-cancelable demand contracts are $1,926,000 in 2005, $1,409,000 in 2006, $677,000 in 2007, $617,000 in 2008, $617,000 in 2009 and $412,000 thereafter.

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

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

(12) SEGMENT INFORMATION

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

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

	Exploration And Production			Gas Distribution		Marketing		Other			Total
2004	(in thousands)
Revenues from external customers	$	253,920		$	152,288	$	65,128	$	5,801		$	477,137
Intersegment revenues		33,004			161		249,849		448			283,462
Operating income		164,585			8,516		3,151		6,035			182,287
Depreciation, depletion and amortization expense		66,924			6,592		67		91			73,674
Interest expense(1)		11,537			4,461		--		994			16,992
Provision for income taxes(1)		55,197			1,471		1,151		1,959			59,778
Assets		890,486			184,213		29,243		42,202	(2)		1,146,144
Capital expenditures(3)		281,988			7,298		--		5,704			294,990
2003
Revenues from external customers	$	143,864		$	137,200	$	43,313	$	3,024		$	327,401
Intersegment revenues		32,381			156		158,664		448			191,649
Operating income		84,737			6,766		2,612		3,227			97,342
Depreciation, depletion and amortization expense		49,553			6,252		50		93			55,948
Interest expense(1)		11,911			4,395		--		1,005			17,311
Provision for income taxes(1)		26,010			767		954		1,165			28,896
Assets		666,815			171,027		16,223		36,645	(2)		890,710
Capital expenditures(3)		170,886			8,178		10		1,129			180,203
2002
Revenues from external customers	$	104,081		$	115,712	$	41,709	$	--		$	261,502
Intersegment revenues		18,126			138		89,357		448			108,069
Operating income		36,048			7,563		2,652		242			46,505
Depreciation, depletion and amortization expense		47,680			6,115		104		93			53,992
Interest expense(1)		16,597			3,868		--		1,001			21,466
Provision (benefit) for income taxes(1)		6,744			1,316		963		(315)			8,708
Assets		527,591			163,803		9,998		38,770	(2)		740,162
Capital expenditures		85,201	(4)		6,115		--		746			92,062

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

(2) Other assets include the Company's equity investment in the operations of NOARK (see Note 7), corporate assets not allocated to segments and assets for non-reportable segments.

(3) Capital expenditures for 2004 and 2003 included $3.9 million and $12.0 million, respectively, related to the change in accrued expenditures between years.

(4) Includes $0.5 million in 2002 funded by the owner of the minority interest in Overton partnership.

        Included in intersegment revenues of the marketing segment are $235.7 million, $154.1 million and $89.4 million for 2004, 2003 and 2002, respectively, for marketing of the Company's exploration and production sales. Intersegment sales by the E&P segment and marketing segment to the gas distribution segment are priced in accordance with terms of existing contracts and current market conditions. Parent company assets include furniture and fixtures, prepaid debt costs, and prepaid and intangible pension related costs. Parent company general and administrative costs, depreciation expense and taxes other than income are allocated to segments. All of the Company's operations are located within the United States.

75

(13) QUARTERLY RESULTS (UNAUDITED)

        The following is a summary of the quarterly results of operations for the years ended December 31, 2004 and 2003:

	Mar 31		June 30		Sept 30		Dec 31
	(in thousands, except per share amounts) 2004
Operating revenues	$	119,790	$	96,427	$	111,395	$	149,525
Operating income		43,307		38,246		45,437		55,297
Net income		24,472		20,790		25,399		32,915
Basic earnings per share		0.69		0.58		0.71		0.92
Diluted earnings per share		0.67		0.56		0.68		0.88
	2003
Operating revenues	$	98,655	$	66,487	$	71,068	$	91,191
Operating income		27,674		19,946		22,707		27,015
Net income		13,642		9,526		10,878		14,851
Basic earnings per share		0.48		0.27		0.31		0.42
Diluted earnings per share		0.47		0.26		0.30		0.41

(14) NEW ACCOUNTING STANDARDS

        In December 2004, the FASB issued Statement on Financial Accounting Standards No. 123 (Revised 2004), "Share-Based Payment," revising FASB Statement 123, "Accounting for Stock-Based Compensation" and superseding APB Opinion No. 25, "Accounting for Stock Issued to Employees." This statement requires a public entity to measure the cost of services provided by employees and directors received in exchange for an award of equity instruments, including stock options, at a grant-date fair value. The fair value cost is then recognized over the period that services are provided. FAS 123 (Revised 2004) is effective for interim and annual periods that begin after June 15, 2005 and will be adopted by the Company in the third quarter of 2005. See Note 1 of these financial statements for a disclosure of the effect on net income and earnings per share for the years 2002 through 2004 if the Company had applied the fair value recognition provisions of FAS 123 to stock-based employee compensation.

        The FASB issued Statement on Financial Accounting Standards No. 153, "Exchanges of Productive Assets," in December 2004 that amended APB Opinion No. 29, "Accounting for Nonmonetary Transactions." FAS 153 requires that nonmonetary exchanges of similar productive assets are to be accounted for at fair value. Previously these transactions were accounted for at book value of the assets. This statement is effective for nonmonetary transactions occurring in fiscal periods beginning after June 15, 2005. The Company does not expect this statement to have a material impact on it results of operations or its financial condition.

        In November 2004, the FASB issued Statement on Financial Accounting Standards No. 151, "Inventory Costs, an amendment of ARB No. 43, Chapter 4," which clarifies the types of costs that should be expensed rather than capitalized as inventory. The provisions of FAS 151 are effective for years beginning after June 15, 2005. The Company has not determined the impact, if any, that this statement will have on its results of operations or its financial condition.

76

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

        None.

ITEM 9A. CONTROLS AND PROCEDURES

We have performed an evaluation under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of our disclosure controls and procedures, as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934 (the Exchange Act).   Our disclosure controls and procedures are the controls and other procedures that we have designed to ensure that we record, process, summarize and report the information that is required to be disclosed or submitted by us within the time periods specified in the SEC's rules and forms. All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those determined to be effective can provide only a reasonable assurance with respect to financial statement preparation and presentation. Based on the evaluation, our management, including our Chief Executive Officer and Chief Financial Officer, concluded that our disclosure controls and procedures were effective as of December 31, 2004. There were no significant changes in our internal control over financial reporting during the three months ended December 31, 2004 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

        Management's Report on Internal Control Over Financial Reporting is included on page 52 of this Form 10-K.

ITEM 9B. OTHER INFORMATION

        There was no information required to be disclosed in a report on Form 8-K during the fourth quarter of the fiscal year ended December 31, 2004 that was not reported on such form.

77

PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

        The definitive Proxy Statement to holders of our common stock in connection with the solicitation of proxies to be used in voting at the Annual Meeting of Shareholders on May 11, 2005, or the 2005 Proxy Statement, is hereby incorporated by reference for the purpose of providing information about the identification of our directors, and for discussion of our audit committee financial expert. We refer you to the sections "Election of Directors" and "Share Ownership of Management, Directors and Nominees" in the 2005 Proxy Statement for information concerning our directors. We refer you to the section "Meetings and Committees of the Board of Directors" for discussion of our audit committee financial expert. Information concerning our executive officers is presented in Part I, Item 4 of this Form 10-K. We refer you to the section "Section 16(a), Beneficial Ownership Reporting Compliance" for information relating to compliance with Section 16(a) of the Exchange Act.

        The Company has adopted a code of ethics that applies to the Company's chief executive officer, chief financial officer and chief accounting officer. The full text of such code of ethics has been posted on the Company's website at www.swn.com, and is available free of charge in print to any shareholder who requests it. Requests for copies should be addressed to the Secretary at 2350 N. Sam Houston Parkway East, Suite 300, Houston TX, 77032.

ITEM 11. EXECUTIVE COMPENSATION

        The 2005 Proxy Statement is hereby incorporated by reference for the purpose of providing information about executive compensation. We refer you to the section "Executive Compensation" in the 2005 Proxy Statement.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

        The 2005 Proxy Statement is hereby incorporated by reference for the purpose of providing information about securities authorized for issuance under our equity compensation plans and security ownership of certain beneficial owners and our management. For information about our equity compensation plans, refer to "Equity Compensation Plans" in our 2005 Proxy Statement. Refer to the sections "Security Ownership of Certain Beneficial Owners" and "Share Ownership of Management, Directors and Nominees" for information about security ownership of certain beneficial owners and our management.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

        The 2005 Proxy Statement is hereby incorporated by reference for the purpose of providing information about certain relationships and related transactions. Refer to the sections "Certain Transactions," "Share Ownership of Management, Directors and Nominees," "Agreements Concerning Employment and Change in Control," "Pension Plans" and "Equity Compensation Plans" for information about transactions with our executive officers, directors or management.

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

        The 2005 Proxy Statement is hereby incorporated by reference for the purpose of providing information about fees paid to the principal accountant and the audit committee's pre-approval policies and procedures. We refer you to the section "Relationship with Independent Registered Public Accounting Firm" for information concerning fees paid to our principal accountant and the audit committee's pre-approval policies and procedures and other required information.

78

PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a) (1) The consolidated financial statements of Southwestern Energy Company and its subsidiaries and the report of independent auditors are included in Item 8 of this Form 10-K.

        (2) The consolidated financial statement schedules have been omitted because they are not required under the related instructions, or are not applicable.

        (3) The exhibits listed on the accompanying Exhibit Index are filed as part of, or incorporated by reference into, this Form 10-K.

79

SIGNATURES

        Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused the report to be signed on its behalf by the undersigned, thereunto duly authorized.

		SOUTHWESTERN ENERGY COMPANY
Dated:	March 8, 2005	BY:	/s/ Greg D. Kerley
			Greg D. Kerley
			Executive Vice President
			and Chief Financial Officer

        Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities indicated on March 8, 2005.

/s/ Harold M. Korell	Director, Chairman, President and Chief Executive Officer
Harold M. Korell
/s/ Greg D. Kerley	Executive Vice President and Chief Financial Officer
Greg D. Kerley
/s/ Stanley T. Wilson	Controller and Chief Accounting Officer
Stanley T. Wilson
/s/ Lewis E. Epley, Jr	Director
Lewis E. Epley, Jr
/s/ John Paul Hammerschmidt	Director
John Paul Hammerschmidt
/s/ Robert L. Howard	Director
Robert L. Howard
/s/ Vello A. Kuuskraa	Director
Vello A. Kuuskraa
/s/ Kenneth R. Mourton	Director
Kenneth R. Mourton
/s/ Charles E. Scharlau	Director
Charles E. Scharlau

80

EXHIBIT INDEX

Exhibit Number	Description
3.1	Amended and Restated By-Laws of Southwestern Energy Company. (Incorporated by reference to Exhibit 3.1 to the Registrant's Annual Report filed on Form 10-K (Commission File No. 1-08246) for the year ended December 31, 2002)
3.2	Amended and Restated Articles of Incorporation of Southwestern Energy Company. (Incorporated by reference to Exhibit 4.2 to the Registrant's Registration Statement on Form S-3 (File No. 333-101658) filed on December 5, 2002)
4.1	Form of Common Stock Certificate. (Incorporated by reference to Exhibit 4.1 to the Registrant's Form S-3 (File No. 333-101658)
4.2	Amended and Restated Rights Agreement between Southwestern Energy Company and the First Chicago Trust Company of New York dated April 12, 1999. (Incorporated by reference to Exhibit 4.1 to the Registrant's Annual Report on Form 10-K (Commission File No. 1-08246) for the year ended December 31, 1999)
4.3	Amendment No. 1 to the Amended and Restated Rights Agreement between Southwestern Energy Company and Equiserve Trust Company as successor to the First Chicago Trust Company of New York dated March 15, 2002. (Incorporated by reference to Exhibit 4.1 to the Registrant's Annual Report on Form 10-K (Commission File No. 1-08246) for the year ended December 31, 2001)
4.4	Indenture, dated as of December 1, 1995 between Southwestern Energy Company and The First National Bank of Chicago (now Bank One Trust Company, N.A.). (Incorporated by reference to Exhibit 4 to Amendment No. 1 to Registrant's Registration Statement on Form S-3 (File No. 33-63895) filed on November 17, 1995)
4.5*	Amended and Restated Credit Agreement dated January 4, 2005 among Southwestern Energy Company, JPMorgan Chase Bank, NA, SunTrust Bank, Royal Bank of Scotland, Royal Bank of Canada, Fleet National Bank, and the other lenders named therein, JPMorgan Chase Bank, NA, as administrative agent, SunTrust Bank as syndication agent.
10.1	Consulting Agreement between Southwestern Energy Company and Charles E. Scharlau, dated May 15, 2002. (Incorporated by reference to Exhibit 3.1 to Registrant's Annual Report on Form 10-K (Commission File No. 1-08246) for the year ended December 31, 2002)
10.2	Form of Indemnity Agreement between Southwestern Energy Company and each Executive Officer and Director of the Registrant. (Incorporated by reference to Exhibit 10.20 of the Registrant's Annual Report on Form 10-K (Commission File No. 1-08246) for the year ended December 31, 1991)
10.3	Form of Executive Severance Agreement between Southwestern Energy Company and each of the Executive Officers of Southwestern Energy Company, effective February 17, 1999. (Incorporated by reference to Exhibit 10.12 of the Registrant's Annual Report on Form 10-K (Commission File No. 1-08246) for the year ended December 31, 1998)
10.4	Southwestern Energy Company Incentive Compensation Plan. (Incorporated by reference to Exhibit 10.2(b) to the Registrant's Annual Report on Form 10-K (Commission File No. 1-08246) for the year ended December 31, 1998)
10.5	Southwestern Energy Company Supplemental Retirement Plan amended as of February 1, 1996. (Incorporated by reference to Exhibit 10.5 to the Registrant's Annual Report on Form 10-K (Commission File No. 1-08246) for the year ended December 31, 1995)
10.6	Southwestern Energy Company Supplemental Retirement Plan Trust, dated December 30, 1993. (Incorporated by reference to Exhibit 10.6 to the Registrant's Annual Report on Form 10-K (Commission File No. 1-08246) for the year ended December 31, 1993)
10.7	Southwestern Energy Company Non-Qualified Retirement Plan, effective October 4, 1995. (Incorporated by reference to Exhibit 10.7 to the Registrant's Annual Report on Form 10-K (Commission File No. 1-08246) for the year ended December 31, 1995)

81

10.8	Amended and Restated Limited Partnership Agreement of NOARK Pipeline System, Limited Partnership dated January 12, 1998. (Incorporated by reference to Exhibit 10.7 to the Registrant's Annual Report on Form 10-K (Commission File No. 1-08246) for the year ended December 31, 1997)
10.9	Amendment No. 1 to the Amended and Restated Limited Partnership Agreement of NOARK Pipeline System, Limited Partnership dated June 18, 1998. (Incorporated by reference to Exhibit 10.14 to the Registrant's Annual Report on Form 10-K (Commission File No. 1-08246) for the year ended December 31, 1998)
10.10	Southwestern Energy Company 1993 Stock Incentive Plan, dated April 7, 1993. (Incorporated by reference to Exhibit 10.4(e) to the Registrant's Annual Report on Form 10-K (Commission File No. 1-08246) for the year ended December 31, 1993)
10.11	Southwestern Energy Company 1993 Stock Incentive Plan for Outside Directors, dated April 7, 1993. (Incorporated by reference to Exhibit 10.4(f) to the Registrant's Annual Report on Form 10-K (Commission File No. 1-08246) for the year ended December 31, 1993)
10.12	Southwestern Energy Company 2000 Stock Incentive Plan dated February 18, 2000. (Incorporated by reference to the Appendix of the Registrant's Definitive Proxy Statement (Commission File No. 1-08246) for the 2000 Annual Meeting of Shareholders)
10.13	Southwestern Energy Company 2002 Employee Stock Incentive Plan, effective October 23, 2002. (Incorporated by reference to Exhibit 3.1 to Registrant's Annual Report on Form 10-K (Commission File No. 1-08246) for the year ended December 31, 2002)
10.14	Southwestern Energy Company 2002 Performance Unit Plan, effective December 11, 2002. (Incorporated by reference to Exhibit 3.1 to Registrant's Annual Report on Form 10-K (Commission File No. 1-08246) for the year ended December 31, 2002)
10.15	Southwestern Energy Company 2004 Stock Incentive Plan. (Incorporated by reference to Appendix A to the Company's Proxy Statement dated March 29, 2004)
10.16	Form of Incentive Stock Option Agreement. (Incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on December 20, 2004)
10.17	Form of Restricted Stock Agreement. (Incorporated by reference to Exhibit 10.3 to the Current Report on Form 8-K filed on December 20, 2004)
10.18	Form of Non-Qualified Stock Option Agreement for non-employee directors. (Incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K filed on December 20, 2004)
10.19*	Form of Non-Qualified Stock Option Agreement.
10.20	Description of Compensation Payable to Non-Management Directors. (Incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on March 2, 2005)
21.1*	List of Subsidiaries.
23.1*	Consent of PricewaterhouseCoopers LLP.
23.2*	Consent of Netherland, Sewell & Associates, Inc.
31.1*	Certification of CEO filed pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*	Certification of CFO filed pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32*	Certification of CEO and CFO furnished pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

____________

* Filed herewith

82

EX-4

2 5

AMENDED AND RESTATED CREDIT AGREEMENT


DATED AS OF JANUARY 4, 2005


AMONG


SOUTHWESTERN ENERGY COMPANY,


THE LENDERS,


JPMORGAN CHASE BANK, N.A.,
AS ADMINISTRATIVE AGENT,

SUNTRUST BANK,
AS SYNDICATION AGENT,

AND

ROYAL BANK OF CANADA,

FLEET NATIONAL BANK

AND

THE ROYAL BANK OF SCOTLAND, PLC,

AS CO-DOCUMENTATION AGENTS,

JPMORGAN SECURITIES, INC.
and
SUNTRUST ROBINSON HUMPHREY

(a division of SunTrust Capital Markets, Inc.)

CO-LEAD ARRANGERS AND JOINT BOOK RUNNERS

AMENDED AND RESTATED CREDIT AGREEMENT

            This Amended and Restated Credit Agreement, dated as of January 4, 2005 is among Southwestern Energy Company, the Lenders, JPMorgan Chase Bank, N.A., a national banking association, as Administrative Agent, SunTrust Bank, as Syndication Agent, and Royal Bank of Canada, Fleet National Bank and The Royal Bank of Scotland, plc, as Co-Documentation Agents. The parties hereto agree as follows:

ARTICLE I

DEFINITIONS

      1.1    Definitions. As used in this Agreement, the following terms have the respective meanings set forth below (such meanings to be equally applicable to both the singular and plural forms of the terms defined):

            "Administrative Agent" means JPMorgan in its capacity as administrative agent for the Lenders pursuant to Article X, and not in its individual capacity as a Lender, and any successor Administrative Agent appointed pursuant to Article X.

            "Administrative Questionnaire" means an administrative questionnaire, substantially in the form supplied by the Administrative Agent, completed by a Lender and furnished to the Administrative Agent in connection with this Agreement.

            "Advance" means a group of Revolving Loans (i) made by the Lenders on the same Borrowing Date or (ii) converted or continued by the Lenders on the same date of conversion or continuation and, in either case, consisting of Revolving Loans of the same Type and, in the case of Eurodollar Loans, for the same Interest Period.

            "Affected Lender" is defined in Section 2.19.

            "Affiliate" of any Person means any other Person directly or indirectly controlling, controlled by or under common control with such Person. A Person shall be deemed to control another Person if the controlling Person owns 10% or more of any class of voting securities (or other ownership interests) of the controlled Person or possesses, directly or indirectly, the power to direct or cause the direction of the management or policies of the controlled Person, whether through ownership of stock, by contract or otherwise.

            "Aggregate Commitment" means the aggregate amount of the Commitments of all the Lenders, as changed from time to time pursuant to the terms hereof.

            "Agreement" means this amended and restated credit agreement, as it may be amended or modified and in effect from time to time.

            "Agreement Accounting Principles" means generally accepted accounting principles as in effect from time to time; provided that if the Borrower notifies the Administrative Agent that the Borrower does not want to give effect to any change in generally accepted accounting principles (or if the Administrative Agent notifies the Borrower that the Required Lenders do not want to give effect to any such change), then Agreement Accounting Principles shall mean generally accepted accounting principles as in effect immediately before the relevant change in generally accepted accounting principles became effective, until either such notice is withdrawn or this Agreement is amended in a manner satisfactory to the Borrower and the Required Lenders.

            "Alternate Base Rate" means, for any day, a rate of interest per annum equal to the higher of (i) the Prime Rate for such day and (ii) the sum of the Federal Funds Effective Rate for such day plus 0.5% per annum.

            "Applicable Margin" means a rate per annum determined in accordance with Schedule 1B.

            "Arrangers" means J.P. Morgan Securities, Inc. and SunTrust Robinson Humphrey, a division of SunTrust Capital Markets, Inc., and "Arranger" means either of them.

            "Asset Sale" means any sale, lease, assignment for value or other disposition by the Borrower or any Subsidiary, excluding (i) sales and other dispositions in the ordinary course of business and (ii) any sale or other disposition of any asset listed on Schedule 2.8(a).

            "Authorized Officer" means any of the following officers of the Borrower, acting singly: the Chief Executive Officer, the President, the Chief Financial Officer, the Treasurer or any Executive Vice President, Senior Vice President or Vice President.

            "AWG" means Arkansas Western Gas Company.

            "Borrower" means Southwestern Energy Company, an Arkansas corporation, and its successors and assigns.

            "Borrowing Date" means a date on which an Advance or a Swing Line Loan is made hereunder.

            "Borrowing Notice" is defined in Section 2.4.

            "Business Day" means (i) with respect to any borrowing, payment or rate selection of Eurodollar Advances, a day (other than a Saturday or Sunday) on which banks generally are open in the cities of Chicago, Dallas and New York for the conduct of substantially all of their commercial lending activities, interbank wire transfers can be made on the Fedwire system and dealings in United States dollars are carried on in the London interbank market and (ii) for all other purposes, a day (other than a Saturday or Sunday) on which banks generally are open in the cities of Chicago, Dallas and New York for the conduct of substantially all of their commercial lending activities and interbank wire transfers can be made on the Fedwire system.

            "Capitalized Lease" of a Person means any lease of Property, except oil and gas leases, by such Person as lessee that would be capitalized on a balance sheet of such Person prepared in accordance with Agreement Accounting Principles.

            "Capitalized Lease Obligations" of a Person means the amount of the obligations of such Person under Capitalized Leases which would be shown as a liability on a balance sheet of such Person prepared in accordance with Agreement Accounting Principles.

            "Cash Equivalent Investments" means, at any time, (i) any evidence of Debt, maturing not more than one year after such time, issued or guaranteed by the United States Government or any agency thereof, (ii) commercial paper, maturing not more than one year from the date of issue, or corporate demand notes, in each case (unless issued by a Lender or its holding company) rated at least A-l by Standard & Poor's Ratings Group or P-l by Moody's Investors Service, Inc., (iii) any certificate of deposit (or time deposits represented by such certificates of deposit) or bankers acceptance, maturing not more than one year after such time, or overnight Federal Funds transactions that are issued or sold by a commercial banking institution that is a member of the Federal Reserve System and has a combined capital and surplus and undivided profits of not less than $500,000,000, (iv) any repurchase agreement entered into with any Lend er (or other commercial banking institution of the stature referred to in clause (iii)) which (a) is secured by a fully perfected security interest in any obligation of the type described in any of clauses (i) through (iii) and (b) has a market value at the time such repurchase agreement is entered into of not less than 100% of the repurchase obligation of such Lender (or other commercial banking institution) thereunder and (v) investments in short-term asset management accounts offered by any Lender for the purpose of investing in loans to any corporation (other than the Borrower or an Affiliate of the Borrower), state or municipality, in each case organized under the laws of any state of the United States or of the District of Columbia.

            "Change of Control" means that (i) any Person or group (within the meaning of Rule 13d-5 under the Securities Exchange Act of 1934, as amended) shall beneficially own, directly or indirectly, 25% or more of the common stock or other voting securities of the Borrower; or (ii) Continuing Directors shall fail to constitute a majority of the Board of Directors of the Borrower. For purposes of the foregoing, "Continuing Director" means an individual who (x) is a member of the Board of Directors of the Borrower on the date of this Agreement or (y) is nominated to be a member of such Board of Directors after the date hereof by a majority of the Continuing Directors then in office.

            "Code" means the Internal Revenue Code of 1986, as amended, reformed or otherwise modified from time to time.

            "Collateral Shortfall Amount" is defined in Section 8.1.

            "Commitment" means, for each Lender, the obligation of such Lender to make Revolving Loans, to issue or participate in Letters of Credit and to make or participate in Swing Line Loans, in an aggregate amount not exceeding the amount set forth (i) opposite such Lender's name on Schedule 1A, (ii) in any assignment that has become effective pursuant to Section 12.3.2, or (iii) in any increase letter or assumption letter that has become effective pursuant to Section 2.6.3, in each case as such amount may be adjusted from time to time pursuant to the terms hereof.

            "Commitment Fee Rate" means a rate per annum determined in accordance with Schedule 1B.

            "Contingent Obligation" of a Person means any agreement, undertaking or arrangement by which such Person assumes, guarantees, endorses, contingently agrees to purchase or provide funds for the payment of, or otherwise becomes or is contingently liable upon, the obligation or liability of any other Person, or agrees to maintain the net worth or working capital or other financial condition of any other Person, or otherwise assures any creditor of such other Person against loss, including any comfort letter, operating agreement, take or pay contract, application for a letter of credit or the obligations of any such Person as general partner of a partnership with respect to the liabilities of the partnership.

            "Conversion/Continuation Notice" is defined in Section 2.5.

            "Controlled Group" means all members of a controlled group of corporations or other business entities and all trades or businesses (whether or not incorporated) under common control which, together with the Borrower or any of its Subsidiaries, are treated as a single employer under Section 414 of the Code.

            "Credit Extension" means the making of an Advance or a Swing Line Loan or the issuance, or extension of the term or increase in the amount, of a Letter of Credit.

            "Debt to Capitalization Ratio" means the ratio of (i) Total Debt to (ii) the sum of Total Debt plus Stockholders' Equity.

            "Default" means an event described in Article VII.

            "Environmental Laws" means any and all federal, state, local and foreign statutes, laws, judicial decisions, regulations, ordinances, rules, judgments, orders, decrees, plans, injunctions, permits, concessions, grants, franchises, licenses, agreements and other governmental restrictions relating to (i) the protection of the environment, (ii) the effect of the environment on human health, (iii) emissions, discharges or releases of pollutants, contaminants, hazardous substances or wastes into surface water, ground water or land or (iv) the manufacture, processing, distribution, use, treatment, storage, disposal, transport or handling of pollutants, contaminants, hazardous substances or wastes or the clean-up or other remediation thereof.

            "Equity Issuance " means any issuance by the Borrower or any Subsidiary of any equity securities other than (i) pursuant to and in accordance with stock option plans or other benefit plans for directors, officers or employees of the Borrower or any Subsidiary, (ii) in connection with a merger, acquisition, joint venture, asset purchase or other investment by the Borrower or any Subsidiary permitted under this Agreement or (iii) any issuance by a Subsidiary to the Borrower or to another Subsidiary.

            "ERISA" means the Employee Retirement Income Security Act of 1974, as amended from time to time, and any rule or regulation issued thereunder.

            "Eurodollar Advance" means an Advance which, except as otherwise provided in Section 2.10, bears interest at the applicable Eurodollar Rate.

            "Eurodollar Base Rate" means, with respect to a Eurodollar Advance for the relevant Interest Period, the applicable British Bankers' Association Interest Settlement Rate for deposits in U.S. dollars as reported by any generally recognized financial information service as of 11:00 a.m. (London time) two Business Days prior to the first day of such Interest Period, and having a maturity equal to such Interest Period, provided that, if no such British Bankers' Association Interest Settlement Rate is available to the Administrative Agent, the applicable Eurodollar Base Rate for the relevant Interest Period shall instead be the rate determined by the Administrative Agent to be the rate at which JPMorgan or one of its Affiliate banks offers to place deposits in U.S. dollars with first-class banks in the London interbank market at approximately 11:00 a.m. (London time) two Business Days prior to the first day of such Interest Period, in the approximate amount of the relevant Eurodollar Loan and having a maturity equal to such Interest Period.

            "Eurodollar Loan" means a Revolving Loan which, except as otherwise provided in Section 2.10, bears interest at the applicable Eurodollar Rate.

            "Eurodollar Rate" means, with respect to a Eurodollar Advance for the relevant Interest Period, the sum of the Eurodollar Base Rate applicable to such Interest Period plus the Applicable Margin as in effect from time to time.

            "Excluded Taxes" means, in the case of each Lender or applicable Lending Installation and the Administrative Agent, taxes imposed on its overall net income, and franchise taxes imposed on it, by (i) the jurisdiction under the laws of which such Lender or the Administrative Agent is incorporated or organized or (ii) the jurisdiction in which the Administrative Agent's or such Lender's principal executive office or such Lender's applicable Lending Installation is located.

            "Existing Agreement" means the Credit Agreement dated as of January 2, 2004 among the Borrower, various lenders and JPMorgan (as successor to Bank One, NA), as administrative agent.

            "Existing Letter of Credit" means letter of credit number 00344160 issued by JPMorgan (as successor to Bank One, NA) in the stated amount of $3,000.00 and with a stated expiry of December 18, 2005 issued in favor of the Arkansas Oil and Gas Commission under the Existing Agreement.

            "Facility" is defined in Section 9.11(b).

            "Federal Funds Effective Rate" means, for any day, an interest rate per annum equal to the weighted average of the rates on overnight Federal funds transactions with members of the Federal Reserve System arranged by Federal funds brokers on such day, as published for such day (or, if such day is not a Business Day, for the immediately preceding Business Day) by the Federal Reserve Bank of New York, or, if such rate is not so published for any day which is a Business Day, the average of the quotations at approximately 11:00 a.m. on such day on such transactions received by the Administrative Agent from three Federal funds brokers of recognized standing selected by the Administrative Agent in its sole discretion.

            "Floating Rate" means, for any day, a rate per annum equal to the Alternate Base Rate for such day, changing when and as the Alternate Base Rate changes, plus the Applicable Margin as in effect on such day.

            "Floating Rate Advance" means an Advance which, except as otherwise provided in Section 2.10, bears interest at the Floating Rate.

            "Floating Rate Loan" means a Revolving Loan which, except as otherwise provided in Section 2.10, bears interest at the Floating Rate.

            "Guarantor" means each Subsidiary which is a party to the Subsidiary Guaranty.

            "Indebtedness" of a Person means such Person's (i) obligations for borrowed money, (ii) obligations representing the deferred purchase price of Property or services, (iii) obligations, whether or not assumed, secured by Liens or payable out of the proceeds or production from Property now or hereafter owned or acquired by such Person, (iv) obligations which are evidenced by notes, acceptances, or other instruments, (v) obligations of such Person to purchase accounts, securities or other Property arising out of or in connection with the sale of the same or substantially similar accounts, securities or Property, (vi) Capitalized Lease Obligations, (vii) any other obligation for borrowed money or other financial accommodation which in accordance with Agreement Accounting Principles would be shown as a liability on the consolidated balance sheet of such Person, (viii) net liabilities under interest rate swap, exchange or cap a greements, obligations or other liabilities with respect to accounts or notes, (i) Sale and Leaseback Transactions which do not create a liability on the consolidated balance sheet of such Person, (ix) other transactions which are the functional equivalent, or take the place, of borrowing but which do not constitute a liability on the consolidated balance sheet of such Person, (x) Contingent Obligations and (xi) Mandatorily Redeemable Stock; provided that, notwithstanding any of the foregoing, accounts payable arising in the ordinary course of business payable on terms customary in the trade, and Contingent Obligations in respect thereof, shall not constitute Indebtedness; and provided, further, that Indebtedness shall not include accounts payable which the Borrower is required to reflect on its balance sheet in accordance with Agreement Accounting Principles to the extent that (a) such accounts payable consist solely of contingent obligations under oil and gas hedge transactions for fut ure periods and (b) as of any date of calculation thereof, the volume of oil and gas subject to such hedge transactions is not greater than 90% of the Borrower's anticipated production from proved, producing, oil and gas reserves owned by the Borrower and its Subsidiaries as of such date over the term covered by such hedge transactions.

            "Interest Coverage Ratio" means, for any period of four fiscal quarters of the Borrower ending on the last day of a fiscal quarter, the ratio of (i) the sum of (a) the Borrower's consolidated net income before interest, taxes, depreciation and amortization of non-cash charges, all determined on a consolidated basis and in accordance with Agreement Accounting Principles for such period, but excluding, to the extent otherwise included therein, any non-cash gain or loss on any hedging agreement resulting from the requirements of SFAS 133, plus (b) to the extent deducted in determining such consolidated net income, any non-cash charge after the date hereof resulting from any write-down of the Borrower's oil and gas properties to the full cost ceiling limitation required by the full cost method of accounting for such properties, to (ii) the Borrower's interest expense for such period.

            "Interest Period" means, with respect to a Eurodollar Advance, a period of one, two, three or six months commencing on a Business Day selected by the Borrower pursuant to this Agreement. Such Interest Period shall end on the day which corresponds numerically to such date one, two, three or six months thereafter, provided that if there is no such numerically corresponding day in such next, second, third or sixth succeeding month, such Interest Period shall end on the last Business Day of such next, second, third or sixth succeeding month. If an Interest Period would otherwise end on a day which is not a Business Day, such Interest Period shall end on the next succeeding Business Day, provided that if said next succeeding Business Day falls in a new calendar month, such Interest Period shall end on the immediately preceding Business Day. Notwithstanding any other provision of this Agreement, the Borrower may n ot select any Interest Period that would end after the scheduled Termination Date.

            "Investment" of a Person means any loan, advance (other than commission, travel and similar advances to officers and employees made in the ordinary course of business), extension of credit (other than accounts receivable arising in the ordinary course of business on terms customary in the trade) or contribution of capital by such Person; stocks, bonds, mutual funds, partnership interests, notes, debentures or other securities owned by such Person; any deposit accounts and certificate of deposit owned by such Person; and structured notes, derivative financial instruments and other similar instruments or contracts owned by such Person.

            "Issuer" means JPMorgan, in its capacity as the issuer of Letters of Credit, and its successors in such capacity.

            "JPMorgan" means JPMorgan Chase Bank, N.A., a national banking association, in its individual capacity, and its successors.

            "Knowledge" means, with respect to the Borrower, the actual knowledge of (i) any Authorized Officer, (ii) any vice president of the Borrower in charge of a principal business unit, division or function (such as sales, administration or finance), (iii) any other officer who performs a policy making function or (iv) any other person who performs similar policy making functions for the Borrower.

            "LC Application" means, with respect to the issuance or modification of any Letter of Credit, the customary form for the issuance or modification, as the case may be, of letters of credit used by the Issuer from time to time in the normal course of its business or such other form as may be agreed to by the Borrower and the Issuer.

            "LC Collateral Account" is defined in Section 2.20.11.

            "LC Fee Rate" means a rate per annum determined in accordance with Schedule 1B.

            "LC Obligations" means, at any time, the sum, without duplication, of (i) the aggregate Stated Amount of all outstanding Letters of Credit at such time plus (ii) the aggregate amount of all Reimbursement Obligations at such time.

            "Lenders" means the lending institutions from time to time party to this Agreement and their respective successors and assigns. Unless otherwise specified, the term "Lenders" includes JPMorgan in its capacity as Issuer and Swing Line Lender.

            "Lending Installation" means, with respect to a Lender or the Administrative Agent, the office, branch, subsidiary or affiliate of such Lender or the Administrative Agent listed on its Administrative Questionnaire, in the assignment agreement pursuant to which it became a Lender or otherwise designated pursuant to Section 2.17.

            "Letter of Credit" is defined in Section 2.20.1.

            "Lien" means any lien (statutory or other), mortgage, pledge, hypothecation, assignment, deposit arrangement, encumbrance or other security arrangement (including the interest of a vendor or lessor under any conditional sale, Capitalized Lease or other title retention agreement).

            "Loan" means a Revolving Loan or a Swing Line Loan.

            "Loan Documents" means this Agreement, any Note, the Subsidiary Guaranty, any Letter of Credit and any LC Application.

            "Mandatorily Redeemable Stock" means, with respect to any Person, any share of such Person's capital stock or other equity interest to the extent that it is (i) redeemable, payable or required to be purchased or otherwise retired or extinguished, or convertible into any Indebtedness or other liability of such Person, (a) at a fixed or determinable date, whether by operation of a sinking fund or otherwise, (b) at the option of any Person other than such Person or (c) upon the occurrence of a condition not solely within the control of such Person, such as a redemption required to be made out of future earnings or (ii) convertible into Mandatorily Redeemable Stock.

            "Margin Stock" has the meaning given thereto in Regulation U.

            "Material Adverse Effect" means a material adverse effect on (i) the business, Property, condition (financial or otherwise) or results of operations of the Borrower and its Subsidiaries taken as a whole, (ii) the prospect that the Borrower will have the ability to fully and timely pay the Obligations or (iii) the validity or enforceability of any of the Loan Documents or the rights or remedies of the Administrative Agent or the Lenders thereunder.

            "Material Group of Subsidiaries" means two or more Subsidiaries which, if merged as of any relevant date of determination, would constitute a Material Subsidiary.

            "Material Subsidiary" means, as of any date of determination, each Subsidiary of the Borrower that:

                    (i)    has assets with a book value representing more than 10% of the book value of the consolidated assets of the Borrower and its Subsidiaries as of the end of the fiscal quarter ended immediately prior to such date of determination; and

                   (ii)     is responsible for more than 10% of the consolidated revenues of the Borrower and its Subsidiaries as reflected in the consolidated financial statements of the Borrower and its Subsidiaries for the four fiscal quarters immediately preceding such date of determination;

provided that each such determination of such assets or revenues shall be made after deducting all intercompany transactions which, in accordance with Agreement Accounting Principles, would be eliminated in preparing consolidated financial statements for the Borrower and its Subsidiaries.

            "Modification" and "Modify" are defined in Section 2.20.1.

            "Multiemployer Plan" means a Plan maintained pursuant to a collective bargaining agreement or any other arrangement to which the Borrower or any member of the Controlled Group is a party to which more than one employer is obligated to make contributions.

            "Non-U.S. Lender" is defined in Section 3.5(iv).

            "Note" means a promissory note, substantially in the form of Exhibit E, issued at the request of a Lender pursuant to Section 2.13.

            "Obligations" means all unpaid principal of and accrued and unpaid interest on the Loans, all Reimbursement Obligations, all accrued and unpaid fees and all expenses, reimbursements, indemnities and other obligations of the Borrower to any Lender, the Issuer, the Swing Line Lender, the Administrative Agent or any other indemnified party arising under the Loan Documents.

            "Other Taxes" is defined in Section 3.5(ii).

            "Participants" is defined in Section 12.2.1.

            "Payment Date" means the last day of each March, June, September and December.

            "PBGC" means the Pension Benefit Guaranty Corporation, or any successor thereto.

            "Person" means any natural person, corporation, firm, joint venture, partnership, limited liability company, association, enterprise, trust or other entity or organization, or any government or political subdivision or any agency, department or instrumentality thereof.

            "Plan" means an employee pension benefit plan which is covered by Title IV of ERISA or subject to the minimum funding standards under Section 412 of the Code as to which the Borrower or any member of the Controlled Group may have any liability.

            "Prime Rate" means a rate per annum equal to the prime rate of interest announced by JPMorgan or its parent, which is not necessarily the lowest rate charged to any customer, changing when and as said prime rate changes.

            "Principal Transmission Facility" means any transportation or distribution facility, including pipelines, of the Borrower or any Subsidiary located in the United States of America other than (i) any such facility which in the opinion of the Board of Directors of the Borrower is not of material importance to the business conducted by the Borrower and its Subsidiaries taken as a whole, or (ii) any such facility in which interests are held by the Borrower or by one or more Subsidiaries or by the Borrower and one or more Subsidiaries and by others and the aggregate interest held by the Borrower and all Subsidiaries does not exceed 50%.

            "Productive Property" means any property interest owned by the Borrower or a Subsidiary in land (including submerged land and rights in and to oil, gas and mineral leases) located in the United States of America and classified by the Borrower or such Subsidiary, as the case may be, as productive of crude oil, natural gas or other petroleum hydrocarbons in paying quantities; provided that such term shall not include any exploration or production facilities on said land, including any drilling or producing platform.

            "Property" of a Person means any and all property, whether real, personal, tangible, intangible, or mixed, of such Person, or other assets owned, leased or operated by such Person.

            "Pro Rata Share" means, with respect to any Lender, the percentage which the amount of such Lender's Commitment is of the Aggregate Commitment (or, if the Commitments have been terminated, the percentage which the sum of the principal amount of such Lender's Revolving Loans plus such Lender's participation interest in all Letters of Credit and Swing Line Loans is of the Total Outstandings).

            "Purchasers" is defined in Section 12.3.1.

            "Regulation D" means Regulation D of the Board of Governors of the Federal Reserve System as from time to time in effect and any successor thereto or other regulation or official interpretation of said Board of Governors relating to reserve requirements applicable to member banks of the Federal Reserve System.

            "Regulation U" means Regulation U of the Board of Governors of the Federal Reserve System as from time to time in effect and any successor or other regulation or official interpretation of said Board of Governors relating to the extension of credit by banks for the purpose of purchasing or carrying Margin Stock applicable to member banks of the Federal Reserve System.

            "Reimbursement Obligation" means any unpaid obligation of the Borrower to reimburse the Issuer for a payment made by the Issuer under a Letter of Credit.

            "Reportable Event" means a reportable event as defined in Section 4043 of ERISA and the regulations issued under such section, with respect to a Plan, excluding, however, such events as to which the PBGC has by regulation waived the requirement of Section 4043(a) of ERISA that it be notified within 30 days of the occurrence of such event, provided that a failure to meet the minimum funding standard of Section 412 of the Code and of Section 302 of ERISA shall be a Reportable Event regardless of the issuance of any such waiver of the notice requirement in accordance with either Section 4043(a) of ERISA or Section 412(d) of the Code.

            "Required Lenders" means Lenders in the aggregate having more than 50% of the Aggregate Commitment or, if the Aggregate Commitment has been terminated, Lenders in the aggregate holding more than 50% of the Total Outstandings.

            "Reserve Requirement" means, with respect to an Interest Period, the daily average during such Interest Period of the maximum aggregate reserve requirement (including all basic, supplemental, marginal and other reserves) which is imposed under Regulation D on Eurocurrency liabilities.

            "Revolving Loan" is defined in Section 2.1.

            "Sale and Leaseback Transaction" means any sale or other transfer of Property by any Person with the intent to lease such Property as lessee.

            "SEC" means the Securities and Exchange Commission.

            "Single Employer Plan" means a Plan maintained by the Borrower or any member of the Controlled Group for employees of the Borrower or any member of the Controlled Group.

            "Stated Amount" means, with respect to any Letter of Credit at any time, the maximum amount available to be drawn under such Letter of Credit at or after such time under any and all circumstances.

            "Stockholders' Equity" means the Borrower's stockholders' equity, determined in accordance with Agreement Accounting Principles, but without giving effect to (1) any non-cash charge after the date hereof resulting from any write-down of the Borrower's oil and gas properties to the full cost ceiling limitations required by the full cost method of accounting for such properties and (ii) any non-cash gain or loss on any hedging agreement resulting from the requirements of SFAS 133.

            "Subsidiary" of a Person means (i) any corporation more than 50% of the outstanding securities having ordinary voting power of which shall at the time be owned or controlled, directly or indirectly, by such Person or by one or more of its Subsidiaries or by such Person and one or more of its Subsidiaries, or (ii) any partnership, limited liability company, association, joint venture or similar business organization more than 50% of the ownership interests having ordinary voting power of which shall at the time be so owned or controlled. Unless otherwise expressly provided, all references herein to a "Subsidiary" shall mean a Subsidiary of the Borrower.

            "Subsidiary Guaranty" means the Amended and Restated Subsidiary Guaranty executed by various Subsidiaries in favor of the Administrative Agent, for the ratable benefit of the Lenders, substantially in the form of Exhibit F.

            "Swing Line Lender" means JPMorgan and its successors in its capacity as a swing line lender hereunder.

            "Swing Line Loan" - see Section_2.21.1.

            "Swing Line Loan Notice" - see Section 2.21.2.

            "Taxes" means any and all present or future taxes, duties, levies, imposts, deductions, charges or withholdings, and any and all liabilities with respect to the foregoing, but excluding Excluded Taxes and Other Taxes.

            "Termination Date" means January 4, 2010 or such earlier date when the Aggregate Commitment has been reduced to zero.

            "Total Debt" means all Indebtedness of the Borrower and its Subsidiaries, determined on a consolidated basis in accordance with Agreement Accounting Principles.

            "Total Outstandings" means, at any time, the sum at such time of the aggregate principal amount of all Loans plus the LC Obligations.

            "Transferee" is defined in Section 12.4.

            "Type" means, with respect to any Advance, its nature as a Floating Rate Advance or a Eurodollar Advance.

            "Unmatured Default" means an event which but for the lapse of any requisite time period or the giving of any requisite notice, or both, would, unless cured or waived, constitute a Default.

            "Wholly-Owned Subsidiary" of a Person means (i) any Subsidiary all of the outstanding voting securities of which shall at the time be owned or controlled, directly or indirectly, by such Person or one or more Wholly-Owned Subsidiaries of such Person, or by such Person and one or more Wholly-Owned Subsidiaries of such Person, or (ii) any partnership, limited liability company, association, joint venture or similar business organization 100% of the ownership interests having ordinary voting power of which shall at the time be so owned or controlled.

           1.2    Other Interpretive Provisions. In this Agreement, (a) in the computation of periods of time from a specified date to a later specified date, the word "from" means "from and including" and the words "to" and "until" each means "to but excluding"; (b) unless otherwise indicated, any reference to a time of day shall mean such time of day in New York City, New York; (c) unless otherwise indicated, any reference to an Article, Section, Exhibit or Schedule means an Article or Section hereof or an Exhibit or Schedule hereto; and (d) the term "including" means "including without limitation".

ARTICLE II

THE CREDITS

           2.1    Commitments. From the date of this Agreement to the Termination Date, (a) each Lender severally agrees, on the terms and conditions set forth in this Agreement, to make loans (each a "Revolving Loan") to the Borrower from time to time in an amount equal to its Pro Rata Share of all Revolving Loans requested by the Borrower, (b) the Issuer agrees to issue Letters of Credit for the account of the Borrower from time to time in an aggregate amount not at any time exceeding $20,000,000 (and each Lender severally agrees to participate in each such Letter of Credit as more fully set forth in Section 2.20) and (c) the Swing Line Lender agrees to make Swing Line Loans to the Borrower from time to time in an aggregate amount not at any time exceeding $20,000,000 (and each Lender severally agrees to participate in each such Swing Line Loan as more fully set forth in Section 2.21.3); provide d that the Total Outstandings shall not at any time exceed the Aggregate Commitment. Subject to the terms of this Agreement, the Borrower may borrow, repay and reborrow Revolving Loans at any time prior to the Termination Date.

           2.2    Types of Advances. Advances may be Floating Rate Advances or Eurodollar Advances, or a combination thereof, as selected by the Borrower in accordance with Sections 2.4 and 2.5.

           2.3    Minimum Amount of Each Advance. Each Eurodollar Advance shall be in the amount of $1,000,000 or a higher integral multiple thereof and each Floating Rate Advance shall be in the amount of $1,000,000 or a higher integral multiple of $500,000, provided that (a) any Floating Rate Advance made (in whole or in part) to repay any Reimbursement Obligations or any Swing Line Loan may be in the amount of $100,000 or an integral multiple thereof; and (b) any Floating Rate Advance may be in the amount of the unused Aggregate Commitment.

           2.4    Method of Selecting Types and Interest Periods for New Advances. The Borrower shall select the Type of Advance and, in the case of each Eurodollar Advance, the Interest Period applicable thereto from time to time. The Borrower shall give the Administrative Agent irrevocable notice (a "Borrowing Notice") not later than 11:00 a.m. on the Borrowing Date of each Floating Rate Advance and three Business Days before the Borrowing Date of each Eurodollar Advance, specifying:

            (i)    the Borrowing Date, which shall be a Business Day, of such Advance,

           (ii)    the aggregate amount of such Advance,

          (iii)    the Type of Advance selected, and

          (iv)    in the case of a Eurodollar Advance, the Interest Period applicable thereto.

Each Borrowing Notice shall be in writing (or by telephone promptly confirmed in writing) substantially in the form of Exhibit A. Not later than 1:00 p.m. on the Borrowing Date for an Advance, each Lender shall make available its Pro Rata Share of such Advance in funds immediately available in Chicago to the Administrative Agent at its address specified pursuant to Article XIII. The Administrative Agent will make the funds so received from the Lenders available to the Borrower at the Administrative Agent's aforesaid address.

           2.5    Conversion and Continuation of Outstanding Advances. Floating Rate Advances shall continue as Floating Rate Advances unless and until such Floating Rate Advances are converted into Eurodollar Advances pursuant to this Section 2.5 or are repaid. Each Eurodollar Advance shall continue as a Eurodollar Advance, until the end of the then applicable Interest Period therefor, at which time such Eurodollar Advance shall be automatically converted into a Floating Rate Advance unless (x) such Advance is or was repaid or (y) the Borrower shall have given the Administrative Agent a Conversion/Continuation Notice requesting that, at the end of such Interest Period, such Advance continue as a Eurodollar Advance for the same or another Interest Period. Subject to the terms of Section 2.3, the Borrower may elect from time to time to convert all or any part of any Advance into an Advance of the other Type. The Borrower shall give the Administrative Agent irrevocable notice (a "Conversion/Continuation Notice") of each continuation or conversion of an Advance (other than an automatic continuation or conversion as provided in this Section 2.5) not later than the time specified in Section 2.4 for the making of the Type of Advance to be continued or converted into, specifying:

           (i)    the requested date, which shall be a Business Day, of such conversion or continuation;

          (ii)    the aggregate amount and Type of the Advance which is to be converted or continued;

          (iii)    in the case of conversion of an Advance, the Type of Advance to be converted into;

          (iv)   the amount of the Advance which is to be converted or continued; and

          (v)    in the case of conversion into or continuation of a Eurodollar Advance, the duration of the Interest Period applicable thereto.

            Each Conversion/Continuation Notice given by the Borrower shall constitute a representation and warranty by the Borrower that no Default or Unmatured Default exists.

           2.6         Commitment Fee; Voluntary Changes in Aggregate Commitment.

           2.6.1          The Borrower agrees to pay to the Administrative Agent for the account of each Lender a commitment fee at a per annum rate equal to the Commitment Fee Rate on the daily unused portion of such Lender's Commitment from the date hereof to the Termination Date, payable on each Payment Date hereafter and on the Termination Date. For purposes of calculating utilization under this subsection, the Commitments shall be deemed used to the extent of the principal amount of Revolving Loans then outstanding (excluding any outstanding Swing Line Loans), plus the L/C Obligations then outstanding.

           2.6.2         The Borrower may permanently reduce the Aggregate Commitment in whole, or in part ratably among the Lenders in accordance with their respective Pro Rata Shares, in integral multiples of $1,000,000, upon at least three Business Days' written notice to the Administrative Agent, which notice shall specify the amount of any such reduction, provided that the amount of the Aggregate Commitment may not be reduced below the Total Outstandings. All accrued commitment fees shall be payable on the effective date of any termination of the obligations of the Lenders to make Revolving Loans hereunder.

            2.6.3        The Borrower may, from time to time, by means of a letter delivered to the Administrative Agent substantially in the form of Exhibit H, request that the Aggregate Commitment be increased by up to $50,000,000 in the aggregate by (i) increasing the Commitment of one or more Lenders which have agreed to such increase in their sole and absolute discretion and/or (ii) adding one or more commercial banks or other Persons as a party hereto (each an "Additional Lender") with a Commitment in an amount agreed to by any such Additional Lender; provided that no Additional Lender shall be added as a party hereto without the written consent of the Administrative Agent, the Issuer and the Swing Line Lender (which consents shall not be unreasonably withheld or delayed) or if an Unmatured Default or a Default exists. Any increase in the Aggregate Commitment pursuant to this Secti on 2.6.3 shall be effective three Business Days after the date on which the Administrative Agent, the Issuer and the Swing Line Lender have approved the applicable increase letter in the form of Annex 1 to Exhibit H (in the case of an increase in the Commitment of an existing Lender) or assumption letter in the form of Annex 2 to Exhibit H (in the case of the addition of a commercial bank or other Person as a new Lender). The Administrative Agent shall promptly notify the Borrower and the Lenders of any increase in the amount of the Aggregate Commitment pursuant to this Section 2.6.3 and of the Commitment of each Lender after giving effect thereto. The parties hereto agree that, notwithstanding any other provision of this Agreement, the Administrative Agent, the Borrower, each Additional Lender and each increasing Lender, as applicable, may make arrangements satisfactory to such parties to cause an Additional Lender or an increasing Lender to temporarily hold risk participations in t he outstanding Advances of the other Lenders (rather than fund its Percentage of all outstanding Loans concurrently with the applicable increase) with a view toward minimizing breakage costs and transfers of funds in connection with any increase in the Aggregate Commitment. The Borrower acknowledges that if, as a result of a non-pro-rata increase in the Aggregate Commitment, any Eurodollar Loans are prepaid or converted (in whole or in part) on a day other than the last day of an Interest Period therefor, then such prepayment or conversion shall be subject to the provisions of Section 3.4.

            2.7            Mandatory Reduction of the Aggregate Commitment. On any date on which a Change of Control occurs, the Aggregate Commitment shall be immediately reduced to zero.

            2.8            Prepayments. (a) The Borrower may from time to time prepay, without penalty or premium, all outstanding Floating Rate Advances or, in an aggregate amount of $1,000,000 or a higher integral multiple of $500,000 (or, in the case of any prepayment of a Floating Rate Advance made to repay Reimbursement Obligations, in such other amount as is necessary to repay such Advance in full), any portion of the outstanding Floating Rate Advances upon notice to the Administrative Agent not later than 11:00 a.m. on the date of prepayment. The Borrower may from time to time prepay, without penalty or premium, all outstanding Eurodollar Advances or, in an aggregate amount of $1,000,000 or a higher integral multiple thereof, any portion of the outstanding Eurodollar Advances upon three Business Days' prior notice to the Administrative Agent.

            (b)            On any date on which the Aggregate Commitment is reduced pursuant to Section 2.7, the Borrower shall prepay all Revolving Loans.

            (c)            Any prepayment of a Eurodollar Loan on a day other than the last day of an Interest Period therefor shall be subject to Section 3.4.

            (d)            The Borrower may, upon notice to the Swing Line Lender (with a copy to the Administrative Agent), at any time or from time to time, voluntarily prepay Swing Line Loans in whole or in part without premium or penalty; provided that (i) such notice must be received by the Swing Line Lender and the Administrative Agent not later than noon on the date of the prepayment, and (ii) any such prepayment shall be in a principal amount which is an integral multiple of $100,000 (except that, if at any time Swing Line Loans are made in an amount which is not an integral multiple of $100,000 upon delivery of by the Swing Line Lender of a Swing Line Loan Notice as contemplated by Section 2.21.2, the next prepayment of Swing Line Loans shall be in an amount so that the outstanding principal amount of all Swing Line Loans is either (x) zero or (y) an integral mu ltiple of $100,000). Each such notice shall specify the date and amount of such prepayment. If such notice is given by the Borrower, the Borrower shall make such prepayment and the payment amount specified in such notice shall be due and payable on the date specified therein.

            2.9            Interest Rates, etc. Each Floating Rate Advance shall bear interest on the outstanding principal amount thereof, for each day from the date such Advance is made or is converted from a Eurodollar Advance into a Floating Rate Advance pursuant to Section 2.5 to the date it is paid or is converted into a Eurodollar Advance pursuant to Section 2.5, at a rate per annum equal to the Floating Rate for such day. Each Swing Line Loan shall bear interest on the outstanding principal amount thereof for each day from the applicable borrowing date at a rate per annum equal to the Floating Rate for such day or, so long as the Lenders have not been required to fund their participations in such Swing Ling Loan pursuant to Section 2.21.3(b), such other rate as is agreed to in writing by the Swing Line Lender and the Borrower. Changes in the rate of interest on Floating Rate Advances will take effect simultaneously with each change in the Alternate Base Rate. Each Eurodollar Advance shall bear interest on the outstanding principal amount thereof from the first day of each Interest Period applicable thereto to the last day of such Interest Period at the interest rate determined by the Administrative Agent as applicable to such Eurodollar Advance based upon the Borrower's selections under Sections 2.4 and 2.5 and otherwise in accordance with the terms hereof.

            2.10            Rates Applicable After Default. Notwithstanding anything to the contrary herein, during the existence of a Default or Unmatured Default, the Required Lenders may, at their option, by notice to the Borrower (which notice may be revoked at the option of the Required Lenders notwithstanding any provision of Section 8.2 requiring unanimous consent of the Lenders to changes in interest rates), declare that no Advance may be made as, converted into or continued as a Eurodollar Advance. During the existence of a Default, the Required Lenders may, at their option, by notice to the Borrower (which notice may be revoked at the option of the Required Lenders notwithstanding any provision of Section 8.2 requiring unanimous consent of the Lenders to changes in interest rates), declare that (i) each Eurodollar Advance shall bear interest for the rema inder of the applicable Interest Period at the rate otherwise applicable to such Interest Period plus 2% per annum and (ii) each Floating Rate Advance and Swing Line Loan shall bear interest at a rate per annum equal to the Floating Rate in effect from time to time plus 2% per annum, provided that, during the existence of a Default under Section 7.1.6 or 7.1.7, the interest rates set forth in clauses (i) and (ii) above shall be applicable to all Advances and Swing Line Loans without any election or action on the part of the Administrative Agent or any Lender.

            2.11            Maturity. Any outstanding Advances and all other accrued and unpaid Obligations shall be paid in full by the Borrower on the scheduled Termination Date or such earlier date required by Section 2.7 or Section 8.1.

            2.12            Method of Payment. All payments of the Obligations hereunder shall be made, without setoff, deduction, or counterclaim, in immediately available funds to the Administrative Agent at the Administrative Agent's address specified pursuant to Article XIII, or at any other Lending Installation of the Administrative Agent specified in writing by the Administrative Agent to the Borrower, by 1:00 p.m. on the date when due and (except as otherwise specifically required hereunder) shall be applied ratably by the Administrative Agent among the Lenders in accordance with their respective Pro Rata Shares. Each payment delivered to the Administrative Agent for the account of any Lender shall be delivered promptly by the Administrative Agent to such Lender in the same type of funds that the Administrative Agent received at its address specified pursuant to < U>Article XIII or at any Lending Installation specified in a notice received by the Administrative Agent from such Lender. The Administrative Agent is hereby authorized to charge the account of the Borrower maintained with JPMorgan for each payment of principal, interest and fees as it becomes due hereunder.

            2.13            Noteless Agreement; Evidence of Indebtedness. (i)  Each Lender shall maintain in accordance with its usual practice an account or accounts evidencing the indebtedness of the Borrower to such Lender resulting from each Loan made by such Lender from time to time, including the amounts of principal and interest payable and paid to such Lender from time to time hereunder.

            (ii)               The Administrative Agent shall also maintain accounts in which it will record (a) the amount of each Loan made hereunder, the Type thereof and, if applicable, each Interest Period with respect thereto, (b) the amount of any principal or interest due and payable or to become due and payable from the Borrower to each Lender hereunder, (c) the Stated Amount of each Letter of Credit and the amount of all Reimbursement Obligations and (d) the amount of any sum received by the Administrative Agent hereunder from the Borrower and each Lender's share thereof.

            (iii)             The entries maintained in the accounts maintained pursuant to subsections (i) and (ii) above shall be prima facie evidence of the existence and amounts of the Obligations therein recorded; provided that the failure of the Administrative Agent or any Lender to maintain such accounts or any error therein shall not in any manner affect the obligation of the Borrower to repay the Obligations in accordance with their terms.

            (iv)            Any Lender may request that its Loans be evidenced by a Note. In such event, the Borrower shall prepare, execute and deliver to such Lender a Note payable to the order of such Lender. Thereafter, the Loans evidenced by such Note and interest thereon shall at all times (including after any assignment pursuant to Section 12.3) be represented by one or more Notes payable to the order of the payee named therein or any assignee pursuant to Section 12.3, except to the extent that any such Lender or assignee subsequently returns any such Note for cancellation and requests that such Loans once again be evidenced as described in subsections (i) and (ii) above.

            2.14            Telephonic Notices. The Borrower hereby authorizes the Lenders and the Administrative Agent to extend, convert or continue Loans and/or Advances, to effect selections of Types of Advances and to transfer funds based on telephonic notices made by any person or persons the Administrative Agent or any Lender in good faith believes to be acting on behalf of the Borrower, it being understood that the foregoing authorization is specifically intended to allow Borrowing Notices and Conversion/Continuation Notices to be given telephonically. The Borrower agrees to deliver promptly to the Administrative Agent a written confirmation, if such confirmation is requested by the Administrative Agent or any Lender, of each telephonic notice signed by an Authorized Officer. If the written confirmation differs in any material respect from the action taken by the Admini strative Agent and the Lenders, the records of the Administrative Agent and the Lenders shall govern absent manifest error.

            2.15            Interest Payment Dates; Interest and Fee Basis. Interest accrued on each Floating Rate Advance and on each Swing Line Loan shall be payable on each Payment Date, and at maturity (whether due to acceleration or otherwise). Interest accrued on each Eurodollar Advance shall be payable on the last day of each applicable Interest Period, on any date on which such Advance is prepaid or is converted into a Floating Rate Advance and at maturity (whether due to acceleration or otherwise). Interest accrued on each Eurodollar Advance having an Interest Period longer than three months shall also be payable on the last day of each three-month interval during such Interest Period. Interest and commitment fees shall be calculated for actual days elapsed on the basis of a 360-day year, except that interest accruing at the Prime Rate shall be calculated for actual da ys elapsed on the basis of a 365, or when appropriate 366, day year. Interest shall be payable for the day an Advance is made but not for the day of any payment on the amount paid if payment is received prior to noon at the place of payment. If any payment of principal of or interest on an Advance shall become due on a day which is not a Business Day, such payment shall be made on the next succeeding Business Day and, in the case of a principal payment, such extension of time shall be included in computing interest in connection with such payment.

            2.16            Notification of Advances, Interest Rates, Prepayments and Commitment Reductions. Promptly after receipt thereof, the Administrative Agent will notify each Lender of the contents of each Aggregate Commitment reduction notice, Borrowing Notice, Conversion/Continuation Notice and repayment notice received by it hereunder. The Administrative Agent will notify each Lender of the interest rate applicable to each Eurodollar Advance promptly upon determination of such interest rate and will give each Lender prompt notice of each change in the Alternate Base Rate.

            2.17            Lending Installations. Each Lender may book its Loans at any Lending Installation selected by such Lender and may change its Lending Installation from time to time. All terms of this Agreement shall apply to any such Lending Installation and the Loans and any Notes issued hereunder shall be deemed held by each Lender for the benefit of any such Lending Installation. Each Lender may, by written notice to the Administrative Agent and the Borrower in accordance with Article XIII, designate replacement or additional Lending Installations through which Loans will be made by it and for whose account Loan payments are to be made.

            2.18            Non-Receipt of Funds by the Administrative Agent. Unless the Borrower or Lender, as the case may be, notifies the Administrative Agent prior to the date on which it is scheduled to make payment to the Administrative Agent of (i) in the case of a Lender, the proceeds of a Loan or (ii) in the case of the Borrower, a payment of principal, interest or fees to the Administrative Agent for the account of the Lenders, that it does not intend to make such payment, the Administrative Agent may assume that such payment has been made. The Administrative Agent may, but shall not be obligated to, make the amount of such payment available to the intended recipient in reliance upon such assumption. If such Lender or the Borrower, as the case may be, has not in fact made such payment to the Administrative Agent, the recipient of such payment shall, on demand by the Administrative Agent, repay to the Administrative Agent the amount so made available together with interest thereon in respect of each day during the period commencing on the date such amount was so made available by the Administrative Agent until the date the Administrative Agent recovers such amount at a rate per annum equal to (x) in the case of payment by a Lender, the Federal Funds Effective Rate for such day for the first three days and, thereafter, the interest rate applicable to the relevant Loan or (y) in the case of payment by the Borrower, the interest rate applicable to the relevant Loan.

            2.19            Replacement of Lender. If the Borrower is required pursuant to Section 3.1, 3.2 or 3.5 to make any additional payment to any Lender or if any Lender's obligation to make or continue, or to convert Advances into, Eurodollar Advances shall be suspended pursuant to Section 3.3 (any Lender so affected an "Affected Lender"), the Borrower may elect, if such amounts continue to be charged or such suspension is still effective, to replace such Affected Lender as a Lender party to this Agreement, provided that no Default or Unmatured Default shall have occurred and be continuing at the time of such replacement, and provided, further, that, concurrently with such replacement, (i) another bank or other entity which is reasonably satisfactory to the Borrower and the Administrative Agent shall agree, as of such dat e, to purchase for cash the Advances and other Obligations due to the Affected Lender pursuant to an assignment substantially in the form of Exhibit C and to become a Lender for all purposes under this Agreement and to assume all obligations of the Affected Lender to be terminated as of such date and to comply with the requirements of Section 12.3 applicable to assignments, and (ii) the Borrower shall pay to such Affected Lender in same day funds on the day of such replacement (A) all interest, fees and other amounts then accrued but unpaid to such Affected Lender by the Borrower hereunder to the date of termination, including payments due to such Affected Lender under Sections 3.1, 3.2 and 3.5, and (B) an amount, if any, equal to the payment which would have been due to such Lender on the day of such replacement under Section 3.4 had the Revolving Loans of such Affected Lender been prepaid on such date rather than sold to the replacement Lender.

            2.20            Letters of Credit.

            2.20.1         Issuance. The Issuer hereby agrees, on the terms and conditions set forth in this Agreement, to issue standby letters of credit (together with the Existing Letter of Credit, each a "Letter of Credit") and to renew, extend, increase, decrease or otherwise modify Letters of Credit ("Modify," and each such action a "Modification") from time to time from the date of this Agreement to the Termination Date upon the request of the Borrower; provided that immediately after each Letter of Credit is issued or Modified, (i) the amount of the LC Obligations shall not exceed $20,000,000 and (ii) the Total Outstandings shall not exceed the Aggregate Commitment. No Letter of Credit shall have an expiry date later than the earlier of (a) one year after the date of issuance thereof (provided that any Letter of Credit with a one-year tenor may provide for the renewal th ereof for additional one-year periods (which shall in no event extend beyond the date referred to in the following clause (b)) and (b) five Business Days prior to the scheduled Termination Date.

            2.20.2         Participations. Upon the issuance or Modification by the Issuer of a Letter of Credit in accordance with this Section 2.20, the Issuer shall be deemed, without further action by any Person, to have unconditionally and irrevocably sold to each Lender, and each Lender shall be deemed, without further action by any Person, to have unconditionally and irrevocably purchased from the Issuer, a participation in such Letter of Credit (and each Modification thereof) and the related LC Obligations in proportion to its Pro Rata Share.

            2.20.3            Issuance or Modification of Letters of Credit. Subject to Section 2.20.1, the Borrower shall deliver an LC Application to the Issuer prior to noon at least two Business Days (or such lesser period of time as the Issuer may agree in its sole discretion) prior to the proposed date of issuance or Modification of a Letter of Credit, specifying the beneficiary, the proposed date of issuance (or Modification) and the expiry date of such Letter of Credit and, in the case of issuance of a Letter of Credit, describing the proposed terms of such Letter of Credit and the nature of the transactions proposed to be supported thereby. Upon receipt of an LC Application, the Issuer shall promptly notify the Administrative Agent, and the Administrative Agent shall promptly notify each Lender, of the contents thereof and of the amount of each Lender's particip ation in such proposed Letter of Credit. The Issuer shall have no obligation to issue, or to increase the amount or extend the expiry date of, any Letter of Credit unless the conditions precedent set forth in Article IV are satisfied; it being understood that the Issuer shall have no duty to ascertain whether such conditions have been satisfied unless the Issuer has received written notice from the Borrower, the Administrative Agent or any Lender, which has not been rescinded, stating that any such condition precedent has not been satisfied. In the event of any conflict between the terms of this Agreement and the terms of any LC Application, the terms of this Agreement shall control.

            2.20.4            Letter of Credit Fees. The Borrower shall pay to the Administrative Agent, for the account of the Lenders ratably in accordance with their respective Pro Rata Shares, with respect to each Letter of Credit, a letter of credit fee at a rate per annum equal to the LC Fee Rate in effect from time to time on the Stated Amount of such Letter of Credit, such fee to be payable in arrears on each Payment Date, on the Termination Date and thereafter (if applicable) on demand; provided that during the existence of a Default, the Required Lenders may, at their option, by notice to the Borrower (which notice may be revoked at the option of the Required Lenders notwithstanding any provision of Section 8.2 requiring unanimous consent of the Lenders to changes in fees), declare that such fee shall be calculated based upon the LC Fee Rate plus 2%. The Borrower shall also pay to the Issuer for its own account (x) a fronting fee of 0.125% per annum on the Stated Amount of each Letter of Credit, with such fee to be payable in arrears on each Payment Date, and (y) documentary and processing charges in connection with the issuance or Modification of and draws under Letters of Credit in accordance with the Issuer's standard schedule for such charges as in effect from time to time.

            2.20.5            Reimbursement by Borrower. Promptly upon receipt from the beneficiary of any Letter of Credit of any demand for payment under such Letter of Credit, the Issuer shall notify the Administrative Agent, and upon receipt of such notice the Administrative Agent shall promptly notify the Borrower and each other Lender, as to the amount to be paid by the Issuer as a result of such demand and the proposed payment date. If the Issuer honors such demand for payment, the Issuer shall promptly notify the Borrower and the Borrower shall be irrevocably and unconditionally obligated to reimburse the Issuer for such payment not later than noon (i) if notice of such payment is received from the Issuer prior to 10:45 a.m. on a Business Day, on such Business Day, or (ii) otherwise, on the Business Day immediately following the Borrower's receipt of such notice (it bei ng understood that, subject to the other terms and conditions of this Agreement, the Borrower may request Advances to pay Reimbursement Obligations hereunder and that, in determining whether the making of any Advance would cause the Total Outstandings to exceed the Aggregate Commitment, any Reimbursement Obligation that will be paid with the proceeds of such Advance shall be deemed not to be outstanding). Any amount paid by the Issuer under a Letter of Credit and not reimbursed by the Borrower on the date of such payment shall bear interest, payable on demand, at a rate per annum equal to (a) for any day prior to the date on which such payment by the Borrower is due in accordance with the foregoing sentence, the Federal Funds Effective Rate, and (b) thereafter, the rate applicable to Floating Rate Advances plus, beginning on the first Business Day after such payment is due, 2%.

            2.20.6            Reimbursement by Lenders. If and to the extent that the Borrower fails to reimburse the Issuer for any payment under a Letter of Credit by the time required by Section 2.20.5, each Lender (other than the Issuer in its capacity as a Lender) shall be unconditionally and irrevocably obligated, without regard to the occurrence of any Default or Unmatured Default or any condition precedent whatsoever, to pay the Issuer on demand (i) such Lender's Pro Rata Share of such unreimbursed amount plus (ii) interest on the amount payable by such Lender, for each day from the date of the applicable payment by the Issuer to the date on which the Issuer receives payment from such Lender, at a rate per annum equal to the Federal Funds Effective Rate or, beginning on third Business Day after demand for such amount by the Issuer, the rate applicable to Floating Rate Advances. The Issuer will pay to each Lender, ratably in accordance with its Pro Rata Share, any amount received by it from the Borrower for application in payment, in whole or in part, to amounts owed by the Borrower in respect of any drawing under a Letter of Credit, together with interest paid by the Borrower thereon, but only to the extent (and, in the case of interest, for the relevant period of time after) such Lender made payment to the Issuer in respect of such drawing pursuant to this Section 2.20.6.

            2.20.7            Obligations Absolute. The Borrower's obligation to reimburse the Issuer for each drawing under a Letter of Credit shall be absolute and unconditional under any and all circumstances and irrespective of any setoff, counterclaim or defense to payment which the Borrower may have or have had against the Issuer, any Lender or any beneficiary of a Letter of Credit. The Borrower further agrees with the Issuer and the Lenders that neither the Issuer nor any Lender shall be responsible for, and the Reimbursement Obligations in respect of any Letter of Credit shall not be affected by, among other things, any error, omission, interruption or delay in transmission, dispatch or delivery of any message or advice, however transmitted, in connection with any Letter of Credit, the validity or genuineness of documents or of any endorsements thereon, even if such doc uments should in fact prove to be in any or all respects invalid, fraudulent or forged, or any dispute between or among the Borrower, any of its Affiliates, the beneficiary of any Letter of Credit or any financing institution or other Person to whom any Letter of Credit may be transferred or any claim or defense whatsoever of the Borrower or of any of its Affiliates against the beneficiary of any Letter of Credit or any such transferee. The Borrower agrees that any action taken or omitted by the Issuer or any Lender under or in connection with any Letter of Credit and the related drafts and documents, if done without gross negligence or willful misconduct, shall be binding upon the Borrower and shall not put the Issuer or any Lender under any liability to the Borrower. Notwithstanding the foregoing or any other provision of this Agreement, the Borrower shall not be precluded from asserting any claim for direct (but not consequential) damages suffered by the Borrower to the extent, but only to the extent, cau sed by (i) the gross negligence or willful misconduct of the Issuer in determining whether a request presented under any Letter of Credit complied with the terms of such Letter of Credit, (ii) the Issuer's failure to pay under any Letter of Credit after the presentation to it of a request strictly complying with the terms and conditions of such Letter of Credit or (iii) the gross negligence or willful misconduct of the Administrative Agent or any Lender in giving a notice of the type described in the second-to-last sentence of Section 2.20.3.

            2.20.8            Actions of Issuer. The Issuer shall be entitled to rely, and shall be fully protected in relying, upon any Letter of Credit, draft, writing, resolution, notice, consent, certificate, affidavit, letter, cablegram, telegram, facsimile, telex or teletype message, statement, order or other document believed in good faith by it to be genuine and correct and to have been signed, sent or made by the proper Person or Persons, and upon advice and statements of legal counsel, independent accountants and other experts selected by the Issuer. The Issuer shall be fully justified in failing or refusing to take any action under this Agreement unless it shall first have received such advice or concurrence of the Required Lenders as it reasonably deems appropriate or it shall first be indemnified to its reasonable satisfaction by the Lenders against any and all lia bility and expense which may be incurred by it by reason of taking or continuing to take any such action. Notwithstanding any other provision of this Section 2.20, the Issuer shall in all cases be fully protected in acting, or in refraining from acting, under this Agreement in accordance with a request of the Required Lenders, and such request and any action taken or failure to act pursuant thereto shall be binding upon the Lenders and any future holder of a participation in any Letter of Credit. Without limiting the foregoing, the responsibility of the Issuer to the Borrower and each Lender with respect to any requested drawing under a Letter of Credit shall be only to determine that the documents delivered under such Letter of Credit in connection with a demand for payment appear on their face to be in conformity in all material respects with such Letter of Credit.

            2.20.9            Indemnification. The Borrower agrees to indemnify and hold harmless each Lender, the Issuer and the Administrative Agent, and their respective directors, officers, agents and employees, from and against any and all claims and damages, losses, liabilities, costs or expenses which such Lender, the Issuer or the Administrative Agent may incur (or which may be claimed against such Lender, the Issuer or the Administrative Agent by any Person whatsoever) by reason of or in connection with the issuance, execution and delivery or transfer of or payment or failure to pay under any Letter of Credit or any actual or proposed use of any Letter of Credit, including any claims, damages, losses, liabilities, costs or expenses which the Issuer may incur by reason of or in connection with (i) the failure of any other Lender to fulfill or comply with its obligations to the Issuer hereunder (but nothing herein contained shall affect any right the Borrower may have against any defaulting Lender) or (ii) by reason of or on account of the Issuer issuing any Letter of Credit which specifies that the term "Beneficiary" therein includes any successor by operation of law of the named Beneficiary, but which Letter of Credit does not require that any drawing by any such successor Beneficiary be accompanied by a copy of a legal document, satisfactory to the Issuer, evidencing the appointment of such successor Beneficiary; provided that the Borrower shall not be required to indemnify any Lender, the Issuer or the Administrative Agent for any claims, damages, losses, liabilities, costs or expenses to the extent, but only to the extent, caused by any event described in clause , (ii) or (iii) of the last sentence of Section 2.20.7. Nothing in this Section 2.20.9 is intended to limit the obligations of the Borrower under any other provision of this Agreement.

            2.20.10            Lenders' Indemnification. Each Lender shall, ratably in accordance with its Pro Rata Share, indemnify the Issuer and its affiliates and their respective directors, officers, agents and employees (to the extent not reimbursed by the Borrower) against any cost, expense (including reasonable counsel fees and charges), claim, demand, action, loss or liability (except such as result from such indemnitees' gross negligence or willful misconduct or the Issuer's failure to pay under any Letter of Credit after the presentation to it of a request strictly complying with the terms and conditions of such Letter of Credit) that such indemnitees may suffer or incur in connection with this Section 2.20 or any action taken or omitted by such indemnitees hereunder.

            2.20.11           LC Collateral Account. The Borrower agrees that, if any Letter of Credit is outstanding on the Termination Date, it will establish on such date (or on such earlier date as may be required pursuant to Section 8.1), and thereafter maintain so long as any Letter of Credit is outstanding or any amount is payable to the Issuer or the Lenders in respect of any Letter of Credit, a special collateral account pursuant to arrangements satisfactory to the Administrative Agent (the "LC Collateral Account") at the Administrative Agent's office at the address specified pursuant to Article XIII, in the name of the Borrower but under the sole dominion and control of the Administrative Agent, for the benefit of the Lenders, and in which the Borrower shall have no interest other than as set forth in Section 8.1. The Borrower hereby pledges, assigns a nd grants to the Administrative Agent, on behalf of and for the ratable benefit of the Lenders and the Issuer, a security interest in all of the Borrower's right, title and interest in and to all funds which may from time to time be on deposit in the LC Collateral Account, to secure the prompt and complete payment and performance of the Obligations. The Administrative Agent will invest any funds on deposit from time to time in the LC Collateral Account in certificates of deposit of JPMorgan having a maturity not exceeding 30 days. The Administrative Agent agrees that when all Obligations have been paid in full and all Letters of Credit have expired or been terminated, the Administrative Agent will deliver all remaining funds in the LC Collateral Account to the Borrower (or such other Person as is entitled thereto under applicable law). If the Administrative Agent determines that any Person other than the Borrower is entitled to such remaining funds, the Administrative Agent shall use reasonable efforts to gi ve the Borrower notice of such determination in advance of delivering such funds to any other Person, but the Administrative Agent shall have no liability for the failure to deliver such notice.

            2.20.12       Rights as a Lender. In its capacity as a Lender, the Issuer shall have the same rights and obligations as any other Lender.

            2.21            Swing Line Loans.

            2.21.1         Amount of Swing Line Loans. Upon the satisfaction of the applicable conditions precedent set forth in Article IV, from and including the date of this Agreement and prior to the Termination Date, the Swing Line Lender agrees, on the terms and conditions set forth in this Agreement, to make Swing Line Loans to the Borrower from time to time in an aggregate principal amount not to exceed $20,000,000 notwithstanding the fact that such Swing Line Loans, when aggregated with such Lender's Pro Rata Share of Revolving Loans and L/C Obligations hereunder may exceed the amount of such Lender's Commitment; provided that the Total Outstandings shall not at any time exceed the Aggregate Commitment. Subject to the terms of this Agreement, the Borrower may borrow, repay and reborrow Swing Line Loans at any time prior to the Termination Date.

            2.21.2          Method of Borrowing. Not later than 1:00 p.m. on the Borrowing Date of each Swing Line Loan, the Borrower shall deliver to the Administrative Agent and the Swing Line Lender irrevocable notice (a "Swing Line Loan Notice") specifying (i) the applicable Borrowing Date (which date shall be a Business Day), and (ii) the aggregate amount of the requested Swing Line Loan, which shall be an integral multiple of $100,000.

            2.21.3          Making of Swing Line Loans. Promptly after receipt of a Swing Line Loan Notice, the Administrative Agent shall notify each Lender by fax, or other similar form of transmission, of the requested Swing Line Loan. Not later than 3:00 p.m. on the applicable Borrowing Date, the Swing Line Lender shall make available the Swing Line Loan, in funds immediately available in [New York City], to the Administrative Agent at its address specified pursuant to Article XIII. The Administrative Agent will promptly make the funds so received from the Swing Line Lender available to the Borrower on the Borrowing Date at the Administrative Agent's aforesaid address.

            2.21.4        Repayment of Swing Line Loans. The Swing Line Lender may, at any time in its sole discretion, by notice to the Administrative Agent not later than noon on any day (which shall promptly notify each Lender), require each Lender (including the Swing Line Lender) to make a Revolving Loan in the amount of such Lender's Pro Rata Share of such Swing Line Loan (including, without limitation, any interest accrued and unpaid thereon), for the purpose of repaying such Swing Line Loan. Not later than 2:00 p.m. on the date of any notice received pursuant to this Section 2.21.4, each Lender shall make available its required Revolving Loan, in funds immediately available in Chicago to the Administrative Agent at its address specified pursuant to Article XIII. Revolving Loans made pursuant to this Section 2.21.4 shall initially be Floating Rate Loans and thereaft er may be continued as Floating Rate Loans or converted into Eurodollar Loans in the manner provided in Section 2.5 and subject to the other conditions and limitations set forth in this Article II. Unless a Lender shall have notified the Swing Line Lender, prior to the making of any Swing Line Loan, that any applicable condition precedent set forth in Article IV had not then been satisfied, such Lender's obligation to make Revolving Loans pursuant to this Section 2.21.4 to repay Swing Line Loans shall be unconditional, continuing, irrevocable and absolute and shall not be affected by any circumstance, including, (a) any set-off, counterclaim, recoupment, defense or other right which such Lender may have against the Administrative Agent, the Swing Line Lender or any other Person, (b) the occurrence or continuance of a Default or Unmatured Default, (c) any adverse change in the condition (financial or otherwise) of the Borrower or (d) any other circumstance, happening or event whats oever. If any Lender fails to make payment to the Administrative Agent of any amount due under this Section 2.21.4, the Administrative Agent shall be entitled to receive, retain and apply against such obligation the principal and interest otherwise payable to such Lender hereunder until the Administrative Agent receives such payment from such Lender or such obligation is otherwise fully satisfied. In addition to the foregoing, if for any reasons any Lender fails to make payment to the Administrative Agent of any amount due under this Section 2.21.4, such Lender shall be deemed, at the option of the Administrative Agent, to have unconditionally and irrevocably purchased from the Swing Line Lender, without recourse or warranty, an undivided interest and participation in the applicable Swing Line Loan in the amount of such Revolving Loan, and such interest and participation may be recovered from such Lender together with interest thereon at the Federal Funds Effective Rate for each day during the period commencing on the date of demand and ending on the date such amount is received.

ARTICLE III

YIELD PROTECTION; TAXES

            3.1            Yield Protection. (a)  If, on or after the date of this Agreement, (x) the adoption of or any change in any law or any governmental or quasi-governmental rule, regulation, policy, guideline or directive (whether or not having the force of law), or (y) any change in the interpretation or administration thereof by any governmental or quasi-governmental authority, central bank or comparable agency charged with the interpretation or administration thereof, or (z) compliance by any Lender or applicable Lending Installation with any request or directive (whether or not having the force of law) issued on or after the date hereof of any such authority, central bank or comparable agency:

            (i)            subjects any Lender or any applicable Lending Installation to any Taxes, or changes the basis of taxation of payments (other than with respect to Excluded Taxes) to any Lender in respect of its Eurodollar Loans or Letters of Credit or participations therein, or

            (ii)            imposes or increases or deems applicable any reserve, assessment, insurance charge, special deposit or similar requirement against assets of, deposits with or for the account of, or credit extended by, any Lender or any applicable Lending Installation (other than reserves and assessments taken into account in determining the interest rate applicable to Eurodollar Advances), or

            (iii)           imposes any other condition the result of which is to increase the cost to any Lender or any applicable Lending Installation of making, funding or maintaining its Eurodollar Loans or of issuing or participating in Letters of Credit or reduces any amount receivable by any Lender or any applicable Lending Installation in connection with its Eurodollar Loans or its issuance of or participations in Letters of Credit, or requires any Lender or any applicable Lending Installation to make any payment calculated by reference to the amount of Eurodollar Loans held or interest received, or Letters of Credit issued or participated in, by it, by an amount deemed material by such Lender,

and the result of any of the foregoing is to increase the cost to such Lender or applicable Lending Installation of making or maintaining its Eurodollar Loans or Commitment or issuing or participating in Letters or Credit or to reduce the return received by such Lender or applicable Lending Installation in connection with such Eurodollar Loans, such Commitment or the Letters of Credit, then, within 15 days of demand by such Lender, the Borrower shall pay such Lender such additional amount or amounts as will compensate such Lender for such increased cost or reduction in amount received. A Lender shall not be entitled to demand compensation or be compensated hereunder to the extent that such compensation relates to any period of time more than 60 days prior to the date upon which such Lender first notified the Borrower of the occurrence of the event entitling such Lender to such compensation (unless, and to the extent, that any such compensation so demanded shall relate to the retroactive appli cation of any event so notified to the Borrower).

            (b)            Without limiting subsection (a) above, any Lender may require the Borrower to pay, contemporaneously with each payment of interest on any Eurodollar Loan of such Lender, additional interest on such Eurodollar Loan at a rate per annum determined by such Lender up to but not exceeding the excess of (i) (A) the applicable Eurodollar Base Rate divided by (B) one minus the Reserve Requirement over (ii) the applicable Eurodollar Base Rate. Any Lender wishing to require payment of such additional interest (x) shall so notify the Borrower and the Administrative Agent, in which case such additional interest on the Eurodollar Loans of such Lender shall be payable to such Lender at the place indicated in such notice with respect to each Interest Period commencing at least three Business Days after the giving of such notice and (y) shall notify the Borrowe r at least five Business Days prior to each date on which interest is payable on any Eurodollar Loan of the amount then due it under this Section 3.1.

            3.2            Changes in Capital Adequacy Regulations. If a Lender determines the amount of capital required or expected to be maintained by such Lender, any Lending Installation of such Lender or any corporation controlling such Lender is increased as a result of a Change, then, within 15 days of demand by such Lender, the Borrower shall pay such Lender the amount necessary to compensate for any shortfall in the rate of return on the portion of such increased capital which such Lender determines is attributable to this Agreement, its Loans, its Commitment or its obligation to issue or participate in Letters of Credit (after taking into account such Lender's policies as to capital adequacy). "Change" means (i) any change after the date of this Agreement in the Risk-Based Capital Guidelines or (ii) any adoption of or change in any other law, governmental or quas i-governmental rule, regulation, policy, guideline, interpretation, or directive (whether or not having the force of law) after the date of this Agreement which affects the amount of capital required or expected to be maintained by any Lender or any Lending Installation or any corporation controlling any Lender. "Risk-Based Capital Guidelines" means (i) the risk-based capital guidelines in effect in the United States on the date of this Agreement, including transition rules, and (ii) the corresponding capital regulations promulgated by regulatory authorities outside the United States implementing the July 1988 report of the Basle Committee on Banking Regulation and Supervisory Practices Entitled "International Convergence of Capital Measurements and Capital Standards," including transition rules, and any amendments to such regulations adopted prior to the date of this Agreement.

            3.3            Availability of Types of Advances. If any Lender reasonably determines that maintenance of its Eurodollar Loans at a suitable Lending Installation would violate any applicable law, rule, regulation, or directive, whether or not having the force of law, or if the Required Lenders reasonably determine that (i) deposits of a type and maturity appropriate to match fund Eurodollar Advances are not available or (ii) the Eurodollar Base Rate does not accurately reflect the cost of obtaining funds to make or maintain Eurodollar Advances, then the Administrative Agent shall suspend the availability of Eurodollar Advances and require any affected Eurodollar Advances to be repaid or converted to Floating Rate Advances (on or before the date required by such law, rule, regulation or directive), subject to the payment of any funding indemnification amounts require d by Section 3.4.

            3.4            Funding Indemnification. If any payment of a Eurodollar Advance occurs on a date which is not the last day of the applicable Interest Period, whether because of acceleration, prepayment or otherwise, or a Eurodollar Advance is not made, continued or converted on a date specified by the Borrower for any reason other than default by the Lenders, the Borrower will indemnify each Lender for any loss or cost incurred by it resulting therefrom, including any loss or cost in liquidating or employing deposits acquired to fund or maintain such Eurodollar Rate Advance.

            3.5            Taxes. (i)  All payments by the Borrower to or for the account of any Lender or the Administrative Agent hereunder or under any Note shall be made free and clear of and without deduction for any and all Taxes. If the Borrower shall be required by law to deduct any Taxes from or in respect of any sum payable hereunder to any Lender or the Administrative Agent, (a) the sum payable shall be increased as necessary so that after making all required deductions (including deductions applicable to additional sums payable under this Section 3.5) such Lender or the Administrative Agent (as the case may be) receives an amount equal to the sum it would have received had no such deductions been made, (b) the Borrower shall make such deductions, (c) the Borrower shall pay the full amount deducted to the relevant authority in accordance with applicab le law and (d) the Borrower shall furnish to the Administrative Agent the original copy of a receipt evidencing payment thereof within 30 days after such payment is made.

            (ii)            In addition, the Borrower hereby agrees to pay any present or future stamp or documentary taxes and any other excise or property taxes, charges or similar levies which arise from any payment made hereunder or under any Note or LC Application or from the execution or delivery of, or otherwise with respect to, this Agreement, any Note or any LC Application ("Other Taxes").

            (iii)            The Borrower hereby agrees to indemnify the Administrative Agent and each Lender for the full amount of Taxes or Other Taxes (including any Taxes or Other Taxes imposed on amounts payable under this Section 3.5) paid by the Administrative Agent or such Lender and any liability (including penalties, interest and expenses) arising therefrom or with respect thereto. Payments due under this indemnification shall be made within 30 days of the date the Administrative Agent or such Lender makes demand therefor pursuant to Section 3.6.

            (iv)            Each Lender that is not incorporated under the laws of the United States of America or a state thereof (each a "Non-U.S. Lender") agrees that it will, not less than ten Business Days after the date of this Agreement, (i) deliver to each of the Borrower and the Administrative Agent two duly completed copies of United States Internal Revenue Service Form W-8BEN or W-8ECI, certifying in either case that such Lender is entitled to receive payments under this Agreement without deduction or withholding of any United States federal income taxes, and (ii) deliver to each of the Borrower and the Administrative Agent a United States Internal Revenue Form W-8 or W-9, as the case may be, and certify that it is entitled to an exemption from United States backup withholding tax. Each Non-U.S. Lender further undertakes to deliver to each of the Borrower and the Administra tive Agent (x) renewals or additional copies of such form (or any successor form) on or before the date that such form expires or becomes obsolete, and (y) after the occurrence of any event requiring a change in the most recent forms so delivered by it, such additional forms or amendments thereto as may be reasonably requested by the Borrower or the Administrative Agent. All forms or amendments described in the preceding sentence shall certify that such Lender is entitled to receive payments under this Agreement without deduction or withholding of any United States federal income taxes, unless an event (including any change in treaty, law or regulation) has occurred prior to the date on which any such delivery would otherwise be required which renders all such forms inapplicable or which would prevent such Lender from duly completing and delivering any such form or amendment with respect to it and such Lender advises the Borrower and the Administrative Agent that it is not capable of receiving payment s without any deduction or withholding of United States federal income tax.

            (v)            For any period during which a Non-U.S. Lender has failed to provide the Borrower with an appropriate form pursuant to subsection (iv), above (unless such failure is due to a change in treaty, law or regulation, or any change in the interpretation or administration thereof by any governmental authority, occurring subsequent to the date on which a form originally was required to be provided), such Non-U.S. Lender shall not be entitled to indemnification under this Section 3.5 with respect to Taxes imposed by the United States; provided that, should a Non-U.S. Lender which is otherwise exempt from or subject to a reduced rate of withholding tax become subject to Taxes because of its failure to deliver a form required under subsection (iv), above, the Borrower shall take such steps as such Non-U.S. Lender shall reasonably request to a ssist such Non-U.S. Lender to recover such Taxes.

            (vi)              Any Lender that is entitled to an exemption from or reduction of withholding tax with respect to payments under this Agreement or any Note pursuant to the law of any relevant jurisdiction or any treaty shall deliver to the Borrower (with a copy to the Administrative Agent), at the time or times prescribed by applicable law, such properly completed and executed documentation prescribed by applicable law as will permit such payments to be made without withholding or at a reduced rate.

            (vii)            If the U.S. Internal Revenue Service or any other governmental authority of the United States or any other country or any political subdivision thereof asserts a claim that the Administrative Agent did not properly withhold tax from amounts paid to or for the account of any Lender (because the appropriate form was not delivered or properly completed, because such Lender failed to notify the Administrative Agent of a change in circumstances which rendered its exemption from withholding ineffective, or for any other reason), such Lender shall indemnify the Administrative Agent fully for all amounts paid, directly or indirectly, by the Administrative Agent as tax, withholding therefor, or otherwise, including penalties and interest, and including taxes imposed by any jurisdiction on amounts payable to the Administrative Agent under this subsection, together w ith all costs and expenses related thereto (including attorneys fees and time charges of attorneys for the Administrative Agent, which attorneys may be employees of the Administrative Agent). The obligations of the Lenders under this Section 3.5(vii) shall survive the payment of the Obligations and termination of this Agreement.

            3.6            Lender Statements; Survival of Indemnity. To the extent reasonably possible, each Lender shall designate an alternate Lending Installation with respect to its Eurodollar Loans to reduce any liability of the Borrower to such Lender under Sections 3.1, 3.2 and 3.5 or to avoid the unavailability of Eurodollar Advances under Section 3.3, so long as such designation is not, in the reasonable judgment of such Lender, disadvantageous to such Lender. Each Lender shall deliver a written statement of such Lender to the Borrower (with a copy to the Administrative Agent) as to the amount due, if any, under Section 3.1, 3.2, 3.4 or 3.5. Such written statement shall set forth in reasonable detail the calculations upon which such Lender determined such amount and shall be rebuttable presumptive evidence of the amount thereof. Determination of amounts payable under such Sections in connection with a Eurodollar Loan shall be calculated as though each Lender funded its Eurodollar Loan through the purchase of a deposit of the type and maturity corresponding to the deposit used as a reference in determining the Eurodollar Base Rate applicable to such Eurodollar Loan, whether in fact that is the case or not. The obligations of the Borrower under Sections 3.1, 3.2, 3.4 and 3.5 shall survive payment of the Obligations and termination of this Agreement.

ARTICLE IV

CONDITIONS PRECEDENT

              4.1         Effectiveness. This Agreement shall become effective at the time (the "Effective Time") at which the Borrower has furnished the following documents to Administrative Agent with sufficient copies for the Lenders:

            (i)            Copies of the articles or certificate of incorporation or other organizational documents of the Borrower and each Guarantor, together with all amendments, and a certificate of good standing, each certified by the appropriate governmental officer in its jurisdiction of organization, as well as any other information that any Lender may request that is required by Section 326 of the USA PATRIOT ACT or necessary for the Administrative Agent or any Lender to verify the identity of the Borrower as required by Section 326 of the USA PATRIOT ACT.

            (ii)           Copies certified by the Secretary or Assistant Secretary of the Borrower and each Guarantor, of its by-laws (to the extent applicable) and of its Board of Directors' resolutions, members' resolutions or similar documents authorizing the execution of the Loan Documents to which the Borrower or such Guarantor is a party.

            (iii)          An incumbency certificate, executed by the Secretary or Assistant Secretary of the Borrower and each Guarantor, which shall identify by name and title and bear the signatures of the officers of the Borrower or such Guarantor authorized to sign the Loan Documents to which the Borrower or such Guarantor is a party, upon which certificate the Administrative Agent and the Lenders shall be entitled to rely until informed of any change in writing by the Borrower or such Guarantor.

            (iv)            Evidence, in form and substance satisfactory to the Administrative Agent, that the Borrower has obtained all governmental approvals necessary for it to enter into the Loan Documents.

            (v)            A certificate, signed by an Authorized Officer, stating that on the initial Borrowing Date, and after giving effect to any Credit Extension to be made on such date, (x) no Default or Unmatured Default has occurred and is continuing, (y) the representations and warranties set forth in Article V are true and correct as of such date and (z) since December 31, 2003 there has been no change in the business, property, condition (financial or otherwise) or results of operations of the Borrower and its Subsidiaries which could reasonably be expected to have a Material Adverse Effect.

            (vi)            A written opinion of counsel to the Borrower and the Guarantors, addressed to the Lenders in substantially the form of Exhibit B.

            (vii)            Any Note requested by a Lender pursuant to Section 2.13 payable to the order of such requesting Lender.

            (viii)           Written money transfer instructions, in substantially the form of Exhibit D, addressed to the Administrative Agent and signed by an Authorized Officer, together with such other related money transfer authorizations as the Administrative Agent may have reasonably requested.

            (ix)            The Subsidiary Guaranty executed by Material Subsidiaries and in compliance with Section 6.2.8.

            (x)            Copies, certified as being correct and complete by an Authorized Officer, of the Indenture dated as of December 1, 1995, between the Borrower and JPMorgan (as successor to The First National Bank of Chicago), as trustee, and all supplements thereto.

            (xi)            Such other documents as any Lender or its counsel may have reasonably requested.

            4.2            Each Credit Extension. No Lender shall be required to make any Credit Extension unless on the date of such Credit Extension:

            (i)              No Default or Unmatured Default exists or will result therefrom.

            (ii)            The representations and warranties contained in Article V are true and correct as of such date except to the extent any such representation or warranty is stated to relate solely to an earlier date, in which case such representation or warranty shall have been true and correct on and as of such earlier date.

            (iii)            All legal matters incident to the making of such Credit Extension are reasonably satisfactory to the Administrative Agent and its counsel.

            Each Borrowing Notice with respect to an Advance, each Swing Line Loan Notice with respect to a Swing Line Loan and each LC Application shall constitute a representation and warranty by the Borrower that the conditions contained in subsections (i) and (ii) above have been satisfied. For the avoidance of doubt, the conversion or continuation of a Revolving Loan shall not constitute the making of a Credit Extension.

ARTICLE V

REPRESENTATIONS AND WARRANTIES

            The Borrower represents and warrants to the Lenders that:

            5.1            Organization. The Borrower and each of its Subsidiaries are duly organized, validly existing and in good standing under the laws of the states of their organization and have all requisite authority to conduct their respective businesses in each jurisdiction in which the failure to have such authority, singly or in the aggregate, could reasonably be expected to have a Material Adverse Effect. The Borrower and each of its Subsidiaries have full power and authority to carry on their business as now conducted.

            5.2            Authorization and Validity. The Borrower and each Guarantor has the power and authority and legal right to execute and deliver the Loan Documents to which it is a party and to perform its obligations thereunder. The execution and delivery by the Borrower and each Guarantor of the Loan Documents to which it is a party have been duly authorized by proper organizational proceedings, and the Loan Documents to which the Borrower and such Guarantor is a party constitute legal, valid and binding obligations of the Borrower or such Guarantor, as the case may be, enforceable against the Borrower or such Guarantor, as the case may be, in accordance with their terms, except as enforceability may be limited by bankruptcy, insolvency or similar laws affecting the enforcement of creditors' rights generally.

            5.3            Financial Statements. The December 31, 2003 and the September 30, 2004 consolidated financial statements of the Borrower and the Subsidiaries heretofore delivered to the Administrative Agent and the Lenders were prepared in accordance with generally accepted accounting principles in effect on the date such statements were prepared and fairly present the financial position and results of operations of the Borrower and its Subsidiaries at such dates and the consolidated results of their operations for the periods then ended.

            5.4            Subsidiaries. Schedule 5.4 contains an accurate list of all of the presently existing Subsidiaries, setting forth their respective jurisdictions of organization and the percentage of their respective capital stock or membership interests owned by the Borrower or other Subsidiaries. All of the issued and outstanding shares of capital stock of each corporate Subsidiary have been duly authorized and issued and are fully paid and nonassessable.

            5.5            ERISA. Each Plan is in material compliance with, and has been administered in material compliance with, all applicable provisions of ERISA, the Code and any other applicable federal or state law, except where the failure to so comply would not (individually or in the aggregate) reasonably be expected to have a Material Adverse Effect, and no event or condition has occurred and is continuing as to which the Borrower is under an obligation to furnish a report to the Administrative Agent and the Lenders under Section 6.1(d) and which would reasonably be expected (individually or in the aggregate) to have a Material Adverse Effect.

            5.6            Defaults. No Default or Unmatured Default has occurred and is continuing.

            5.7            Accuracy of Information. No information, exhibit or report furnished by the Borrower or any Subsidiary to the Administrative Agent or any Lender in connection with the negotiation of this Agreement contains any material misstatement of fact or omitted to state a material fact necessary to make the statements contained therein not misleading.

            5.8            Regulation U. Neither the Borrower nor any Subsidiary is engaged principally, or as one of its important activities, in the business of extending credit for the purpose of purchasing or carrying Margin Stock. Margin Stock constitutes less than 25% of the consolidated assets of the Borrower and its Subsidiaries which are subject to any limitation on sale or pledge or any other restriction hereunder. No part of the proceeds of any Loan will be used to purchase or carry any Margin Stock in violation of Regulation U.

            5.9            Taxes. The Borrower and its Subsidiaries have filed all United States federal tax returns and all other tax returns which, to the Knowledge of the Borrower, are required to be filed and have paid all taxes due pursuant to said returns or material taxes due pursuant to any assessment received by the Borrower or any Subsidiary, except in both cases such taxes, if any, as are being contested in good faith and as to which adequate reserves have been provided in accordance with Agreement Accounting Principles. The charges, accruals and reserves on the books of the Borrower and its Subsidiaries in respect of any taxes or other governmental charges are adequate in accordance with Agreement Accounting Principles.

            5.10        Liens. There are no Liens on any of the properties or assets of the Borrower or any Subsidiary except (i) Liens permitted by Section 6.3.2 and (ii) with respect to properties and assets other than Productive Properties, Principal Transmission Facilities and the stock of any Subsidiary, Liens that could not, individually or in the aggregate, reasonably be expected to have a Material Adverse Effect. All easements, rights of way, licenses and other real property rights required for operation of the businesses of the Borrower and its Subsidiaries (collectively the "Rights of Way") are owned free and clear of any Lien, other than Liens permitted by this Agreement and Liens already on any parcel of real property with respect to which the Rights of Way have been granted, which will not, in the aggregate, at any time materially detract from the value of the Rights of Way or materially impair the use of the Rights of Way in the operation of the businesses of the Borrower and its Subsidiaries.

            5.11        Compliance with Orders. Neither the Borrower nor any Subsidiary is in default under the terms of any order of any federal or state court or administrative agency by which it or any of its properties may be bound, except for any defaults which could not, individually or in the aggregate, be reasonably expected to have a Material Adverse Effect.

            5.12        Litigation. Except as set forth in Schedule 5.12, there are no actions at law or in equity pending or, to the Knowledge of the Borrower, threatened involving the likelihood of any judgment or liability against the Borrower or any Subsidiary which could reasonably be expected to have a Material Adverse Effect.

            5.13        Burdensome Agreements. The Borrower is not a party to any contract or agreement which, in the opinion of management of the Borrower, could reasonably be expected to have a Material Adverse Effect.

            5.14        No Conflict. Neither the execution and delivery by the Borrower or any Guarantor of the Loan Documents to which it is a party, nor the consummation of the transactions therein contemplated, nor compliance with the provisions thereof will conflict with or result in the breach of any of the terms, conditions or provisions of, or constitute a default under, the charter or bylaws of the Borrower or any Subsidiary, or any indenture, loan agreement or other agreement or instrument to which the Borrower or any Subsidiary is a party or by which it may be bound, or result in creation of any Lien on any property of the Borrower or any Subsidiary, and neither the Borrower nor any Subsidiary is in default (after the expiration of any applicable grace period) in the performance, observance or fulfillment of any of the obligations, covenants or conditions contained in (i) any agreeme nt to which it is a party, which default could reasonably be expected to have a Material Adverse Effect, or (ii) any agreement or instrument evidencing or governing Indebtedness in a principal amount exceeding $10,000,000.

            5.15        Title to Properties. The Borrower and its Subsidiaries have good and marketable title to all real properties purported to be owned by them and good title to all other assets purported to be owned by them, subject to such minor defects as are common to property of the type owned by the Borrower and its Subsidiaries and Liens permitted by this Agreement and such defects and Liens in the aggregate do not materially interfere with or impair the Borrower's or any Subsidiary's business as presently conducted.

            5.16        Public Utility Holding Company Act. The Borrower and the Subsidiaries are exempt from registration under the provisions of the Public Utility Holding Company Act of 1935 pursuant to Section 3(a) thereof.

            5.17        Regulatory Approval. No consent or authorization of, filing with, or any other act by or in respect of any Person is required in connection with the enforceability, execution, delivery, performance or validity of this Agreement or the transactions contemplated thereby.

            5.18        Negative Pledge. Except as set forth in Schedule 5.18, neither the Borrower nor any Subsidiary is subject to any agreement, indenture, instrument, undertaking or security (other than this Agreement) which prohibits the creation, incurrence or sufferance to exist of any Lien.

            5.19        Investment Company Act. The Borrower is not an "investment company" or a Borrower "controlled" by an "investment company", within the meaning of the Investment Company Act of 1940, as amended.

            5.20        Compliance with Laws. The Borrower and its Subsidiaries have all franchises, licenses and permits necessary for the conduct of their respective businesses, and are in compliance with all laws, rules, regulations, orders, writs, judgments, injunctions, decrees or awards to which it may be subject, including (i) all provisions of ERISA, which, if violated, might result in a Lien or charge upon any property of the Borrower or any Subsidiary, and (ii) all material provisions of the Occupational Safety and Health Act of 1970 and the rules and regulations thereunder and applicable statutes, regulations, orders and restrictions relating to environmental standards or controls, except to the extent that failure to maintain or comply with any of the foregoing, singly and in the aggregate, could not reasonably be expected to have a Material Adverse Effect.

ARTICLE VI

COVENANTS

            During the term of this Agreement, unless the Required Lenders shall otherwise consent in writing:

            6.1            Information. The Borrower will furnish to each Lender:

                            (a)    As soon as reasonably practicable and in any event within 120 days after the close of each of its fiscal years, financial statements of the Borrower for such fiscal year on a consolidated and consolidating basis (consolidating statements need not be certified by such accountants) for itself and its Subsidiaries, including balance sheets as of the end of such period, statements of income and statements of retained earnings, and statements of cash flows, and, as to the consolidated statements, prepared in accordance with generally accepted accounting principles (except as expressly set forth therein) and accompanied by an unqualified (as to going concern or the scope of the audit) opinion of independent certified public accountants of recognized standing, which opinion shall state that such audit was conducted in accordance with generally accepted auditing standards and said financial statements fairly present the financial condition and results of operation of the Borrower as at the end of, and for, such fiscal year and a certificate of said accountants that, in the course of their examination necessary for their opinion, they have obtained no knowledge of any Default or Unmatured Default relating to accounting matters, or if, in the opinion of such accountants, any such Default or Unmatured Default shall exist, said certificate shall state the nature and status thereof; provided that delivery pursuant to subsection (e) below of copies of the Annual Report on Form 10-K of the Borrower for such fiscal year filed with the SEC (together with copies of the financial statements required to be included therein) shall be deemed to satisfy the requirement of this subsection (a) to deliver consolidated financial statements (but not the requirement to deliver consolidating statements or the accountants' certificate as to the presence or absence of any Default or Unmatured Default).

                        (b)     As soon as reasonably practicable and in any event within 60 days after the close of each of the first three quarterly accounting periods of each of its fiscal years, for itself and its Subsidiaries, consolidated and consolidating unaudited balance sheets as at the close of each such period and consolidated and consolidating statements of income and statements of retained earnings and statements of cash flows for the period from the beginning of such fiscal year to the end of such quarter; provided that delivery pursuant to subsection (e) below of copies of the Quarterly Report on Form 10-Q of the Borrower for such quarterly period filed with the SEC shall be deemed to satisfy the requirements of this subsection (b) to deliver consolidated financial statements (but not the requirement to deliver the certific ate of the Borrower's chief financial officer or chief accounting officer with respect thereto).

                        (c)    Simultaneously with the delivery of each set of financial statements referred to in Sections 6.1(a) and 6.1(b), a certificate of the chief financial officer or the chief accounting officer of the Borrower in the form of Exhibit G (i) setting forth in reasonable detail the calculations required to establish whether the Borrower was in compliance with the requirements of Section 6.4 on the date of such financial statements, (ii) stating whether there exists on the date of such certificate any Default and or Unmatured Default and, if any Default or Unmatured Default then exists, setting forth the details thereof and the action which the Borrower is taking or proposes to take with respect thereto, and (iii) stating that such financial statements fairly reflect in all material respects the financial conditions a nd results of operations of the Borrower and its Subsidiaries as of the date of the delivery of such financial statements and for the period covered thereby.

                        (d)    As soon as possible and in any event within 10 Business Days after the Borrower has Knowledge that any of the events or conditions specified below has occurred or exists with respect to any Plan or Multiemployer Plan, a statement, signed by the chief financial officer or chief accounting officer of the Borrower, describing said event or condition and the action which the Borrower or applicable member of the Controlled Group proposes to take with respect thereto (and a copy of any report or notice required to be filed with or given to the PBGC by the Borrower or applicable member of the Controlled Group with respect to such event or condition):

                                (i)    the occurrence of any Reportable Event with respect to any Plan, or any waiver shall be requested under Section 412(d) of the Code for any Plan,

                                (ii)    the distribution under Section 4041(c) of ERISA of a notice of intent to terminate any Plan, or any action taken by the Borrower or any member of the Controlled Group to terminate any Plan under Section 4041(c) of ERISA,

                                (iii)    the institution by PBGC of proceedings under Section 4042 of ERISA for the termination of, or the appointment of a trustee to administer, any Plan, or the receipt by the Borrower or any member of the Controlled Group of a notice from any Multiemployer Plan that such action has been taken by PBGC with respect to such Multiemployer Plan,

                                (iv)    the complete or partial withdrawal from a Multiemployer Plan by the Borrower or any member of the Controlled Group that could reasonably be expected to result in liability of the Borrower or such member under Section 4201 or 4204 of ERISA (including the obligation to satisfy secondary liability as a result of a purchaser default) having a Material Adverse Effect, or the receipt by the Borrower or any member of the Controlled Group of notice from a Multiemployer Plan that it is in reorganization or insolvency pursuant to Section 4241 or 4245 of ERISA or that it intends to terminate or has terminated under Section 4041A of ERISA,

                                (v)    the institution of a proceeding by a fiduciary of any Multiemployer Plan against the Borrower or any member of the Controlled Group to enforce Section 515 of ERISA, which proceeding is not dismissed within 30 days, or

                                (vi)    the adoption of an amendment to any Plan that, pursuant to Section 401(a)(29) of the Code or Section 307 of ERISA, would result in the loss of tax-exempt status of the trust of which such Plan is a part if the Borrower or any member of the Controlled Group fails to timely provide security to the Plan in accordance with the provisions of said Sections.

                        (e)    Promptly upon the filing thereof, copies of all registration statements and annual, quarterly, monthly or other regular reports which the Borrower or any of its Subsidiaries files with the SEC.

                        (f)    Promptly upon the furnishing thereof to all shareholders of the Borrower generally, copies of all financial statements, reports and proxy statements so furnished.

                        (g)    Promptly upon receipt thereof, one copy of each written audit report submitted to the Borrower or any Subsidiary by independent accountants resulting from (i) any annual or interim audit submitted after the occurrence and during the continuance of a Default or Unmatured Default and (ii) any special audit submitted at any time, in each case, made by them of the books of the Borrower or any Subsidiary.

                        (h)    As soon as available and in any event not later than April 30 of each calendar year, an engineering and economic analysis of the producing properties of the Borrower and its Subsidiaries prepared by an independent firm of consulting petroleum engineers and in form, substance and detail consistent with past practice.

                        (i)    Promptly and in any event within five Business Days after an Authorized Officer obtains knowledge thereof, notice of the occurrence of a Default or Unmatured Default, together with the details of such event and the actions, if any, the Borrower has taken or intends to take with respect thereto.

                        (j)    Such other information (including nonfinancial information) as the Administrative Agent or any Lender may from time to time reasonably request.

            6.2            Affirmative Covenants.

            6.2.1        Reports and Inspection. The Borrower will, and will cause each Subsidiary to, keep proper books and records in good order in accordance with sound business practice and prepare its financial statements in accordance with Agreement Accounting Principles and permit the Administrative Agent or any Lender, at its own expense, by its representatives and agents, to inspect any of the properties, books and financial records of the Borrower and each Subsidiary, to examine and make copies of the books of accounts and other financial records of the Borrower and each Subsidiary, and to discuss the affairs, finances and accounts of the Borrower and each Subsidiary with, and to be advised as to the same by, their respective officers at such reasonable times and intervals during regular business hours as the Administrative Agent or such Lender may designate, provided that such in quiry shall be limited to the purpose of evaluating the Borrower's financial condition or compliance with this Agreement.

            6.2.2        Conduct of Business. The Borrower will, and will cause each Material Subsidiary to, maintain as its principal business the exploration, production, transportation, distribution, refinement, processing, storage, marketing and gathering of oil and other hydrocarbons and petroleum, and natural, synthetic or other gas in substantially the same manner and in substantially the same fields of enterprise as it is presently conducted, and activities related or ancillary thereto. The Borrower will, and will cause each Subsidiary to, do or cause to be done all things necessary to maintain, preserve and keep in full force and effect (i) its existence and (ii) the rights, licenses, permits, privileges and franchises necessary or desirable to the conduct of its business except for any failure to so maintain, preserve or keep in full force and effect the existence of any Subsidiary o r any item listed in clause (ii) that could not reasonably be expected to have a Material Adverse Effect; provided that the foregoing shall not prohibit any merger, consolidation or sale of assets permitted under Section 6.3.1.

            6.2.3         Insurance. The Borrower will, and will cause each Subsidiary to, maintain insurance with reputable insurance companies or associations in such forms and amounts and covering such risks as are customary for companies of established reputation and similar size engaged in similar businesses and owning and operating similar properties; provided that it is agreed that, as of the date of this Agreement, the insurance coverage of the Borrower and its Subsidiaries set forth on Schedule 6.2 satisfies the requirements of this Section 6.2.3.

            6.2.4         Taxes. The Borrower will, and will cause each Subsidiary to, promptly pay and discharge all material taxes, assessments and governmental charges or levies imposed upon the Borrower or any Subsidiary (but in the case of a Subsidiary, only to the extent that such Subsidiary's assets shall be sufficient for the purpose), respectively, or upon or in respect of all or any part of the property and business of the Borrower or any Subsidiary, and all due and payable claims for work, labor or materials, which if unpaid might become a Lien upon any property of the Borrower or any Subsidiary (other than claims against any such Subsidiary in a proceeding under any bankruptcy or similar law), provided that the Borrower or such Subsidiary shall not be required to pay any such tax, assessment, charge, levy or claim if the validity thereof shall concurrently be contested in good faith by appropriate proceedings and if the Borrower or such Subsidiary shall set aside on its or their books reserves deemed by it or them to be required with respect thereto in accordance with generally accepted accounting principles.

            6.2.5         Compliance with Laws. The Borrower will, and will cause each Subsidiary to, comply with all laws, rules, regulations, orders, writs, judgments, injunctions, decrees or awards to which it may be subject, including (i) all provisions of ERISA, which, if violated, might result in a Lien or charge upon any property of the Borrower or any Subsidiary, and (ii) all material provisions of the Occupational Safety and Health Act of 1970 and the rules and regulations thereunder and applicable statutes, regulations, orders and restrictions relating to environmental standards or controls, except to the extent that failure to maintain or comply with any of the foregoing, singly and in the aggregate, could not reasonably be expected to have a Material Adverse Effect.

            6.2.6         Maintenance of Properties. The Borrower will, and will cause each Subsidiary to, do all things necessary to maintain, preserve, protect and keep its material properties (whether owned in fee or a leasehold interest) in good repair, working order and condition, and make all proper repairs, renewals and replacements so that its business carried on in connection therewith may be properly conducted at all times; provided that, subject to Section 6.3.1 and all other terms of this Agreement, nothing in this Section 6.2.6 shall prevent the Borrower or any of its Subsidiaries from discontinuing the operation and maintenance of any of its properties (x) if such discontinuance is, in the judgment of the Borrower or such Subsidiary, desirable in the conduct of its business or (y) if such discontinuance or disposal could not reasonably be expected to hav e a Material Adverse Effect.

            6.2.7         Additional Guarantors. On the date on which any Material Subsidiary which is not an original signatory to the Subsidiary Guaranty delivers to the Administrative Agent a counterpart of the Subsidiary Guaranty, the Borrower will cause such Material Subsidiary to deliver such supporting documents (including documents of the types described in clauses (i), (ii), (iii) and (vi) of Section 4.1(b)) as the Administrative Agent or any Lender may reasonably request in support thereof.

            6.2.8         Material Subsidiary Guarantors. The Borrower will cause each Material Subsidiary (excluding AWG) to be a Guarantor. To the extent that the aggregate net book value of the assets owned by Guarantors as of the last day of the most recent fiscal quarter is less than the lesser of (i) $600,000,000 and (ii) 80% of the aggregate net book value of the assets owned by the Borrower and its consolidated Subsidiaries (excluding AWG) as of such day, the Borrower shall promptly cause one or more Subsidiaries that are not Material Subsidiaries having assets with an aggregate net book value greater than or equal to such deficiency to become Guarantors. For the avoidance of doubt, AWG shall not be required to be a Guarantor.

            6.3            Negative Covenants. The Borrower will not, nor (where applicable) will it permit any Subsidiary to:

            6.3.1        Merger and Sale of Assets. Merge or consolidate with or into any other Person or lease, sell or otherwise dispose of all, or substantially all, of its property, assets (other than inventory, physical assets sold in the ordinary course of business or obsolete, worn out or excess property) or business to any other Person except that:

            (1)            the Borrower may merge or consolidate with or sell all of its assets to any other solvent corporation, provided that (i) the surviving, continuing or resulting corporation (if not the Borrower) shall (x) expressly assume by a written instrument reasonably satisfactory to the Administrative Agent and the Lenders (which shall be provided with an opportunity to review and comment upon it prior to the consummation of any transaction) the due and punctual payment of the principal of all Obligations and the due performance and observance of all covenants, conditions and agreements on the part of the Borrower under this Agreement, (y) deliver to the Administrative Agent and the Lenders an opinion of counsel, in form and substance reasonably satisfactory to the Administrative Agent and the Lenders, to the effect that such written instrument has been duly auth orized, executed and delivered by such surviving, continuing or resulting corporation and constitutes a legal, valid and binding instrument enforceable against such surviving, continuing or resulting corporation in accordance with its terms, and to such further effects as the Administrative Agent and the Lenders may reasonably request, and (z) have an investment grade rating from Moody's Investors Service, Inc. and Standard & Poor's Rating Group, (ii) the surviving, continuing or resulting corporation shall be a corporation organized and existing under the laws of the United States of America or any State thereof or the District of Columbia, and (iii) immediately after such merger, consolidation or sale, no Default or Unmatured Default would exist;

            (2)            any Subsidiary may merge into the Borrower or another Subsidiary which is a Wholly-Owned Subsidiary, and may sell, lease or otherwise dispose of any of its assets to the Borrower or another Subsidiary which is a Wholly-Owned Subsidiary;

            (3)            any Subsidiary may merge or consolidate with any entity other than the Borrower or another Subsidiary, provided that (i) the surviving, continuing or resulting entity shall be a Subsidiary, and (ii) immediately after such merger or consolidation, no Default or Unmatured Default would exist; and

            (4)            the Borrower may sell, lease or otherwise dispose of all or any part of its assets to any Person, and any Subsidiary may sell, lease or otherwise dispose of all or any part of its assets to any Person other than the Borrower or another Subsidiary, in each case for a consideration which represents the fair value at the time of such sale or other disposition, provided that immediately after such sale, lease or other disposition, no Default or Unmatured Default would exist; and provided, further, that neither the Borrower nor any Subsidiary shall sell, lease or otherwise dispose of any asset if, after giving effect to such transaction, the aggregate fair market value of all assets sold, leased or otherwise disposed of by the Borrower and its Subsidiaries in any fiscal year of the Borrower would exceed 15% of the Borrower's consolidated asse ts as of the beginning of such fiscal year.

            Without limiting clause (4) above, the Borrower will not permit AWG to (x) cease to be a Subsidiary of the Borrower; or (y) sell all or any Substantial Portion (as defined below) of its assets. For purposes of the foregoing, "Substantial Portion" means, with respect to AWG, assets which (i) represent more than 20% of the consolidated tangible assets of AWG and its Subsidiaries as at the beginning of the fiscal year in which any determination is to be made or (ii) are responsible for more than 20% of the consolidated net earnings of AWG and its Subsidiaries for the fiscal year preceding the fiscal year in which any determination is to be made.

            6.3.2        Liens. Create, incur, assume or suffer to exist any Lien on (a) any Productive Property, (b) any Principal Transmission Facility or (c) any shares of stock of any Subsidiary, except:

                            (i)    Liens for taxes, assessments or governmental charges or levies on its property if the same shall not at the time be delinquent or thereafter can be paid without penalty or, provided the Borrower or any Subsidiary knew or should have known of such Liens, are being actively contested in good faith and by appropriate proceedings and for which adequate reserves shall have been set aside on its books in accordance with Agreement Accounting Principles,

                            (ii)    Liens imposed by law, such as carriers', warehousemen's, operators', royalty, surface damages and mechanics' liens and other similar liens arising in the ordinary course of business which secure payment of obligations not more than 60 days past due or which are being contested in good faith by appropriate proceedings and for which adequate reserves shall have been set aside on its books in accordance with Agreement Accounting Principles,

                            (iii)    Liens incurred in the ordinary course of business (a) arising out of pledges or deposits under workmen's compensation laws, unemployment insurance, old age pensions, or other social security or retirement benefits, or similar legislation, (b) to secure the performance of letters of credit, bids, tenders, sales contracts, leases (including rent security deposits), statutory obligations, surety, appeal and performance bonds, joint operating agreements or other similar agreements and other similar obligations not incurred in connection with the borrowing of money, the obtaining of advances or the payment of the deferred purchase price of property or (c) consisting of deposits which secure public or statutory obligations of the Borrower or any Subsidiary, or surety, custom or appeal bonds to which the Borrower or any Subsidiary is a party, or the payment of contested taxes or import duties of the Borrower or any Subsidiary,

                            (iv)    utility easements, building restrictions and such other encumbrances or charges against real property as are of a nature generally existing with respect to properties of a similar character and which do not in any material way affect the marketability of the same or interfere with the use thereof in the business of the Borrower or the Subsidiaries,

                            (v)    Liens on drilling equipment and facilities in order to secure the financing for the construction of such equipment and facilities not constructed as of the date hereof, provided that such financing is permitted pursuant to Section 6.4,

                            (vi)    attachment, judgment and other similar Liens arising in connection with court proceedings; provided the execution or other enforcement of such Liens is effectively stayed or the claims secured thereby are being actively contested in good faith and by appropriate proceedings; and provided, further, the Borrower or any Subsidiary knew or should have known of such Liens,

                            (vii)    Liens on property of a Subsidiary, provided such Liens secure only obligations owing to the Borrower or a Wholly-Owned Subsidiary,

                            (viii)    purchase money mortgages or other mortgages or other Liens on assets of the Borrower or any Subsidiary securing Indebtedness hereafter incurred by the Borrower or such Subsidiary for the acquisition of such assets, provided no such mortgage or other Lien shall extend to any other property (unless such mortgage or Lien is permitted under another clause of this Section 6.3.2) and the amount thereby secured shall not exceed the purchase price of such asset plus interest, if any, accrued thereon and shall be permitted pursuant to Section 6.4,

                            (ix)    Liens on property hereafter acquired (including shares of stock hereafter acquired of any Person (including any Person in which the Borrower or any Subsidiary already owns an interest)) existing at the time of acquisition and liens assumed by the Borrower or a Subsidiary as a result of a merger of another entity into the Borrower or a Subsidiary or the acquisition by the Borrower or a Subsidiary of the assets and liabilities of another entity, provided that in each case such Liens shall not have been created in anticipation of such transaction,

                            (x)    any right which any municipal or governmental body or agency may have by virtue of any franchise, license, contract or statute to purchase, or designate a purchaser of or order the sale of, any property of the Borrower or any Subsidiary upon payment of reasonable compensation therefor or to terminate any franchise, license or other rights or to regulate the property and business of the Borrower or any Subsidiary,

                            (xi)    easements or reservations in respect of any property of the Borrower or any Subsidiary for the purpose of rights-of-way and similar purposes, reservations, restrictions, covenants, party wall agreements, conditions of record and other encumbrances (other than to secure the payment of money) and minor irregularities or deficiencies in the record and evidence of title, which in the reasonable opinion of the Borrower (at the time of the acquisition of the property affected or subsequently) will not interfere in any material way with the proper operation and development of the property affected thereby,

                            (xii)    Liens existing on the date hereof and set forth on Schedule 5.18,

                            (xiii)    Liens on property to secure all or any part of the cost of construction, alteration or repair of any building, equipment or other improvement on all or any part of such property, including any pipeline, or to secure any Indebtedness incurred prior to, at the time of, or within 360 days after, the completion of such construction, alteration or repair to provide funds for the payment of all or any part of such cost,

                            (xiv)    rights of lessors under oil, gas or mineral leases arising in the ordinary course of business,

                            (xv)    any extension, renewal or replacement (or successive extensions, renewals or replacements), in whole or in part, of any Lien referred to in the foregoing clauses; provided that the principal amount of Indebtedness secured thereby shall not exceed the principal amount of Indebtedness so secured at the time of such extension, renewal or replacement and such extension, renewal or replacement Lien shall be limited to all or a part of the property which secured the Lien so extended, renewed or replaced (plus improvements on such property),

                            (xvi)    Liens which may hereafter be attached to undeveloped real estate not containing oil or gas reserves presently owned by the Borrower in the ordinary course of the Borrower's real estate sales, development and rental activities,

                            (xvii)    Liens not otherwise permitted by the foregoing clauses of this Section 6.3.2 securing Indebtedness in an aggregate principal amount which, at the time of incurrence, does not exceed 5% of Stockholders' Equity as of the end of the most recently completed fiscal quarter of the Borrower as shown on the consolidated balance sheet related thereto, and

                            (xviii)    Liens not otherwise permitted by the foregoing clauses of this Section 6.3.2 in an aggregate principal amount in excess of 5% of Stockholders' Equity; provided that at the time such Lien is created, the Obligations will be secured pari passu with the obligations such Lien is securing pursuant to documentation in form and substance satisfactory to the Administrative Agent and the Lenders (drafts of which documentation shall be furnished to the Administrative Agent and the Lenders sufficiently in advance to provide the Administrative Agent and the Lenders with an opportunity to review and comment upon it prior to the granting of any such Lien).

            6.3.3        Investments. Make, incur, assume or suffer to exist any Investment in any other Person, except (without duplication) the following:

            (a)            Cash Equivalent Investments;

            (b)            Investments existing on the date of this Agreement;

            (c)            in the ordinary course of business, Investments by the Borrower in any Subsidiary or by any Subsidiary in the Borrower or any other Subsidiary;

            (d)            bank deposits in the ordinary course of business;

            (e)            Investments in Persons involved in oil and gas exploration and production and related businesses in the ordinary course of business consistent with past practice; and

            (f)            other Investments in an aggregate amount not at any time exceeding $5,000,000.

            6.3.4        Indebtedness of Subsidiaries. Permit the aggregate outstanding principal amount of all Indebtedness of:

                            (a)    AWG and its Subsidiaries (excluding (i) Indebtedness outstanding on the date hereof and renewals, extensions and refinancings thereof so long as the principal amount thereof is not increased and (ii) Indebtedness to the Borrower or another Wholly-Owned Subsidiary) to exceed $20,000,000; or

                            (b)    all other Subsidiaries (excluding (i) Indebtedness outstanding on the date hereof and renewals, extensions and refinancings thereof so long as the principal amount thereof is not increased, (ii) Indebtedness to the Borrower or another Wholly-Owned Subsidiary and (iii) Indebtedness under the Subsidiary Guaranty) to exceed $50,000,000.

            6.4            Financial Covenants. The Borrower will not:

            6.4.1        Debt to Capitalization Ratio. Permit the Debt to Capitalization Ratio at any time to exceed 0.60 to 1.0.

            6.4.2        Interest Coverage Ratio. Permit the Interest Coverage Ratio as of the last day of any fiscal quarter of the Borrower to be less than 3.5 to 1.0.

            6.4.3        Net Worth. Permit Stockholder's Equity at any time to be less than the sum of (a) $300,000,000 plus (b) 50% of consolidated net income of the Borrower and its Subsidiaries for each fiscal year of the Borrower (and, if applicable, the completed portion of the then-current fiscal year for which the Borrower has delivered financial statements pursuant to Section 6.1(b)) ending after the date of this Agreement, without giving effect to any loss in any such fiscal year (or, if applicable, the completed portion of the then-current fiscal year), excluding, in the case of the Borrower's 2004 fiscal year, the first three fiscal quarters of such year, plus (c) 75% of the net proceeds of any Equity Issuance after the date of this Agreement.

ARTICLE VII

DEFAULTS

            7.1            Events of Default. The occurrence and continuance of any one or more of the following events shall constitute a Default:

            7.1.1        Representations and Warranties. Any representation or warranty made or deemed made by or on behalf of the Borrower to the Administrative Agent or any Lender in this Agreement or in any certificate or instrument delivered in connection herewith shall be materially false as of the date on which made.

            7.1.2        Payment Default. Nonpayment of any principal, Reimbursement Obligation, interest, fee or other obligation hereunder within five days after the same becomes due.

            7.1.3        Breach of Certain Covenants. The breach by the Borrower of (i) any of the terms or provisions of Section 6.1(i), 6.3.1 or 6.4 or (ii) any term or provision of Section 6.3.2 that is not remedied within ten days after written notice from the Administrative Agent.

            7.1.4        Other Breach of this Agreement. The breach by the Borrower (other than a breach which constitutes a Default under Section 7.1.1, 7.1.2 or 7.1.3) of any term or provision of this Agreement which is not remedied within 30 days after written notice from the Administrative Agent.

            7.1.5        ERISA. An event or condition specified in Section 6.1(d) shall occur or exist with respect to any Plan or any Multiemployer Plan and, as a result or such event or condition, together with all other such events or conditions then outstanding, the Borrower or any member or the Controlled Group shall incur, or shall be reasonably likely to incur, a liability to any Plan, any Multiemployer Plan or the PBGC (or any combination of the foregoing) that would have a Material Adverse Effect.

            7.1.6        Cross-Default. Failure of the Borrower or any Material Subsidiary to pay any Indebtedness when due (after giving effect to any period of grace set forth in any agreement under which such Indebtedness was created or is governed); or the default by the Borrower or any Material Subsidiary in the performance of any other term, provision or condition contained in any agreement under which any of their respective Indebtedness was created or is governed, the effect of which is to cause, or to permit the holder or holders of such Indebtedness to cause, such Indebtedness to become due prior to its stated maturity; or any Indebtedness of the Borrower or any Material Subsidiary shall become due and payable or be required to be prepaid (other than by a regularly scheduled payment) prior to the stated maturity thereof; provided that, in each case, the principal amount of Ind ebtedness as to which such a payment default shall occur and be continuing, or such a failure to perform or other event causing or permitting acceleration shall occur and be continuing, exceeds $10,000,000.

            7.1.7        Voluntary Bankruptcy, etc. The Borrower, or any Material Subsidiary or a Material Group of Subsidiaries shall (i) not pay, or admit in writing its inability to pay, its debts generally as they become due, (ii) make an assignment for the benefit of creditors, (iii) apply for, seek, consent to, or acquiesce in, the appointment of a receiver, custodian, trustee, examiner, liquidator or similar official for the Borrower, such Material Subsidiary or such Material Group of Subsidiaries, (iv) institute any proceeding seeking an order for relief under the Federal bankruptcy laws as now or hereafter in effect or seeking to adjudicate it a bankrupt or insolvent, or seeking dissolution, winding up, liquidation, reorganization, arrangement, adjustment or composition of it or its debts under any law relating to bankruptcy, insolvency or reorganization or relief of debtors or (v) ta ke any action to authorize or effect any of the foregoing actions set forth in this Section 7.1.7.

            7.1.8        Involuntary Bankruptcy, etc. Without the application, approval or consent of the Borrower, the applicable Material Subsidiary or the applicable Material Group of Subsidiaries, a receiver, trustee, examiner, liquidator or similar official shall be appointed for the Borrower, any Material Subsidiary or such Material Group of Subsidiaries, or a proceeding described in Section 7.1.7(iv) shall be instituted against the Borrower, any Material Subsidiary or such Material Group of Subsidiaries and such appointment continues undischarged or such proceeding continues undismissed or unstayed for a period of 60 consecutive days.

            7.1.9        Judgments. The Borrower or any Material Subsidiary shall fail within 30 days to pay, bond or otherwise discharge any final judgment or order for the payment of money in excess of $5,000,000, which is not stayed on appeal or otherwise being appropriately contested in good faith.

            7.1.10       Environmental Matters. The Borrower, any Material Subsidiary or any Material Group of Subsidiaries shall suffer any adverse determination pertaining to the release by the Borrower, any Material Subsidiary or any other Person of any toxic or hazardous waste or substance into the environment, or any violation of any federal, state or local environmental, health or safety law or regulation, which, in either case, could reasonably be expected to have a Material Adverse Effect.

            7.1.11        Subsidiary Guaranty. The Subsidiary Guaranty shall fail to remain in full force or effect or any action shall be taken to discontinue or to assert the invalidity or unenforceability of the Subsidiary Guaranty, or any Guarantor shall deny that it has any further liability under the Subsidiary Guaranty or shall give notice to such effect (excluding any Guarantor which ceases to be a Subsidiary as a result of a transaction permitted by this Agreement).

ARTICLE VIII

ACCELERATION, WAIVERS, AMENDMENTS AND REMEDIES;
RELEASES OF GUARANTORS

            8.1            Acceleration. If any Default described in Section 7.1.6 or 7.1.7 occurs with respect to the Borrower, the obligations of the Lenders to make Loans hereunder and the obligation and power of the Issuer to issue Letters of Credit shall automatically terminate, the Obligations shall immediately become due and payable without any election or action on the part of the Administrative Agent or any Lender and the Borrower will become immediately obligated, without any further notice, act or demand, to pay to the Administrative Agent an amount in immediately available funds, which funds shall be held in the LC Collateral Account, equal to the excess of (i) the amount of LC Obligations at such time over (ii) the amount on deposit in the LC Collateral Account at such time which is free and clear of all rights and claims of third parties and has not been applied against the Obligations (such difference, the "Collateral Shortfall Amount"). If any other Default occurs, the Required Lenders (or the Administrative Agent with the consent of the Required Lenders) may (x) terminate or suspend the obligations of the Lenders to make Loans hereunder and the obligation and power of the Issuer to issue Letters of Credit, or declare the Obligations to be due and payable, or both, whereupon the Obligations shall become immediately due and payable, without presentment, demand, protest or notice of any kind, all of which the Borrower hereby expressly waives, and (y) upon notice to the Borrower and in addition to the continuing right to demand payment of all amounts payable under this Agreement, make demand on the Borrower to pay, and the Borrower will, forthwith upon such demand and without any further notice or act, pay to the Administrative Agent in immediately available funds the Collateral Shortfall Amount, which funds shall be deposited in the LC Collatera l Account.

            If, within 30 days after acceleration of the maturity of the Obligations or termination of the obligations of the Lenders to make Loans hereunder as a result of any Default (other than any Default as described in Section 7.1.6 or 7.1.7 with respect to the Borrower) and before any judgment or decree for the payment of the Obligations due shall have been obtained or entered, the Required Lenders (in their sole discretion) shall so direct, the Administrative Agent shall, by notice to the Borrower, rescind and annul such acceleration and/or termination.

            8.2            Amendments. Subject to the provisions of this Article VIII, the Required Lenders (or the Administrative Agent with the consent in writing of the Required Lenders) and the Borrower may enter into agreements supplemental hereto for the purpose of adding to or modifying any provision in any Loan Document or changing in any manner the rights of the Lenders or the Borrower hereunder or waiving any Default hereunder; provided that no such supplemental agreement shall, without the consent of all of the Lenders:

            (i)            Extend the final maturity of any Loan or Reimbursement Obligation or forgive all or any portion of the principal amount thereof, or reduce the rate or extend the time of payment of interest or fees thereon or extend the expiry date of any Letter of Credit to a date after the scheduled Termination Date.

            (ii)            Reduce the percentage specified in the definition of Required Lenders.

            (iii)            Extend the Termination Date or, except pursuant to Section 2.6.3, increase the amount of the Aggregate Commitment or of the Commitment of any Lender hereunder, or permit the Borrower to assign its rights under this Agreement.

            (iv)            Amend the last paragraph of Section 6.3.1 or this Section 8.2.

            (v)            Release any Guarantor from its obligations under the Subsidiary Guaranty (except as provided in Section 8.4).

No amendment of any provision of this Agreement relating to the Administrative Agent shall be effective without the written consent of the Administrative Agent. No amendment of any provision of this Agreement relating to the Issuer shall be effective without the written consent of the Issuer. No amendment of any provision of this Agreement relating to the Swing Line Lender shall be effective without the written consent of the Swing Line Lender. The Administrative Agent may waive payment of the fee required under Section 12.3.2 without obtaining the consent of any other party to this Agreement.

            8.3            Preservation of Rights. No delay or omission of the Lenders or the Administrative Agent to exercise any right under the Loan Documents shall impair such right or be construed to be a waiver of any Default or an acquiescence therein, and the making of a Credit Extension notwithstanding the existence of a Default or the inability of the Borrower to satisfy the conditions precedent to such Credit Extension shall not constitute any waiver or acquiescence. Any single or partial exercise of any such right shall not preclude other or further exercise thereof or the exercise of any other right, and no waiver, amendment or other variation of the terms, conditions or provisions of the Loan Documents whatsoever shall be valid unless in writing signed by the Lenders required pursuant to Section 8.2, and then only to the extent in such writing specifica lly set forth. All remedies contained in the Loan Documents or by law afforded shall be cumulative and all shall be available to the Administrative Agent and the Lenders until the Obligations have been paid in full.

            8.4            Releases of Guarantors. The Lenders hereby authorize the Administrative Agent to, and the Administrative Agent agrees that it will, release any Guarantor from its obligations under the Subsidiary Guaranty so long as (a) no Default or Unmatured Default exists or will result therefrom and (b) either (i) such Guarantor ceases to be a Subsidiary as a result of a transaction permitted hereunder or (ii) the Borrower requests such release in writing and, after giving effect thereto, the Borrower will be in compliance with Section 6.2.7. In determining whether any such release is permitted, the Administrative Agent may rely on a certificate from the Borrower. The Administrative Agent shall promptly notify the Lenders of any such release.

ARTICLE IX

GENERAL PROVISIONS

            9.1            Survival of Representations. All representations and warranties of the Borrower contained in this Agreement shall survive the making of the Credit Extensions.

            9.2            Governmental Regulation. Anything contained in this Agreement to the contrary notwithstanding, no Lender shall be obligated to extend credit to the Borrower in violation of any limitation or prohibition provided by any applicable statute or regulation.

            9.3            Headings. Section headings in the Loan Documents are for convenience of reference only, and shall not govern the interpretation of any of the provisions of the Loan Documents.

            9.4            Entire Agreement. The Loan Documents embody the entire agreement and understanding among the Borrower, the Administrative Agent and the Lenders and supersede all prior agreements and understandings among the Borrower, the Administrative Agent and the Lenders relating to the subject matter thereof.

            9.5            Several Obligations; Benefits of this Agreement. The respective obligations of the Lenders hereunder are several and not joint and no Lender shall be the partner or agent of any other (except to the extent to which the Administrative Agent is authorized to act as such). The failure of any Lender to perform any of its obligations hereunder shall not relieve any other Lender from any of its obligations hereunder. This Agreement shall not be construed so as to confer any right or benefit upon any Person other than the parties to this Agreement and their respective successors and assigns, provided that the parties hereto expressly agree that each Arranger shall enjoy the benefits of the provisions of Sections 9.6, 9.10 and 10.11 to the extent specifically set forth therein and shall have the right to enforce such provisions on its own behalf and in its own name to the same extent as if it were a party to this Agreement.

            9.6            Expenses; Indemnification. (i) The Borrower shall reimburse the Administrative Agent and JPMorgan Securities, Inc. for all reasonable costs, internal charges and out-of-pocket expenses (including, subject to any limit on fees which is separately agreed to, reasonable attorneys' fees and reasonable time charges of attorneys for the Administrative Agent, which attorneys may be employees of the Administrative Agent) paid or incurred by the Administrative Agent or JPMorgan Securities, Inc. in connection with the preparation, negotiation, execution, delivery, syndication, review, amendment, modification, and administration of the Loan Documents. The Borrower also agrees to reimburse the Administrative Agent, the Arrangers and the Lenders for all reasonable costs, internal charges and out-of-pocket expenses (including reasonable attorneys' fees and reasonab le time charges of attorneys for the Administrative Agent, the Arrangers and the Lenders, which attorneys may be employees of the Administrative Agent, either Arranger or any Lender) paid or incurred by the Administrative Agent, either Arranger or any Lender in connection with the collection and enforcement of the Loan Documents.

                            (ii)    The Borrower hereby further agrees to indemnify the Administrative Agent, the Arrangers, each Lender, their respective affiliates, and each of their directors, officers and employees against all losses, claims, damages, penalties, judgments, liabilities and reasonable expenses (including all reasonable expenses of litigation or preparation therefor whether or not the Administrative Agent, either Arranger, any Lender or any affiliate is a party thereto) which any of them may pay or incur arising out of or relating to this Agreement, the other Loan Documents, the transactions contemplated hereby or the direct or indirect application or proposed application of the proceeds of any Loan hereunder except to the extent that they are determined in a final non-appealable judgment by a court of competent jurisdiction to have resulted from the gross negligence or willful misconduct of the party seeking indemnification. The obligations of the Borrower under this Section 9.6 shall survive the termination of this Agreement.

            9.7            Numbers of Documents. All statements, notices, closing documents, and requests hereunder shall be furnished to the Administrative Agent with sufficient counterparts so that the Administrative Agent may furnish one to each of the Lenders.

            9.8            Accounting. Except as provided to the contrary herein, all accounting terms used herein shall be interpreted and all accounting determinations hereunder shall be made in accordance with Agreement Accounting Principles.

            9.9            Severability of Provisions. Any provision in any Loan Document that is held to be inoperative, unenforceable, or invalid in any jurisdiction shall, as to that jurisdiction, be inoperative, unenforceable, or invalid without affecting the remaining provisions in that jurisdiction or the operation, enforceability, or validity of that provision in any other jurisdiction, and to this end the provisions of all Loan Documents are declared to be severable.

            9.10        Nonliability of Lenders. The relationship between the Borrower on the one hand and the Lenders and the Administrative Agent on the other hand shall be solely that of borrower and lender. None of the Administrative Agent, either Arranger or any Lender shall have any fiduciary responsibilities to the Borrower. None of the Administrative Agent, either Arranger or any Lender undertakes any responsibility to the Borrower to review or inform the Borrower of any matter in connection with any phase of the Borrower's business or operations. The Borrower agrees that, except as otherwise expressly provided in this Agreement, none of the Administrative Agent, either Arranger or any Lender shall have liability to the Borrower (whether sounding in tort, contract or otherwise) for losses suffered by the Borrower in connection with, arising out of, or in any way related to, the transac tions contemplated and the relationship established by the Loan Documents, or any act, omission or event occurring in connection therewith, unless it is determined in a final non-appealable judgment by a court of competent jurisdiction that such losses resulted from the gross negligence or willful misconduct of the party from which recovery is sought. None of the Administrative Agent, either Arranger or any Lender shall have any liability with respect to, and the Borrower hereby waives, releases and agrees not to sue for, any special, indirect or consequential damages suffered by the Borrower in connection with, arising out of, or in any way related to the Loan Documents or the transactions contemplated thereby.

            9.11        Confidentiality. Each Lender agrees to hold any confidential information which it may receive from the Borrower pursuant to this Agreement in confidence, except for disclosure (i) to the extent permitted by law or regulation, to its Affiliates and to other Lenders and their respective Affiliates, (ii) to legal counsel, accountants, and other professional advisors to such Lender or to a Transferee, (iii) to regulatory officials, (iv) to any Person as required by law, regulation, or legal process, (v) to any Person in connection with any legal proceeding to which such Lender is a party to the extent required by law, regulation or legal process, (vi) permitted by Section 12.4, (vii) to rating agencies if required by such agencies in connection with a rating relating to the Advances hereunder, and (viii) to the extent required in connection with the exercise of any r emedy or any enforcement of this Agreement by such Lender or the Administrative Agent.

            9.12        Nonreliance. Each Lender hereby represents that it is not relying on or looking to any Margin Stock for the repayment of the Loans provided for herein.

            9.13        Disclosure. The Borrower and each Lender hereby (i) acknowledge and agree that JPMorgan and/or its Affiliates from time to time may hold investments in, make other loans to or have other relationships with the Borrower and its Affiliates, and (ii) waive any liability of JPMorgan or such Affiliate of JPMorgan to the Borrower or any Lender, respectively, arising out of or resulting from such investments, loans or relationships other than liabilities arising out of the gross negligence or willful misconduct of JPMorgan or its Affiliates.

    ARTICLE X

THE ADMINISTRATIVE AGENT

            10.1            Appointment; Nature of Relationship. JPMorgan is hereby appointed by each of the Lenders as the Administrative Agent hereunder and under each other Loan Document, and each of the Lenders irrevocably authorizes the Administrative Agent to act as the contractual representative of such Lender with the rights and duties expressly set forth herein and in the other Loan Documents. The Administrative Agent agrees to act as Administrative Agent upon the express conditions contained in this Article X. Notwithstanding the use of the defined term "Administrative Agent," it is expressly understood and agreed that the Administrative Agent shall not have any fiduciary responsibilities to any Lender by reason of this Agreement or any other Loan Document and that Administrative Agent is merely acting as the contractual representative of the Lenders wi th only those duties as are expressly set forth in this Agreement and the other Loan Documents. In its capacity as the Administrative Agent, (i) the Administrative Agent does not assume any fiduciary duties to any of the Lenders, (ii) the Administrative Agent is a "representative" of the Lenders within the meaning of Section 9-105 of the Uniform Commercial Code and (iii) the Administrative Agent is acting as an independent contractor, the rights and duties of which are limited to those expressly set forth in this Agreement and the other Loan Documents. Each of the Lenders hereby agrees to assert no claim against the Administrative Agent on any agency theory or any other theory of liability for breach of fiduciary duty, all of which claims each Lender hereby waives.

            10.2            Powers. The Administrative Agent shall have and may exercise such powers under the Loan Documents as are specifically delegated to the Administrative Agent by the terms of each thereof, together with such powers as are reasonably incidental thereto. The Administrative Agent shall not have any implied duties to the Lenders, or any obligation to the Lenders to take any action thereunder except any action specifically provided by the Loan Documents to be taken by the Administrative Agent.

            10.3            General Immunity. Neither the Administrative Agent nor any of the Administrative Agent's directors, officers, agents or employees shall be liable to the Borrower, the Lenders or any Lender for any action taken or omitted to be taken by it or them hereunder or under any other Loan Document or in connection herewith or therewith except to the extent such action or inaction is determined in a final non-appealable judgment by a court of competent jurisdiction to have arisen from the gross negligence or willful misconduct of such Person.

            10.4            No Responsibility for Loans, Recitals, etc. Neither the Administrative Agent nor any of the Administrative Agent's directors, officers, agents or employees shall be responsible for or have any duty to ascertain, inquire into, or verify (a) any statement, warranty or representation made in connection with any Loan Document or any borrowing hereunder; (b) the performance or observance of any of the covenants or agreements of any obligor under any Loan Document, including any agreement by an obligor to furnish information directly to each Lender; (c) the satisfaction of any condition specified in Article IV, except for the receipt of items required to be delivered solely to Administrative Agent; (d) the existence or possible existence of any Default or Unmatured Default; (e) the validity, enforceability, effectiveness, sufficiency or genuinen ess of any Loan Document or any other instrument or writing furnished in connection therewith; or (f) the financial condition of the Borrower or of any of the Borrower's Subsidiaries. The Administrative Agent shall not have any duty to disclose to the Lenders information that is not required to be furnished by the Borrower to the Administrative Agent at such time, but is voluntarily furnished by the Borrower to the Administrative Agent (either in its capacity as the Administrative Agent or in its individual capacity).

            10.5            Action on Instructions of Lenders. The Administrative Agent shall in all cases be fully protected in acting, or in refraining from acting, hereunder and under any other Loan Document in accordance with written instructions signed by the Required Lenders (or, when expressly required hereunder, all of the Lenders), and such instructions and any action taken or failure to act pursuant thereto shall be binding on all of the Lenders. The Lenders hereby acknowledge that the Administrative Agent shall not be under any duty to take any discretionary action permitted to be taken by it pursuant to the provisions of this Agreement or any other Loan Document unless it shall be requested in writing to do so by the Required Lenders. Each Administrative Agent shall be fully justified in failing or refusing to take any action hereunder and under any other Loan D ocument unless it shall first be indemnified to its satisfaction by the Lenders (ratably in accordance with their respective Pro Rata Shares) against any and all liability, cost and expense that it may incur by reason of taking or continuing to take any such action. The Administrative Agent agrees, upon the request of any Lender at any time an Unmatured Default exists, to give a written notice to the Borrower of the type described in Section 7.1.3 or 7.1.4.

            10.6            Employment of Agents and Counsel. The Administrative Agent may execute any of its duties as Administrative Agent hereunder and under any other Loan Document by or through employees, agents, and attorneys-in-fact and shall not be answerable to the Lenders, except as to money or securities received by it or its authorized agents, for the default or misconduct of any such agents or attorneys-in-fact selected by it with reasonable care. The Administrative Agent shall be entitled to advice of counsel concerning the contractual arrangement between the Administrative Agent and the Lenders and all matters pertaining to the Administrative Agent's duties hereunder and under any other Loan Document.

            10.7            Reliance on Documents; Counsel. The Administrative Agent shall be entitled to rely upon any Note, notice, consent, certificate, affidavit, letter, telegram, statement, paper or document believed by it to be genuine and correct and to have been signed or sent by the proper person or persons, and, in respect to legal matters, upon the opinion of counsel selected by the Administrative Agent, which counsel may be employees of the Administrative Agent.

            10.8            Administrative Agent's Reimbursement and Indemnification. The Lenders agree to reimburse and indemnify the Administrative Agent, ratably in accordance with their respective Pro Rata Shares, (i) for any amounts not reimbursed by the Borrower for which the Administrative Agent is entitled to reimbursement by the Borrower under the Loan Documents, (ii) for any other expenses incurred by the Administrative Agent on behalf of the Lenders, in connection with the preparation, execution, delivery, administration and enforcement of the Loan Documents (including for any expenses incurred by the Administrative Agent in connection with any dispute between the Administrative Agent and any Lender or between two or more of the Lenders) and (iii) for any liabilities, obligations, losses, damages, penalties, actions, judgments, suits, costs, expenses or disbursem ents of any kind and nature whatsoever which may be imposed on, incurred by or asserted against the Administrative Agent in any way relating to or arising out of the Loan Documents or any other document delivered in connection therewith or the transactions contemplated thereby (including for any such amounts incurred by or asserted against the Administrative Agent in connection with any dispute between the Administrative Agent and any Lender or between two or more of the Lenders), or the enforcement of any of the terms of the Loan Documents or of any such other documents, provided that (i) no Lender shall be liable to the Administrative Agent for any of the foregoing to the extent any of the foregoing is found in a final non-appealable judgment by a court of competent jurisdiction to have resulted from the gross negligence or willful misconduct of the Administrative Agent and (ii) any indemnification required pursuant to Section 3.5(vii) shall, notwithstanding the provisions of this Section 10.8, be paid by the relevant Lender in accordance with the provisions thereof. The obligations of the Lenders under this Section 10.8 shall survive payment of the Obligations and termination of this Agreement.

            10.9            Notice of Default. The Administrative Agent shall not be deemed to have knowledge or notice of the occurrence of any Default or Unmatured Default hereunder unless the Administrative Agent has received written notice from a Lender or the Borrower referring to this Agreement describing such Default or Unmatured Default and stating that such notice is a "notice of default". In the event that the Administrative Agent receives such a notice, the Administrative Agent shall give prompt notice thereof to the Lenders.

            10.10           Rights as a Lender. In the event the Administrative Agent is a Lender, the Administrative Agent shall have the same rights and powers hereunder and under any other Loan Document with respect to its Commitment and its Loans as any Lender and may exercise the same as though it were not the Administrative Agent, and the term "Lender" or "Lenders" shall, at any time when the Administrative Agent is a Lender, unless the context otherwise indicates, include the Administrative Agent in its individual capacity. The Administrative Agent and its Affiliates may accept deposits from, lend money to, and generally engage in any kind of trust, debt, equity or other transaction, in addition to those contemplated by this Agreement or any other Loan Document, with the Borrower or any of its Subsidiaries in which the Borrower or such Subsidiary is not restricted hereby from engaging with any other Person. The Administrative Agent, in its individual capacity, is not obligated to remain a Lender.

            10.11        Lender Credit Decision. Each Lender acknowledges that it has, independently and without reliance upon the Administrative Agent, either Arranger or any other Lender and based on the financial statements prepared by the Borrower and such other documents and information as it has deemed appropriate, made its own credit analysis and decision to enter into this Agreement and the other Loan Documents. Each Lender also acknowledges that it will, independently and without reliance upon the Administrative Agent, either Arranger or any other Lender and based on such documents and information as it shall deem appropriate at the time, continue to make its own credit decisions in taking or not taking action under this Agreement and the other Loan Documents.

            10.11        Successor Administrative Agent. The Administrative Agent may resign at any time by giving written notice thereof to the Lenders and the Borrower, such resignation to be effective upon the appointment of a successor Administrative Agent, or, if no successor Administrative Agent has been appointed, forty-five days after the retiring Administrative Agent gives notice of its intention to resign. The Administrative Agent may be removed at any time with or without cause by written notice received by the Administrative Agent from the Required Lenders, such removal to be effective on the date specified by the Required Lenders; provided that the Administrative Agent may not be removed unless the Administrative Agent (in its individual capacity) and any affiliate thereof acting as Issuer is relieved of all of its duties as Issuer pursuant to documentation reasonably satis factory to such Person on or prior to the date of such removal. Upon any resignation or removal of the Administrative Agent, the Required Lenders shall have the right (with, so long as no Default or Unmatured Default exists, the consent of the Borrower, which shall not be unreasonably withheld) to appoint, on behalf of the Borrower and the Lenders, a successor Administrative Agent. If no successor Administrative Agent shall have been so appointed by the Required Lenders within thirty days after the resigning Administrative Agent's giving notice of its intention to resign, then the resigning Administrative Agent may appoint, on behalf of the Borrower and the Lenders, a successor Administrative Agent. Notwithstanding the previous sentence, the Administrative Agent may at any time without the consent of any Lender and with the consent of the Borrower, not to be unreasonably withheld or delayed, appoint any of its Affiliates which is a commercial bank as a successor Administrative Agent hereunder. If the Adminis trative Agent has resigned or been removed and no successor Administrative Agent has been appointed, the Lenders may perform all the duties of the Administrative Agent hereunder and the Borrower shall make all payments in respect of the Obligations to the applicable Lender and for all other purposes shall deal directly with the Lenders. No successor Administrative Agent shall be deemed to be appointed hereunder until such Administrative Agent has accepted the appointment. Any such successor Administrative Agent shall be a commercial bank having capital and retained earnings of at least $100,000,000. Upon the acceptance of any appointment as Administrative Agent hereunder by a successor Administrative Agent, such successor Administrative Agent shall thereupon succeed to and become vested with all the rights, powers, privileges and duties of the resigning or removed Administrative Agent. Upon the effectiveness of the resignation or removal of the Administrative Agent, the resigning or removed Administrative Ag ent shall be discharged from its duties and obligations hereunder and under the Loan Documents. After the effectiveness of the resignation or removal of the Administrative Agent, the provisions of this Article X shall continue in effect for the benefit of the such Person in respect of any actions taken or omitted to be taken by such Person while such Person was acting as Administrative Agent hereunder and under the other Loan Documents. In the event that there is a successor to the Administrative Agent by merger, or the Administrative Agent assigns its duties and obligations to an Affiliate pursuant to this Section 10.12, then the term "Prime Rate" as used in this Agreement shall mean the prime rate, base rate or other analogous rate of the new Administrative Agent.

            10.13        Delegation to Affiliates. The Borrower and the Lenders agree that the Administrative Agent may delegate any of its duties under this Agreement to any of its respective Affiliates. Any such Affiliate (and such Affiliate's directors, officers, agents and employees) which performs duties in connection with this Agreement shall be entitled to the same benefits of the indemnification, waiver and other protective provisions to which the Administrative Agent is entitled under Articles IX and X.

            10.14        Other Agents. No Lender identified on the cover page or the signature pages of this Agreement or otherwise herein, or in any amendment hereof or other document related hereto, as being the "Syndication Agent", a "Co-Documentation Agent", a "Managing Agent" or a "Co-Agent" shall have any right, power, obligation, liability, responsibility or duty under this Agreement in such capacity other than those applicable to all Lenders. Each Lender acknowledges that it has not relied, and will not rely, on any Person so identified in deciding to enter into this Agreement or in taking or refraining from taking any action hereunder or pursuant hereto.

ARTICLE XI

SETOFF; RATABLE PAYMENTS

            11.1            Setoff. In addition to, and without limitation of, any rights of the Lenders under applicable law, if the Borrower becomes insolvent, however evidenced, or any Default occurs, any and all deposits (including all account balances, whether provisional or final and whether or not collected or available) and any other Indebtedness at any time held or owing by any Lender or any Affiliate of any Lender to or for the credit or account of the Borrower may be offset and applied toward the payment of the Obligations owing to such Lender, whether or not the Obligations, or any part thereof, shall then be due.

            11.2            Ratable Payments. If any Lender, whether by setoff or otherwise, has payment made to it upon its Loans or its participation in Letters of Credit or Swing Line Loans (other than payments received pursuant to Section 3.1, 3.2, 3.4 or 3.5) in a greater proportion than that received by any other Lender, such Lender agrees, promptly upon demand, to purchase a portion of the Loans (or participations in Letters of Credit and Swing Line Loans) held by the other Lenders so that after such purchase each Lender will hold its Pro Rata Share of all Loans (and participations in Letters of Credit and Swing Line Loans). If any Lender, whether in connection with setoff or amounts which might be subject to setoff or otherwise, receives collateral or other protection for its Obligations or such amounts which may be subject to setoff, suc h Lender agrees, promptly upon demand, to take such action necessary such that all Lenders share in the benefits of such collateral ratably in proportion to their respective Pro Rata Shares. In case any such payment is disturbed by legal process, or otherwise, appropriate further adjustments shall be made.

ARTICLE XII

BENEFIT OF AGREEMENT; ASSIGNMENTS; PARTICIPATIONS

            12.1            Successors and Assigns. The terms and provisions of the Loan Documents shall be binding upon and inure to the benefit of the Borrower and the Lenders and their respective successors and assigns, except that (i) the Borrower shall not have the right to assign its rights or obligations under the Loan Documents and (ii) any assignment by any Lender must be made in compliance with Section 12.3. The parties to this Agreement acknowledge that clause (ii) of the foregoing sentence relates only to absolute assignments and does not prohibit assignments creating security interests, including any pledge or assignment by any Lender of all or any portion of its rights under this Agreement and any Note to a Federal Reserve Bank; provided that no such pledge or assignment creating a security interest shall release the transferor Lender from its obligations hereunder unless and until the parties thereto have complied with the provisions of Section 12.3. The Administrative Agent may treat the Person which made any Loan or which holds any Note as the owner thereof for all purposes hereof unless and until such Person complies with Section 12.3; provided that the Administrative Agent may in its discretion (but shall not be required to) follow instructions from the Person which made any Loan or which holds any Note to direct payments relating to such Loan or Note to another Person. Any assignee of the rights to any Loan or any Note agrees by acceptance of such assignment to be bound by all the terms and provisions of the Loan Documents. Any request, authority or consent of any Person, who at the time of making such request or giving such authority or consent is the owner of the rights to any Loan (whether or not a Note has been issued in evidence thereof), shall be conclusive and binding on any subsequent holder or assignee of the rights to such Loan.

            12.2           Participations.

            12.2.1        Permitted Participants; Effect. Any Lender may, in the ordinary course of its business and in accordance with applicable law, at any time sell to one or more banks or other entities ("Participants") participating interests in any Loan owing to such Lender, any Note held by such Lender, any Commitment of such Lender or any other interest of such Lender under the Loan Documents. In the event of any such sale by a Lender of participating interests to a Participant, such Lender's obligations under the Loan Documents shall remain unchanged, such Lender shall remain solely responsible to the other parties hereto for the performance of such obligations, such Lender shall remain the owner of its Loans and the holder of any Note issued to it in evidence thereof for all purposes under the Loan Documents, all amounts payable by the Borrower under this Agreement (including under A rticle III) shall be determined as if such Lender had not sold such participating interests, and the Borrower and the Administrative Agent shall continue to deal solely and directly with such Lender in connection with such Lender's rights and obligations under the Loan Documents.

            12.2.2        Voting Rights. Each Lender shall retain the sole right to approve, without the consent of any Participant, any amendment, modification or waiver of any provision of the Loan Documents other than any amendment, modification or waiver with respect to any Credit Extension or Commitment in which such Participant has an interest which forgives principal, interest or fees or reduces the interest rate or fees payable with respect to any such Credit Extension or Commitment, extends the Termination Date, postpones any date fixed for any regularly scheduled payment of principal of, or interest or fees on, any such Credit Extension or Commitment or releases any Guarantor from its obligations under the Subsidiary Guaranty (except as provided in Section 8.4).

            12.3            Assignments.

            12.3.1        Permitted Assignments. Any Lender may, in the ordinary course of its business and in accordance with applicable law, at any time assign to one or more banks or other entities ("Purchasers") all or any part of its rights and obligations under the Loan Documents. Such assignment shall be substantially in the form of Exhibit C or in such other form as may be agreed to by the parties thereto. The consents of the Borrower, the Administrative Agent, the Issuer and the Swing Line Lender (which consents shall not be unreasonably withheld or delayed by any such party) shall be required prior to an assignment becoming effective with respect to a Purchaser which is not a Lender or an Affiliate thereof; provided that if a Default has occurred and is continuing, the consent of the Borrower shall not be required; provided, further, that no assignment shall b e permitted if, as of the date thereof, any event or circumstance exists which would result in the Borrower being obligated to pay any greater amount hereunder to the Purchaser than the Borrower is obligated to pay to the assigning Lender. Each such assignment with respect to a Purchaser which is not a Lender or an Affiliate thereof shall (unless each of the Borrower and the Administrative Agent otherwise consents) be in an amount not less than the lesser of (i) $5,000,000 or (ii) the remaining amount of the assigning Lender's Commitment (calculated as at the date of such assignment) or outstanding Loans and participations in Letters of Credit and Swing Line Loans (if the Commitments have been terminated).

            12.3.2        Effect; Effective Date. Upon (i) delivery to the Administrative Agent of an assignment, together with any consents required by Section 12.3.1, and (ii) payment of a $3,500 fee to the Administrative Agent for processing such assignment (unless such fee is waived by the Administrative Agent), such assignment shall become effective on the effective date specified in such assignment. The assignment shall contain a representation by the Purchaser to the effect that none of the consideration used to make the purchase of the Commitment and Loans under the applicable assignment agreement constitutes "plan assets" as defined under ERISA and that the rights and interests of the Purchaser in and under the Loan Documents will not be "plan assets" under ERISA. On and after the effective date of such assignment, such Purchaser shall for all purposes be a Lender party to this Agr eement and any other Loan Document executed by or on behalf of the Lenders and shall have all the rights and obligations of a Lender under the Loan Documents, to the same extent as if it were an original party hereto, and no further consent or action by the Borrower, the Lenders or the Administrative Agent shall be required to release the transferor Lender with respect to the percentage of the Aggregate Commitment and Loans assigned to such Purchaser. Upon the consummation of any assignment to a Purchaser pursuant to this Section 12.3.2, the transferor Lender, the Administrative Agent and the Borrower shall, if the transferor Lender or the Purchaser desires that its Loans be evidenced by Notes, make appropriate arrangements so that new Notes or, as appropriate, replacement Notes are issued to such transferor Lender and new Notes or, as appropriate, replacement Notes, are issued to such Purchaser, in each case in principal amounts reflecting their respective Commitments, as adjusted pursuant to such as signment.

            12.4            Dissemination of Information. The Borrower authorizes each Lender to disclose to any Participant or Purchaser or any other Person acquiring an interest in the Loan Documents by operation of law (each a "Transferee") and any prospective Transferee any and all information in such Lender's possession concerning the creditworthiness of the Borrower and its Subsidiaries, including any information contained in any Reports; provided that each Transferee and prospective Transferee agrees to be bound by Section 9.11 of this Agreement.

            12.5            Tax Treatment. If any interest in any Loan Document is transferred to any Transferee which is organized under the laws of any jurisdiction other than the United States or any State thereof, the transferor Lender shall cause such Transferee, concurrently with the effectiveness of such transfer, to comply with the provisions of Section 3.5(iv) and the Borrower shall not be required to indemnify such Transferee pursuant to Section 3.5 hereof for any Taxes withheld as a result of the failure of the Transferee to so comply.

ARTICLE XIII

NOTICES

            Except as otherwise permitted by Section 2.14 with respect to borrowing notices, all notices, requests and other communications to any party hereunder shall be in writing (including electronic transmission, facsimile transmission or similar writing) and shall be given to such party: (x) in the case of the Borrower or the Administrative Agent, at its address or facsimile number set forth on the signature pages hereof, (y) in the case of any Lender, at its address or facsimile number set forth in its Administrative Questionnaire or in the assignment agreement pursuant to which it became a Lender or (z) in the case of any party, at such other address or facsimile number as such party may hereafter specify for the purpose by notice to the Administrative Agent and the Borrower in accordance with the provisions of this Article XIII Each such notice, request or other communication shall be effective (i) if given by facsimile transmission, when transmitted to the facsimile number specified in this Article XIII and confirmation of receipt is received, or (ii) if given by any other means, when delivered (or, in the case of electronic transmission, received) at the address specified in this Article XIII; provided that notices to the Administrative Agent, the Issuer and the Swing Line Lender under Article II shall not be effective until received.

ARTICLE XIV

COUNTERPARTS

            This Agreement may be executed in any number of counterparts, all of which taken together shall constitute one agreement, and any of the parties hereto may execute this Agreement by signing any such counterpart. This Agreement shall be effective when it has been executed by the Borrower, the Administrative Agent and the Lenders and each party has notified the Administrative Agent by facsimile transmission or telephone that it has taken such action.

ARTICLE XV

CHOICE OF LAW; CONSENT TO JURISDICTION;
WAIVER OF JURY TRIAL; MAXIMUM INTEREST RATE

            15.1            CHOICE OF LAW. THE LOAN DOCUMENTS (OTHER THAN THOSE CONTAINING A CONTRARY EXPRESS CHOICE OF LAW PROVISION) SHALL BE CONSTRUED IN ACCORDANCE WITH THE INTERNAL LAWS (INCLUDING 735 ILCS SECTION 105/5-1 ET SEQ, BUT OTHERWISE WITHOUT REGARD TO THE CONFLICT OF LAWS PROVISIONS) OF THE STATE OF ILLINOIS, BUT GIVING EFFECT TO FEDERAL LAWS APPLICABLE TO NATIONAL BANKS.

            15.2            CONSENT TO JURISDICTION. THE BORROWER HEREBY IRREVOCABLY SUBMITS TO THE NON-EXCLUSIVE JURISDICTION OF ANY UNITED STATES FEDERAL OR ILLINOIS STATE COURT SITTING IN CHICAGO, ILLINOIS IN ANY ACTION OR PROCEEDING ARISING OUT OF OR RELATING TO ANY LOAN DOCUMENTS AND THE BORROWER HEREBY IRREVOCABLY AGREES THAT ALL CLAIMS IN RESPECT OF SUCH ACTION OR PROCEEDING MAY BE HEARD AND DETERMINED IN ANY SUCH COURT AND IRREVOCABLY WAIVES ANY OBJECTION IT MAY NOW OR HEREAFTER HAVE AS TO THE VENUE OF ANY SUCH SUIT, ACTION OR PROCEEDING BROUGHT IN SUCH A COURT OR THAT SUCH COURT IS AN INCONVENIENT FORUM. NOTHING HEREIN SHALL LIMIT THE RIGHT OF THE ADMINISTRATIVE AGENT OR ANY LENDER TO BRING PROCEEDINGS AGAINST THE BORROWER IN THE COURTS OF ANY OTHER JURISDICTION. ANY JUDICIAL PROCEEDING BY THE BORROWER AGAINST THE ADMINISTRATIVE AGENT OR ANY LENDER OR ANY AFFILIATE OF THE ADM INISTRATIVE AGENT OR ANY LENDER INVOLVING, DIRECTLY OR INDIRECTLY, ANY MATTER IN ANY WAY ARISING OUT OF, RELATED TO, OR CONNECTED WITH ANY LOAN DOCUMENT SHALL BE BROUGHT ONLY IN A COURT IN CHICAGO, ILLINOIS.

            15.3            WAIVER OF JURY TRIAL. THE BORROWER, THE ADMINISTRATIVE AGENT AND EACH LENDER HEREBY WAIVE TRIAL BY JURY IN ANY JUDICIAL PROCEEDING INVOLVING, DIRECTLY OR INDIRECTLY, ANY MATTER (WHETHER SOUNDING IN TORT, CONTRACT OR OTHERWISE) IN ANY WAY ARISING OUT OF, RELATED TO, OR CONNECTED WITH ANY LOAN DOCUMENT OR THE RELATIONSHIP ESTABLISHED THEREUNDER.

            15.4            Maximum Interest Rate. No provision of the Loan Documents shall require the payment or permit the collection of interest in excess of the maximum permitted by applicable law ("Maximum Rate"). If any interest in excess of the Maximum Rate is provided for or shall be adjudicated to be provided for in the Notes or otherwise in connection with this Agreement, the provisions of this Section 15.4 shall govern and prevail and neither the Borrower nor the sureties, guarantors, successors or assigns of the Borrower shall be obligated to pay the excess amount of the interest or any other excess sum paid for the use, forbearance, or detention of sums loaned. In the event the Administrative Agent or any Lender ever receives, collects or applies as interest any amount in excess of the Maximum Rate, the amount by which such amount exceeds the Maximum Rate s hall be applied as a payment and reduction of the principal of indebtedness evidenced by the Loans, and, if the principal amount of the Loans has been paid in full, any remaining excess shall forthwith be paid to the Borrower.

ARTICLE XVI

AMENDMENT AND RESTATEMENT OF EXISTING AGREEMENT

            The Borrower and the Lenders agree that, at the Effective Time, (i) the Existing Agreement shall be deemed to be restated in the form hereof; it being understood that all provisions thereof which by their terms survive any termination thereof shall continue in full force and effect (without duplicating the obligations of any Person under this Agreement); and (ii) the Pro Rata Shares of the Lenders shall be reallocated in accordance with the terms hereof.

            To facilitate the allocation described in the preceding paragraph, at the Effective Time, (i) all "Loans" under the Existing Agreement ("Existing Loans") shall be deemed to be Revolving Loans, (ii) each Lender shall transfer to the Administrative Agent an amount equal to the excess, if any, of such Lender's pro rata share (according to its Pro Rata Share) of the outstanding Revolving Loans hereunder (including any Revolving Loans made at the Effective Time) over the amount of all of such Lender's Existing Loans, (iii) the Administrative Agent shall apply the funds received from the Lenders pursuant to clause (ii), first, to purchase from each Lender which has Existing Loans in excess of such Lender's pro rata share (according to its Pro Rata Share) of the outstanding Revolving Loans hereunder (including any Revolving Loans made upon the effectiveness of this Agreement), a portion of such Existing Loans equal to suc h excess, second, to pay to each Lender all interest, fees and other amounts (including amounts payable pursuant to Section 3.4 of the Existing Agreement, assuming for such purpose that the Existing Loans were prepaid rather than allocated at the Effective Time) owed to such Lender under the Existing Agreement (whether or not otherwise then due) and, third, as the Borrower shall direct, and (iv) all Revolving Loans shall commence new Interest Periods in accordance with elections made by the Borrower at least three Business Days prior to the date hereof pursuant to the procedures applicable to conversions and continuations set forth in Section 2.5 (all as if the Existing Loans were continued or converted at the Effective Time). To the extent the Borrower fails to make a timely election pursuant to clause (iv) of the preceding sentence with respect to any Revolving Loans, such Revolving Loans shall be Floating Rate Loans.

ARTICLE XVII

USA PATRIOT ACT NOTIFICATION

            The following notification is provided to the Borrower pursuant to Section 326 of the USA Patriot Act of 2001, 31 U.S.C. Section 5318: IMPORTANT INFORMATION ABOUT PROCEDURES FOR OPENING A NEW ACCOUNT. To help the government fight the funding of terrorism and money laundering activities, Federal law requires all financial institutions to obtain, verify and record information that identifies each person or entity that opens an account, including any deposit account, treasury management account, loan, other extension of credit or other financial services product. What this means for the Borrower: When the Borrower opens an account, the Lenders will ask for the Borrower's name, tax identification number, business address and other information that will allow the Administrative Agent and the Lenders to identify the Borrower. The Administrative Agent and the Lenders may also ask to see the Borrower's legal organizationa l documents or other identifying documents.

            IN WITNESS WHEREOF, the Borrower, the Lenders and the Administrative Agent have executed this Agreement as of the date first above written.

SOUTHWESTERN ENERGY COMPANY

By:

Executive Vice President and
Chief Financial Officer


2350 N. Sam Houston Parkway East
Suite 300
Houston, Texas 77032
Attention:;Greg Kerley
Fax: 281-618-4820

JPMORGAN CHASE BANK, N.A., as Administrative Agent, as Swing Line Lender, as Issuer and as a Lender


By:

Title:


For notices of borrowing, payments and other administrative matters:

1111 Fannin, 10th Floor

Houston, TX 77002

Attention: Sylvia Gutierrez

Fax: 713-427-6307

For all other notices:

600 Travis, 20th Floor

Houston, TX 77002

Attention: Rob Traband

Fax: 713-216-8870

SUNTRUST BANK, as Syndication Agent and as a Lender

By:

Title:

ROYAL BANK OF CANADA, as Co-Documentation Agent and as a Lender

By:

Title:

FLEET NATIONAL BANK, as Co-Documentation Agent and as a Lender

By:

Title:

THE ROYAL BANK OF SCOTLAND plc, as Co-Documentation Agent and as a Lender

By:

Title:

UFJ BANK LIMITED, as Managing Agent and as a Lender

By:

Title:

HARRIS NESBITT FINANCING, INC., as Managing Agent and as a Lender

By:

Title:

WELLS FARGO BANK, N.A., as Managing Agent and as a Lender

By:

Title:

U.S. BANK NATIONAL ASSOCIATION, as Co- Agent and as a Lender

By:

Title:

KEYBANK NATIONAL ASSOCIATION, as Co- Agent and as a Lender

By:

Title:

COMERICA BANK

By:

Title:

MIZUHO CORPORATE BANK, LTD.

By:

Title:

COMPASS BANK

By:

Title:

ARVEST BANK

By:

Title:

HIBERNIA BANK

By:

Title:

BANK OF ARKANSAS

By:

Title:

SCHEDULE 1A
COMMITMENTS

Lender	Amount of Commitment
JPMorgan Chase Bank, N.A.	$47,500,000
SunTrust Bank	$47,500,000
Royal Bank of Canada	$45,000,000
Fleet National Bank	$45,000,000
The Royal Bank of Scotland, plc	$45,000,000
UFJ Bank Limited	$35,000,000
Harris Nesbitt Financing, Inc.	$35,000,000
Wells Fargo Bank, N.A.	$30,000,000
U.S. Bank National Association	$27,500,000
KeyBank National Association	$27,500,000
Comerica Bank	$25,000,000
Mizuho Corporate Bank, Ltd.	$25,000,000
Compass Bank	$20,000,000
Arvest Bank	$20,000,000
Hibernia Bank	$15,000,000
Bank of Arkansas	$10,000,000
Aggregate Commitment	$500,000,000

SCHEDULE 1B

PRICING SCHEDULE
(Applicable Margins and Rate in basis points)

	LEVEL I STATUS	LEVEL II STATUS	LEVEL III STATUS	LEVEL IV STATUS	LEVEL V STATUS	LEVEL VI STATUS
Commitment Fee Rate	15.0	17.5	22.5	25.0	30.0	30.0
Applicable Margin for Eurodollar Rate and LC Fee Rate	62.5	75.0	100.0	125.0	150.0	175.0
Applicable Margin for Floating Rate	0.0	0.0	0.0	0.0	25.0	50.0

        For the purposes of this Schedule, the following terms have the following meanings, subject to the final paragraph of this Schedule:

        "Level I Status" exists at any date if, on such date, the Borrower's Moody's Rating is Baa1 or better or the Borrower's S&P Rating is BBB+ or better.

        "Level II Status" exists at any date if, on such date, (i) the Borrower has not qualified for Level I Status and (ii) the Borrower's Moody's Rating is Baa2 or better or the Borrower's S&P Rating is BBB or better.

        "Level III Status" exists at any date if, on such date, (i) the Borrower has not qualified for Level I Status or Level II Status and (ii) the Borrower's Moody's Rating is Baa3 or better or the Borrower's S&P Rating is BBB- or better.

        "Level IV Status" exists at any date if, on such date, (i) the Borrower has not qualified for Level I Status, Level II Status or Level III Status and (ii) the Borrower's Moody's Rating is Ba1 or better or the Borrower's S&P Rating is BB+ or better.

        "Level V Status" exists at any date if, on such date, (i) the Borrower has not qualified for Level I Status, Level II Status, Level III Status or Level IV Status and (ii) the Borrower's Moody's Rating is Ba2 or better or the Borrower's S&P Rating is BB or better.

        "Level VI Status" exists at any date if, on such date, the Borrower has not qualified for Level I Status, Level II Status, Level III Status, Level IV Status or Level V Status.

        "Moody's Rating" means, at any time, the rating issued by Moody's Investors Service, Inc. and then in effect with respect to the Borrower's senior unsecured long-term public debt securities without third-party credit enhancement.

        "S&P Rating" means, at any time, the rating issued by Standard and Poor's Rating Services, a division of The McGraw Hill Companies, Inc., and then in effect with respect to the Borrower's senior unsecured long-term public debt securities without third-party credit enhancement.

        "Status" means Level I Status, Level II Status, Level III Status, Level IV Status, Level V Status or Level VI Status.

        The Applicable Margin, the Commitment Fee Rate and the LC Fee Rate shall be determined in accordance with the foregoing table based on the Borrower's Status as determined from its then-current Moody's and S&P Ratings. The credit rating in effect on any date for the purposes of this Schedule is that in effect at the close of business on such date. If at any time the Borrower has no Moody's Rating or no S&P Rating, Level VI Status shall exist.

        If the Borrower is split-rated and the ratings differential is one level, the higher rating will apply. If the Borrower is split-rated and the ratings differential is two levels or more, the intermediate rating at the midpoint will apply. If there is no midpoint, the higher of the two intermediate ratings will apply.

SCHEDULE 5.4
SUBSIDIARIES

Arkansas Western Gas Company

Southwestern Energy Production Company

Southwestern Energy Pipeline Company

SEECO, Inc.

A.W. Realty Company

Southwestern Energy Services Company

Diamond "M" Production Company

DeSoto Gathering Company, L.L.C.

All of the above are 100% owned by the Company and are formed under the laws of Arkansas.

Arkansas Gas Gathering Company, an Arkansas corporation, and PV Exploration Company, an Arkansas corporation, are both 100% owned by SEECO, Inc

Certified Title Company, a Texas corporation, is 100% owned by A.W. Realty Company

Overton Partners, LLC, an Arkansas limited liability company, is 100% owned by Southwestern Energy Production Company.

SCHEDULE 5.12
LITIGATION

None.

SCHEDULE 5.18
NEGATIVE PLEDGES

        Listed below are all of the documents evidencing Indebtedness of the Borrower and its Subsidiaries which contain limitations on the creation, incurrence, or assumption of Liens on any of their properties.

        Indenture dated as of December 1, 1995, between the Borrower and JPMorgan (then known as The First National Bank of Chicago), as Trustee.

SCHEDULE 6.2
INSURANCE

1. Property "all risk" insurance including earthquake coverage for buildings, personal property, equipment and inventory. Minimum limit of $15,000,000.

2. Workers' Compensation with Statutory Limits and Employer's Liability with $1,000,000 per accident or occupational disease covering all employees in compliance with the laws of the States of Arkansas, Oklahoma, New Mexico and Texas. Such policy is endorsed to provide United States Longshoremen's & Harbor Workers' Compensation Act and Maritime Coverages.

3. Commercial General Liability Insurance with bodily injury and death limits of $1,000,000 for injury to or death of one person and $2,000,000 for the death or injury of more than one person in one occurrence and property damage limits of $1,000,000 for each occurrence.

4. Automobile Public Liability Insurance covering bodily injury or death and property damage of at least $1,000,000 per occurrence, combined single limit.

5. Control of Well Coverage with $10,000,000 combined single limit for operator's extra expense/care, custody and control; redrilling/recompletion; and seepage, pollution and containment.

6. Excess Liability Insurance with minimum limits of at least $30,000,000 to apply in excess of the primary limits of the above stated policies.

EXHIBIT A
FORM OF BORROWING NOTICE

Reference is made to the Amended and Restated Credit Agreement dated as of January 4, 2005 (as from time to time amended, the "Agreement") among Southwestern Energy Company, an Arkansas corporation (the "Borrower"), various financial institutions, and JPMorgan Chase Bank, N.A., as Administrative Agent (the "Administrative Agent"). Capitalized terms used but not defined herein have the respective meanings given to such terms in the Agreement.

Pursuant to the Agreement, the Borrower hereby requests that an Advance in the amount of $_________ to be made on ____________, ____.

The Borrower requests that the Advance to be made hereunder shall be [a Floating Rate Advance] [a Eurodollar Advance] [and shall have an Interest Period of _______________.]

The Borrower certifies that:

(a) The representations and warranties of the Borrower set forth in Article V of the Agreement are true and correct on and as of the date hereof, with the same effect as though such representations and warranties had been made on and as of the date hereof or, if such representations and warranties are expressly limited to particular dates, as of such particular dates.

(b) No Default or Unmatured Default exists or will result from the Borrower's receipt and application of the proceeds of the Advance requested hereby.

IN WITNESS WHEREOF, this instrument is executed as of _________, ____.

SOUTHWESTERN ENERGY COMPANY

By:________________________________

Name:______________________________

Title:_______________________________

EXHIBIT B
FORM OF OPINION

January 4, 2005

The Administrative Agent and the Lenders who are parties to the
Credit Agreement described below.

Gentlemen/Ladies:

I am counsel for Southwestern Energy Company (the "Borrower"), and have represented the Borrower and the Subsidiaries of the Borrower listed on Schedule 1 (the "Guarantors") in connection with its execution and delivery of an Amended and Restated Credit Agreement dated as of January 4, 2005 (the "Agreement") among the Borrower, the Lenders named therein, and JPMorgan Chase Bank, N.A., as Administrative Agent, and providing for Advances and Letters of Credit in an aggregate principal amount not exceeding $500,000,000 (or $550,000,000 if the option under Section 2.6.3 thereof has been exercised and become effective) at any one time outstanding. All capitalized terms used in this opinion and not otherwise defined herein shall have the meanings attributed to them in the Agreement.

I have examined the Borrower's and each Guarantor's **[describe constitutive documents of Borrower and Guarantors and appropriate evidence of authority to enter into the transaction]**, the Loan Documents and such other matters of fact and law which we deem necessary in order to render this opinion. Based upon the foregoing, it is our opinion that:

l. Each of the Borrower and its Subsidiaries is a corporation, partnership or limited liability company duly and properly incorporated or organized, as the case may be, validly existing and (to the extent such concept applies to such entity) in good standing under the laws of its jurisdiction of incorporation or organization and has all requisite authority to conduct its business in each jurisdiction in which its business is conducted.

2. The execution and delivery by the Borrower and each Guarantor of the Loan Documents to which it is a party and the performance by the Borrower and each Guarantor of its obligations thereunder have been duly authorized by proper corporate or limited liability company proceedings on the part of the Borrower and each Guarantor and will not:

(a) require any consent of the Borrower's or any Guarantor's shareholders or members (other than any such consent as has already been given and remains in full force and effect);

(b) violate (i) any law, rule, regulation, order, writ, judgment, injunction, decree or award binding on the Borrower or any of its Subsidiaries or (ii) the Borrower's or any Subsidiary's articles or certificate of incorporation, articles or certificate of organization, bylaws, or operating or other management agreement, as the case may be, or (iii) the provisions of any indenture, instrument or agreement to which the Borrower or any of its Subsidiaries is a party or is subject, or by which it, or its Property, is bound, or conflict with or constitute a default thereunder; or

(c) result in, or require, the creation or imposition of any Lien in, of or on the Property of the Borrower or a Subsidiary pursuant to the terms of any indenture, instrument or agreement binding upon the Borrower or any of its Subsidiaries.

3. The Loan Documents to which the Borrower or any Guarantor is a party have been duly executed and delivered by the Borrower or such Guarantor, as the case may be, and constitute legal, valid and binding obligations of the Borrower enforceable against the Borrower or such Guarantor, as the case may be, in accordance with their terms except to the extent the enforcement thereof may be limited by bankruptcy, insolvency or similar laws affecting the enforcement of creditors' rights generally and subject also to the availability of equitable remedies if equitable remedies are sought.

4. Except for the litigation disclosed in Borrower's Form 10-K for the year ended December 31, 2003 and updated in the Borrower's most recent Form 10-Q, there is no litigation, arbitration, governmental investigation, proceeding or inquiry pending or, to the best of our knowledge after due inquiry, threatened against the Borrower or any of its Subsidiaries which, if adversely determined, could reasonably be expected to have a Material Adverse Effect.

5. No order, consent, adjudication, approval, license, authorization, or validation of, or filing, recording or registration with, or exemption by, or other action in respect of any governmental or public body or authority, or any subdivision thereof, which has not been obtained by the Borrower or any of its Subsidiaries, is required to be obtained by the Borrower or any of its Subsidiaries in connection with the execution and delivery of the Loan Documents, the borrowings under the Agreement, the payment and performance by the Borrower of the Obligations, or the legality, validity, binding effect or enforceability of any of the Loan Documents.

This opinion may be relied upon by the Administrative Agent, the Lenders and their participants, assignees and other transferees.

Very truly yours,

EXHIBIT C

ASSIGNMENT AGREEMENT

This Assignment and Assumption (the "Assignment and Assumption") is dated as of the Effective Date set forth below and is entered into by and between [Insert name of Assignor] (the "Assignor") and [Insert name of Assignee] (the "Assignee"). Capitalized terms used but not defined herein shall have the respective meanings given to them in the Credit Agreement identified below (as amended, the "Credit Agreement"), receipt of a copy of which is hereby acknowledged by the Assignee. The Terms and Conditions set forth in Annex 1 attached hereto are hereby agreed to and incorporated herein by reference and made a part of this Assignment and Assumption as if set forth herein in full.

For an agreed consideration, the Assignor hereby irrevocably sells and assigns to the Assignee, and the Assignee hereby irrevocably purchases and assumes from the Assignor, subject to and in accordance with the Standard Terms and Conditions and the Credit Agreement, as of the Effective Date inserted by the Administrative Agent as contemplated below, the interest in and to all of the Assignor's rights and obligations in its capacity as a Lender under the Credit Agreement and any other documents or instruments delivered pursuant thereto that represents the amount and percentage interest identified below of all of the Assignor's outstanding rights and obligations under the respective facilities identified below (including any letters of credit and guaranties included in such facilities and, to the extent permitted to be assigned under applicable law, all claims (including contract claims, tort claims, malpractice claims, statutory claims and all other claims at law or in equity), suits, causes o f action and any other right of the Assignor against any Person whether known or unknown arising under or in connection with the Credit Agreement, any other documents or instruments delivered pursuant thereto or the loan transactions governed thereby) (the "Assigned Interest"). Such sale and assignment is without recourse to the Assignor and, except as expressly provided in this Assignment and Assumption, without representation or warranty by the Assignor.

1. Assignor:

2. Assignee:

3. Borrower: Southwestern Energy Company

4. Administrative

Agent: JPMorgan Chase Bank, N.A., as the Administrative Agent under the Credit Agreement.

5. Credit Agreement: The Amended and Restated Credit Agreement dated as of January 4, 2005 among the Borrower, the Lenders party thereto and JPMorgan Chase Bank, N.A., as Administrative Agent.

6. Assigned Interest:

Facility Assigned	Aggregate Amount of Commitment/Loans for all Lenders1	Amount of Commitment/Loans Assigned*	Percentage Assigned of Commitment/Loans1
____________	$	$	_______%
____________	$	$	_______%
____________	$	$	_______%

7. Trade Date: ²

Effective Date: ____________________, 20__ TO BE INSERTED BY AGENT AND WHICH SHALL BE THE EFFECTIVE DATE OF RECORDATION OF TRANSFER BY THE ADMINISTRATIVE AGENT.]

The terms set forth in this Assignment and Assumption are hereby agreed to:

ASSIGNOR
[NAME OF ASSIGNOR]

By:
Title:

ASSIGNEE
[NAME OF ASSIGNEE]

By:
Title:

[Consented to and]³ Accepted:

JPMORGAN CHASE BANK, N.A., as Administrative Agent

By:
Title:

[Consented to:]⁴

[NAME OF RELEVANT PARTY]

By:
Title:

* Amount to be adjusted by the counterparties to take into account any payments or prepayments made between the Trade Date and the Effective Date.

1 Set forth, to at least 9 decimals, as a percentage of the Commitment/Loans of all Banks thereunder.

2 Insert if satisfaction of minimum amounts is to be determined as of the Trade Date.

3 To be added only if the consent of the Administrative Agent is required by the terms of the Credit Agreement.

4 To be added only if the consent of the Company and/or other parties (e.g. LC Issuer) is required by the terms of the Credit Agreement.

ANNEX 1

TERMS AND CONDITIONS FOR
ASSIGNMENT AND ASSUMPTION

1. Representations and Warranties.

1.1 Assignor. The Assignor represents and warrants that (i) it is the legal and beneficial owner of the Assigned Interest, (ii) the Assigned Interest is free and clear of any lien, encumbrance or other adverse claim and (iii) it has full power and authority, and has taken all action necessary, to execute and deliver this Assignment and Assumption and to consummate the transactions contemplated hereby. Neither the Assignor nor any of its officers, directors, employees, agents or attorneys shall be responsible for (i) any statements, warranties or representations made in or in connection with the Credit Agreement or any other Loan Document, (ii) the execution, legality, validity, enforceability, genuineness, sufficiency, perfection, priority, collectibility, or value of the Loan Documents or any collateral thereunder, (iii) the financial condition of the Borrower, any of its Subsidiaries or Affiliates or any other Person obligated in respect of any Loan Document, (iv) the performance or observance by the Borrower, any of its Subsidiaries or Affiliates or any other Person of any of their respective obligations under any Loan Document, (v) inspecting any of the property, books or records of the Borrower, or any guarantor, or (vi) any mistake, error of judgment, or action taken or omitted to be taken in connection with the Advances or the Loan Documents.

1.2. Assignee. The Assignee (a) represents and warrants that (i) it has full power and authority, and has taken all action necessary, to execute and deliver this Assignment and Assumption and to consummate the transactions contemplated hereby and to become a Lender under the Credit Agreement, (ii) from and after the Effective Date, it shall be bound by the provisions of the Credit Agreement as a Lender thereunder and, to the extent of the Assigned Interest, shall have the obligations of a Lender thereunder, (iii) agrees that its payment instructions and notice instructions are as set forth in Schedule 1 to this Assignment and Assumption, (iv) confirms that none of the funds, monies, assets or other consideration being used to make the purchase and assumption hereunder are "plan assets" as defined under ERISA and that its rights, benefits and interests in and under the Loan Documents will not be "plan assets" under ERISA, (v) agrees to indemnify and hold the Assignor harmless against al l losses, costs and expenses (including reasonable attorneys' fees) and liabilities incurred by the Assignor in connection with or arising in any manner from the Assignee's non-performance of the obligations assumed under this Assignment and Assumption, (vi) it has received a copy of the Credit Agreement, together with copies of financial statements and such other documents and information as it has deemed appropriate to make its own credit analysis and decision to enter into this Assignment and Assumption and to purchase the Assigned Interest on the basis of which it has made such analysis and decision independently and without reliance on the Administrative Agent or any other Lender, and (vii) attached as Schedule 1 to this Assignment and Assumption is any documentation required to be delivered by the Assignee with respect to its tax status pursuant to the terms of the Credit Agreement, duly completed and executed by the Assignee and (b) agrees that (i) it will, independently and without reliance on the Ad ministrative Agent, the Assignor or any other Lender, and based on such documents and information as it shall deem appropriate at the time, continue to make its own credit decisions in taking or not taking action under the Loan Documents, and (ii) it will perform in accordance with their terms all of the obligations which by the terms of the Loan Documents are required to be performed by it as a Lender.

2. Payments. The Assignee shall pay the Assignor, on the Effective Date, the amount agreed to by the Assignor and the Assignee. From and after the Effective Date, the Administrative Agent shall make all payments in respect of the Assigned Interest (including payments of principal, interest, Reimbursement Obligations, fees and other amounts) to the Assignor for amounts which have accrued to the Effective Date and to the Assignee for amounts which have accrued from and after the Effective Date.

3. General Provisions. This Assignment and Assumption shall be binding upon, and inure to the benefit of, the parties hereto and their respective successors and assigns. This Assignment and Assumption may be executed in any number of counterparts, which together shall constitute one instrument. Delivery of an executed counterpart of a signature page of this Assignment and Assumption by telecopy shall be effective as delivery of a manually executed counterpart of this Assignment and Assumption. This Assignment and Assumption shall be governed by, and construed in accordance with, the law of the State of Illinois.

ADMINISTRATIVE QUESTIONNAIRE

(Schedule to be supplied by Closing Unit or Trading Documentation Unit)

(For Forms for Primary Syndication call _____________ at ________________)
(For Forms after Primary Syndication call _____________ at ________________)

US AND NON-US TAX INFORMATION REPORTING REQUIREMENTS

(Schedule to be supplied by Closing Unit or Trading Documentation Unit)

(For Forms for Primary Syndication call _____________ at ________________)
(For Forms after Primary Syndication call _____________ at ________________)

EXHIBIT D

LOAN/CREDIT RELATED MONEY TRANSFER INSTRUCTION

To JPMorgan Chase Bank, N.A.,
as Administrative Agent (the "Administrative Agent")
under the Credit Agreement
Described Below.

Re: Credit Agreement, dated as of January 4, 2005 (as the same may be amended or modified, the "Credit Agreement"), among Southwestern Energy Company (the "Borrower"), the Lenders named therein and the Administrative Agent. Capitalized terms used herein and not otherwise defined herein shall have the meanings assigned thereto in the Credit Agreement.

The Administrative Agent is specifically authorized and directed to act upon the following standing money transfer instructions with respect to the proceeds of Advances or other extensions of credit from time to time until receipt by the Administrative Agent of a specific written revocation of such instructions by the Borrower, provided that the Administrative Agent may otherwise transfer funds as hereafter directed in writing by the Borrower in accordance with Section 13.1 of the Credit Agreement or based on any telephonic notice made in accordance with Section 2.14 of the Credit Agreement.

Facility Identification Number(s)

Customer/Account Name: Southwestern Energy Company

Transfer Funds To

For Account No.

Reference/Attention To

Authorized Officer (Customer Representative) Date

(Please Print) Signature

Bank Officer Name Date

(Please Print) Signature

(Deliver Completed Form to Credit Support Staff For Immediate Processing)

EXHIBIT E

NOTE

[Date]

Southwestern Energy Company, an Arkansas corporation (the "Borrower"), promises to pay to the order of ____________________________________ (the "Lender") the aggregate unpaid principal amount of all Loans made by the Lender to the Borrower pursuant to Article II of the Agreement (as hereinafter defined), in immediately available funds at the main office of JPMorgan Chase Bank, N.A., as Administrative Agent, together with interest on the unpaid principal amount hereof at the rates and on the dates set forth in the Agreement. The Borrower shall pay the principal of and accrued and unpaid interest on the Loans in full on the Termination Date.

The Lender shall, and is hereby authorized to, record on the schedule attached hereto, or to otherwise record in accordance with its usual practice, the date and amount of each Loan and the date and amount of each principal payment hereunder.

This Note is one of the Notes issued pursuant to, and is entitled to the benefits of, the Amended and Restated Credit Agreement dated as of January 4, 2005 (as amended or otherwise modified from time to time, the "Agreement"), among the Borrower, the lenders party thereto, including the Lender, and JPMorgan Chase Bank, N.A., as Administrative Agent, to which Agreement reference is hereby made for a statement of the terms and conditions governing this Note, including the terms and conditions under which this Note may be prepaid or its maturity date accelerated. This Note is guaranteed pursuant to the Subsidiary Guaranty, as more specifically described in the Agreement. Capitalized terms used herein and not otherwise defined herein are used with the meanings attributed to them in the Agreement.

Notwithstanding anything to the contrary in this Note, no provision of this Note shall require the payment or permit the collection of interest in excess of the maximum permitted by applicable law ("Maximum Rate"). If any interest in excess of the Maximum Rate is provided for or shall be adjudicated to be so provided, in this Note or otherwise in connection with the loan transaction, the provisions of this paragraph shall govern and prevail, and neither the Borrower nor the sureties, guarantors, successors or assigns of the Borrower shall be obligated to pay the excess of the interest or any other excess sum paid for the use, forbearance, or detention of sums loaned. If for any reason interest in excess of the Maximum Rate shall be deemed charged, required or permitted by any court of competent jurisdiction, the excess shall be applied as payment and reduction of the principal of indebtedness evidenced by this Note, and, if the principal amount has been paid in full, any remaining excess shal l forthwith be paid to the Borrower.

[This Note replaces and supersedes any Note issued under the Existing Credit Agreement to the Lender or in which the Lender has been assigned an interest.]

This Note shall be construed in accordance with the internal laws (and not the law of conflicts) of the State of Illinois, but giving effect to Federal laws applicable to national banks.

SOUTHWESTERN ENERGY COMPANY

By:

Print Name:

Title:

SCHEDULE OF LOANS AND PAYMENTS OF PRINCIPAL
TO
NOTE
of southwestern energy company

DATED __________, 200__

Date Principal
Amount of
Loan Maturity
of Interest
Period Principal
Amount Paid Unpaid Balance

EXHIBIT F

FORM OF SUBSIDIARY GUARANTY

THIS AMENDED AND RESTATED SUBSIDIARY GUARANTY (this "Guaranty") is made as of January 4, 2005 by SOUTHWESTERN ENERGY SERVICES COMPANY, an Arkansas corporation, SOUTHWESTERN ENERGY PRODUCTION COMPANY, an Arkansas corporation, and SEECO, INC., an Arkansas corporation (together with any other entity that may from time to time become party hereto by signing a counterpart hereof, collectively the "Subsidiary Guarantors" and each a "Subsidiary Guarantor"), in favor of JPMorgan Chase Bank, N.A., a national banking association, as administrative agent (in such capacity, the "Agent").

WITNESSETH:

WHEREAS, Southwestern Energy Company, an Arkansas corporation (the "Company"), various financial institutions (the "Lenders") and the Agent have entered into an amended and restated credit agreement dated as of the date hereof (as the same may be amended, restated or otherwise modified from time to time, the "Credit Agreement"), providing, subject to the terms and conditions thereof, for extensions of credit to be made by various financial institutions to the Company;

WHEREAS, certain Subsidiaries of the Company executed and delivered a Subsidiary Guaranty dated as of January 2, 2004 (the "Existing Subsidiary Guaranty") to guarantee the obligations of the Company under a Credit Agreement dated as of January 2, 2004 among the Company, various financial institutions and JPMorgan Chase Bank, N.A. (as successor to Bank One, NA), as administrative agent;

WHEREAS, the execution and delivery of this Guaranty are conditions to the effectiveness of the Credit Agreement; and

WHEREAS, in consideration of the financial and other support that the Company has provided, and such financial and other support as the Company may in the future provide, to the Subsidiary Guarantors, and in order to induce the Lenders to grant extensions of credit under the Credit Agreement, and because each Subsidiary Guarantor has determined that executing this Guaranty is in its interest and to its financial benefit, each of the Subsidiary Guarantors is willing to guarantee the obligations of the Company under the Credit Agreement and the Notes and desires to amend and restate the Existing Subsidiary Guaranty as hereinafter set forth;

NOW, THEREFORE, in consideration of the premises and other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the parties hereto agree as follows:

SECTION 1. Credit Agreement Definitions. Capitalized terms used herein but not defined herein shall have the respective meanings set forth in (or defined by reference in) the Credit Agreement.

SECTION 2. Representations and Warranties. Each Subsidiary Guarantor represents and warrants (which representations and warranties shall be deemed to have been renewed on each date on which a Lender makes a Loan to the Company) that:

(a) It is a corporation, partnership or limited liability company duly and properly incorporated or organized, as the case may be, validly existing and (to the extent such concept applies to such entity) in good standing under the laws of its jurisdiction of incorporation or organization and has all requisite authority to conduct its business in each jurisdiction in which its business is conducted.

(b) It has the power and authority and legal right to execute and deliver this Guaranty and to perform its obligations hereunder. The execution and delivery by it of this Guaranty and the performance of its obligations hereunder have been duly authorized by proper organizational proceedings, and this Guaranty constitutes a legal, valid and binding obligation of such Subsidiary Guarantor enforceable against it in accordance with its terms, except as enforceability may be limited by bankruptcy, insolvency or similar laws affecting the enforcement of creditors' rights generally.

(c) Neither the execution and delivery by it of this Guaranty, nor the consummation of the transactions herein contemplated, nor compliance with the provisions hereof will violate (i) any law, rule, regulation, order, writ, judgment, injunction, decree or award binding on it or any of its Subsidiaries or (ii) its articles or certificate of incorporation, partnership agreement, certificate of partnership, articles or certificate of organization, bylaws, or operating or other management agreement, as the case may be, or (iii) the provisions of any indenture, instrument or agreement to which it or any of its Subsidiaries is a party or is subject, or by which it, or its Property, is bound, or conflict with or constitute a default thereunder, or result in, or require, the creation or imposition of any Lien in, of or on the Property of such Subsidiary Guarantor or a Subsidiary thereof pursuant to the terms of any such indenture, instrument or agreement. No order, consent, adjudication, approval, license, authorization or validation of, or filing, recording or registration with, or exemption by, or other action in respect of any governmental or public body or authority, or any subdivision thereof, which has not been obtained by it or any of its Subsidiaries, is required to be obtained by it or any of its Subsidiaries in connection with the execution and delivery of this Guaranty or the performance by it of its obligations hereunder or the legality, validity, binding effect or enforceability of this Guaranty.

SECTION 3. The Guaranty. Subject to Section 9 hereof, each Subsidiary Guarantor hereby absolutely and unconditionally guarantees, as primary obligor and not as merely surety, the full and punctual payment (whether at stated maturity, upon acceleration or early termination or otherwise, and at all times thereafter) and performance of the unpaid principal of and accrued and unpaid interest on the Loans, all accrued and unpaid fees and all expenses, reimbursements, indemnities and other obligations of the Company to the Lender or any other indemnified party arising under the Loan Documents, including without limitation any such obligations incurred or accrued during the pendency of any bankruptcy, insolvency, receivership or similar proceeding, whether or not allowed or allowable in such proceeding (collectively, subject to the provisions of Section 9 hereof, the "Guaranteed Obligations"). Upon failure by the Company to pay punctually any such amount, each Subsidiary Guarantor agrees that it shall forthwith on written demand pay to the Agent the amount not so paid at the place and in the manner specified in the Credit Agreement. This Guaranty is a guaranty of payment and not of collection. Each Subsidiary Guarantor waives any right to require the Agent or any Lender to sue the Company, any other guarantor, or any other person obligated for all or any part of the Guaranteed Obligations.

SECTION 4. Guaranty Unconditional. Subject to Section 9 hereof, the obligations of each Subsidiary Guarantor hereunder shall be unconditional and absolute and, without limiting the generality of the foregoing, shall not be released, discharged or otherwise affected by:

(i) any extension, renewal, settlement, compromise, waiver or release in respect of any of the Guaranteed Obligations, by operation of law or otherwise, or any obligation of any other guarantor of any of the Guaranteed Obligations, or any default, failure or delay, willful or otherwise, in the payment or performance of the Guaranteed Obligations;

(ii) any modification or amendment of or supplement to the Credit Agreement or the Notes;

(iii) #9; any release, nonperfection or invalidity of any direct or indirect security for any obligation of the Company under the Credit Agreement or the Notes or any obligation of any other guarantor of any of the Guaranteed Obligations;

(iv) any change in the corporate existence, structure or ownership of the Company or any other guarantor of any of the Guaranteed Obligations, or any insolvency, bankruptcy, reorganization or other similar proceeding affecting the Company or any other guarantor of the Guaranteed Obligations, or the assets of any of the foregoing, or any resulting release or discharge of any obligation of the Company or any other guarantor of any of the Guaranteed Obligations;

(v) the existence of any claim, setoff or other right which such Subsidiary Guarantor may have at any time against the Company, any other guarantor of any of the Guaranteed Obligations, the Agent, any Lender or any other Person, whether in connection herewith or any unrelated transaction;

(vi) any invalidity or unenforceability relating to or against the Company, or any other guarantor of any of the Guaranteed Obligations, for any reason related to the Credit Agreement or the Notes, or any provision of applicable law or regulation purporting to prohibit the payment by the Company, or any other guarantor of the Guaranteed Obligations, of the principal of or interest on the Notes or any other amount payable by the Company under the Credit Agreement or the Notes; or

(vii) any other act or omission to act or delay of any kind by the Company, any other guarantor of the Guaranteed Obligations, the Agent, any Lender or any other Person or any other circumstance whatsoever which might, but for the provisions of this paragraph, constitute a legal or equitable discharge of such Subsidiary Guarantor's obligations hereunder.

SECTION 5. Discharge Only Upon Payment In Full: Reinstatement In Certain Circumstances. Each Subsidiary Guarantor's obligations hereunder shall remain in full force and effect until all Guaranteed Obligations shall have been indefeasibly paid in full and the Commitment shall have terminated or expired. If at any time any payment of the principal of or interest on the Notes or any other amount payable by the Company under the Credit Agreement, or by any Subsidiary Guarantor hereunder, is rescinded or must be otherwise restored or returned upon the insolvency, bankruptcy or reorganization of the Company or otherwise, each Subsidiary Guarantor's obligations hereunder with respect to such payment shall be reinstated as though such payment had been due but not made at such time.

SECTION 6. Waivers. Each Subsidiary Guarantor irrevocably waives acceptance hereof, presentment, demand, protest and, to the fullest extent permitted by law, any notice not provided for herein, as well as any requirement that at any time any action be taken by any Person against the Company, any other guarantor of any of the Guaranteed Obligations or any other Person.

SECTION 7. Subrogation. Each Subsidiary Guarantor hereby agrees not to assert any right, claim or cause of action, including, without limitation, a claim for subrogation, reimbursement, indemnification or otherwise, against the Company arising out of or by reason of this Guaranty or the obligations hereunder, including, without limitation, the payment or securing or purchasing of any of the Guaranteed Obligations by any of the Subsidiary Guarantors, unless and until the Guaranteed Obligations are indefeasibly paid in full and the Commitment has terminated.

SECTION 8. Stay of Acceleration. If acceleration of the time for payment of any of the Guaranteed Obligations is stayed upon the insolvency, bankruptcy or reorganization of the Company, all such amounts otherwise subject to acceleration under the terms of the Credit Agreement or the Notes shall nonetheless be payable by each of the Subsidiary Guarantors hereunder forthwith on demand by the Agent.

SECTION 9. Limitation on Obligations.

(a) The provisions of this Guaranty are severable, and in any action or proceeding involving any state corporate law, or any state, federal or foreign bankruptcy, insolvency, reorganization or other law affecting the rights of creditors generally, if the obligations of any Subsidiary Guarantor under this Guaranty would otherwise be held or determined to be avoidable, invalid or unenforceable on account of the amount of such Subsidiary Guarantor's liability under this Guaranty, then, notwithstanding any other provision of this Guaranty to the contrary, the amount of such liability shall, without any further action by any Subsidiary Guarantor, the Agent or any Lender, be automatically limited and reduced to the highest amount that is valid and enforceable as determined in such action or proceeding (such highest amount determined hereunder being the relevant Subsidiary Guarantor's "Maximum Liability"). This Section 9(a) with respect to the Maximum Liability of the Subsidiary Guarantors is intend ed solely to preserve the rights of the Agent and the Lenders hereunder to the maximum extent not subject to avoidance under applicable law, and neither a Subsidiary Guarantor nor any other Person shall have any right or claim under this Section 9(a) with respect to the Maximum Liability, except to the extent necessary so that the obligations of each Subsidiary Guarantor hereunder shall not be rendered voidable under applicable law.

(b) Each Subsidiary Guarantor agrees that the Guaranteed Obligations may at any time and from time to time exceed the Maximum Liability of such Subsidiary Guarantor, and may exceed the aggregate Maximum Liability of all other Subsidiary Guarantors, without impairing this Guaranty or affecting the rights and remedies of the Agent hereunder. Nothing in this Section 9(b) shall be construed to increase any Subsidiary Guarantor's obligations hereunder beyond its Maximum Liability.

(c) If any Subsidiary Guarantor (a "Paying Subsidiary Guarantor") shall make any payment or payments under this Guaranty, each other Subsidiary Guarantor (each a "Non-Paying Subsidiary Guarantor") shall contribute to such Paying Subsidiary Guarantor an amount equal to such Non-Paying Subsidiary Guarantor's "Pro Rata Share" of such payment or payments made, or losses suffered, by such Paying Subsidiary Guarantor. For the purposes hereof, each Non-Paying Subsidiary Guarantor's "Pro Rata Share" with respect to any such payment or loss by a Paying Subsidiary Guarantor shall be determined as of the date on which such payment or loss was made by reference to the ratio of (i) such Non-Paying Subsidiary Guarantor's Maximum Liability as of such date (without giving effect to any right to receive, or obligation to make, any contribution hereunder) or, if such Non-Paying Subsidiary Guarantor's Maximum Liability has not been determined, the aggregate amount of all monies received by such Non-Paying Su bsidiary Guarantor from the Company after the date hereof (whether by loan, capital infusion or by other means) to (ii) the sum of the Maximum Liabilities (which may be greater than the amount of Guaranteed Obligations) of all Subsidiary Guarantors hereunder (including such Paying Subsidiary Guarantor) as of such date (without giving effect to any right to receive, or obligation to make, any contribution hereunder), or to the extent that a Maximum Liability has not been determined for any Subsidiary Guarantor, the aggregate amount of all monies received by such Subsidiary Guarantor from the Company after the date hereof (whether by loan, capital infusion or by other means). Nothing in this Section 9(c) shall affect any Subsidiary Guarantor's several liability for the entire amount of the Guaranteed Obligations (up to such Subsidiary Guarantor's Maximum Liability). Each Subsidiary Guarantor covenants and agrees that its right to receive any contribution under this Guaranty from a Non-Paying Subsidiary Guarant or shall be subordinate and junior in right of payment to all the Guaranteed Obligations. The provisions of this Section 9(c) are for the benefit of the Agent, the Lenders and the Subsidiary Guarantors and may be enforced by any of them in accordance with the terms hereof.

SECTION 10. Application of Payments. All payments received by the Agent hereunder shall be applied by the Agent to payment of the Guaranteed Obligations in the following order unless a court of competent jurisdiction shall otherwise direct:

(a) FIRST, to payment of all costs and expenses of the Agent incurred in connection with the collection and enforcement of the Guaranteed Obligations;

(b) SECOND, to payment of that portion of the Guaranteed Obligations constituting accrued and unpaid interest and fees; and

(c) THIRD, to payment of any other Guaranteed Obligations.

SECTION 11. Notices. All notices, requests and other communications to any party hereunder shall be given or made by facsimile or other writing and faxed, mailed or delivered to the intended recipient at its address or facsimile number set forth under its name on Schedule I hereto or such other address or facsimile number as such party may hereafter specify for such purpose by notice to the Agent in accordance with the provisions of Section 8.5 of the Credit Agreement. Except as otherwise provided in this Guaranty, all such communications shall be deemed to have been duly given when transmitted by facsimile, or personally delivered or, in the case of a mailed notice sent by certified mail return-receipt requested, on the date set forth on the receipt (provided that any refusal to accept any such notice shall be deemed to be notice thereof as of the time of any such refusal), in each case given or addressed as aforesaid.

SECTION 12. No Waivers. No failure or delay by the Agent in exercising any right, power or privilege hereunder shall operate as a waiver thereof nor shall any single or partial exercise thereof preclude any other or further exercise thereof or the exercise of any other right, power or privilege. The rights and remedies provided in this Guaranty, the Credit Agreement and the Notes shall be cumulative and not exclusive of any rights or remedies provided by law.

SECTION 13. No Duty to Advise. Each Subsidiary Guarantor assumes all responsibility for being and keeping itself informed of the Company's financial condition and assets, and of all other circumstances bearing upon the risk of nonpayment of the Guaranteed Obligations and the nature, scope and extent of the risks that such Subsidiary Guarantor assumes and incurs under this Guaranty, and agrees that the Agent does not have any duty to advise such Subsidiary Guarantor of information known to it regarding those circumstances or risks.

SECTION 14. Successors and Assigns. This Guaranty is for the benefit of the Agent, the Lenders and their respective successors and permitted assigns and in the event of an assignment of any amounts payable under the Credit Agreement or the Notes, the rights hereunder, to the extent applicable to the indebtedness so assigned, shall be transferred with such indebtedness. This Guaranty shall be binding upon each Subsidiary Guarantor and its successors.

SECTION 15. Changes in Writing. Neither this Guaranty nor any provision hereof may be changed, waived, discharged or terminated orally, but only in writing signed by each of the Subsidiary Guarantors and the Agent.

SECTION 16. Costs of Enforcement. Each Subsidiary Guarantor agrees to pay all costs and expenses, including, without limitation, all court costs and attorneys' fees and expenses, paid or incurred by the Agent in endeavoring to collect all or any part of the Guaranteed Obligations from, or in prosecuting any action against, the Company, such Subsidiary Guarantor or any other guarantor of all or any part of the Guaranteed Obligations.

SECTION 17. GOVERNING LAW; SUBMISSION TO JURISDICTION; WAIVER OF JURY TRIAL. THIS GUARANTY SHALL BE GOVERNED BY AND CONSTRUED IN ACCORDANCE WITH THE LAW OF THE STATE OF ILLINOIS. EACH SUBSIDIARY GUARANTOR HEREBY SUBMITS TO THE NONEXCLUSIVE JURISDICTION OF THE UNITED STATES DISTRICT COURT FOR THE NORTHERN DISTRICT OF ILLINOIS AND OF ANY ILLINOIS STATE COURT SITTING IN CHICAGO, ILLINOIS FOR PURPOSES OF ALL LEGAL PROCEEDINGS ARISING OUT OF OR RELATING TO THIS GUARANTY (INCLUDING, WITHOUT LIMITATION, THE CREDIT AGREEMENT OR THE NOTES) OR THE TRANSACTIONS CONTEMPLATED HEREBY. EACH SUBSIDIARY GUARANTOR IRREVOCABLY WAIVES, TO THE FULLEST EXTENT PERMITTED BY LAW, ANY OBJECTION WHICH IT MAY NOW OR HEREAFTER HAVE TO THE LAYING OF THE VENUE OF ANY SUCH PROCEEDING BROUGHT IN SUCH A COURT AND ANY CLAIM THAT ANY SUCH PROCEEDING BROUGHT IN SUCH A COURT HAS BEEN BROUGHT IN AN INCONVENIENT FORUM. EACH SUBSIDIARY GUARANTOR, AND THE AGENT AND EACH LENDER BY ACCEPTING THE BENEFITS OF THIS GUARANTY, HEREBY IRREVOCABLY WAIVES ANY AND ALL RIGHT TO TRIAL BY JURY IN ANY LEGAL PROCEEDING ARISING OUT OF OR RELATING TO THIS GUARANTY OR THE TRANSACTIONS CONTEMPLATED HEREBY.

SECTION 18. Taxes. etc. All payments required to be made by any of the Subsidiary Guarantors hereunder shall be made without setoff or counterclaim and free and clear of and without deduction or withholding for or on account of, any present or future taxes, levies, imposts, duties or other charges of whatsoever nature imposed by any government or any political or taxing authority thereof (but excluding Excluded Taxes), provided, however, that if any Subsidiary Guarantor is required by law to make such deduction or withholding, such Subsidiary Guarantor shall forthwith (i) pay to the Agent or the applicable Lender such additional amount as results in the net amount received by the Agent equaling the full amount which would have been received by the Agent or such Lender had no such deduction or withholding been made, (ii) pay the full amount deducted to the relevant authority in accordance with applicable law, and (iii) furnish to the Agent or such Lender certified copies of official rec eipts evidencing payment of such withholding taxes within 30 days after such payment is made.

IN WITNESS WHEREOF, each Subsidiary Guarantor has caused this Guaranty to be duly executed by its authorized officer as of the day and year first above written.

SOUTHWESTERN ENERGY PRODUCTION COMPANY

By: __________________________________

Richard F. Lane,

Executive Vice President, Exploration and Production

SOUTHWESTERN ENERGY SERVICES COMPANY

By: __________________________________

Timothy J. O'Donnell

Vice President, Treasurer and Assistant Secretary

SEECO, INC.

By: __________________________________

Greg D. Kerley

Executive Vice President and Chief Financial Officer

Additional Signature page for the Subsidiary Guaranty dated as of January 4, 2005 (as amended, restated or otherwise modified from time to time) issued by various Subsidiaries of Southwestern Energy Company.

The undersigned is executing a counterpart hereof for purposes of becoming a party hereto (and set forth below is the address of the undersigned for purposes of Schedule I to this Subsidiary Guaranty)

[________________________________]

               By: __________________________________

                                                                                                                   Name: ________________________________

                                                                                                                    Title: _________________________________

                                                                                                            Address:                                                            ;          

SCHEDULE I

TO GUARANTY

ADDRESSES

SOUTHWESTERN ENERGY SERVICES COMPANY

5314 S. Yale

Tulsa, OK 74135

SOUTHWESTERN ENERGY PRODUCTION COMPANY

2350 N. Sam Houston Parkway East

Suite 300

Houston, Texas 77032

SEECO, INC.

1083 Sain Street

P.O. Box 13408

Fayetteville, AR 72703-1004

EXHIBIT G

FORM OF COMPLIANCE CERTIFICATE

The undersigned, the _________________ of Southwestern Energy Company (the "Borrower") hereby (a) delivers this Certificate pursuant to Section 6.1(c) of the Amended and Restated Credit Agreement dated as of January 4, 2005 (the "Agreement"; capitalized terms used but not defined herein have the respective meanings given thereto in the Agreement) among the Borrower, various financial institutions and JPMorgan Chase Bank, N.A., as Administrative Agent, and (b) certifies to each Lender as follows:

1. Attached as Schedule I are the financial statements of the Borrower as of and for the Fiscal _ Year _ Quarter (check one) ended                               ,                  .

2. Such financial statements have been prepared in accordance with Agreement Accounting Principles and fairly present in all material respects the financial condition of the Borrower as of the date indicated therein and the results of operations for the respective periods covered thereby.

3. Attached as Schedule II are detailed calculations used by the Borrower to establish whether the Borrower was in compliance with the requirements of Section 6.4 of the Agreement on the date of the financial statements attached as Schedule I.

4. Unless otherwise disclosed on Schedule III, neither a Default nor an Unmatured Default has occurred which is in existence on the date hereof or, if any Default or Unmatured Default is disclosed on Schedule III, the Borrower has taken or proposes to take the action to cure such Default or Unmatured Default set forth on Schedule III.

5. Except as described on Schedule IV, the representations and warranties of the Borrower set forth in the Agreement are true and correct on and as of the date hereof, with the same effect as though such representations and warranties had been made on and as of the date hereof or, if such representations and warranties are expressly limited to particular dates, as of such particular dates.

IN WITNESS WHEREOF, the undersigned has duly executed this Certificate as of __________, ________.

SOUTHWESTERN ENERGY COMPANY

By:

Print Name:

Title:

Schedule I

Financial Statements
(to be attached)

Schedule II

Compliance Calculations
(to be attached)

Schedule III

Defaults/Remedial Action
(to be attached)

Schedule IV

Qualifications to Representations and Warranties

EXHIBIT H

FORM OF

INCREASE REQUEST

_________________________, 20___

JPMorgan Chase Bank, N.A., as Administrative Agent

under the Credit Agreement referred to below

Ladies/Gentlemen:

Please refer to the Amended and Restated Credit Agreement dated as of January 4, 2005 among Southwestern Energy Company (the "Borrower"), various financial institutions and JPMorgan Chase Bank, N.A., as Administrative Agent (as amended, modified, extended or restated from time to time, the "Credit Agreement"). Capitalized terms used but not defined herein have the respective meanings set forth in the Credit Agreement.

In accordance with Section 2.6.3 of the Credit Agreement, the Borrower hereby requests an increase in the Aggregate Commitment from $__________ to $__________. Such increase shall be made by [increasing the Commitment of ____________ from $________ to $________] [adding _____________ as a Lender under the Credit Agreement with a Commitment of $____________] as set forth in the letter attached hereto. Such increase shall be effective three Business Days after the date that the Administrative Agent accepts the letter attached hereto or such other date as is agreed among the Borrower, the Administrative Agent and the [increasing] [new] Lender.

Very truly yours,

SOUTHWESTERN ENERGY COMPANY

By: __________________________________

Name: _________________________________

Title: __________________________________

ANNEX I TO EXHIBIT H

[Date]

JPMorgan Chase Bank, N.A., as Administrative Agent

under the Credit Agreement referred to below

Ladies/Gentlemen:

Please refer to the letter dated __________, 20__ from Southwestern Energy Company (the "Borrower") requesting an increase in the Aggregate Commitment from $__________ to $__________ pursuant to Section 2.6.3 of the Amended and Restated Credit Agreement dated as of January 4, 2005 among the Borrower, various financial institutions and JPMorgan Chase Bank, N.A., as Administrative Agent (as amended, modified, extended or restated from time to time, the "Credit Agreement"). Capitalized terms used but not defined herein have the respective meanings set forth in the Credit Agreement.

The undersigned hereby confirms that it has agreed to increase its Commitment under the Credit Agreement from $__________ to $__________ effective on the date which is three Business Days after the acceptance hereof by the Administrative Agent or on such other date as may be agreed among the Borrower, the Administrative Agent and the undersigned.

Very truly yours,

[NAME OF INCREASING LENDER]

By:_________________________

Title:______________________

Accepted as of

_________, ____

JPMORGAN CHASE BANK, N.A., as

Administrative Agent

By: ________________________________

Name: _____________________________

Title: _______________________________

ANNEX II TO EXHIBIT H

[Date]

JPMorgan Chase Bank, N.A., as Administrative Agent

under the Credit Agreement referred to below

Ladies/Gentlemen:

Please refer to the letter dated __________, 20___ from Southwestern Energy Company (the "Borrower") requesting an increase in the Aggregate Commitment from $__________ to $__________ pursuant to Section 2.6.3 of the Amended and Restated Credit Agreement dated as of January 4, 2005 among the Borrower, various financial institutions and JPMorgan Chase Bank, N.A., as Administrative Agent (as amended, modified, extended or restated from time to time, the "Credit Agreement"). Capitalized terms used but not defined herein have the respective meanings set forth in the Credit Agreement.

The undersigned hereby confirms that it has agreed to become a Lender under the Credit Agreement with a Commitment of $__________ effective on the date which is three Business Days after the acceptance hereof, and consent hereto, by the Administrative Agent or on such other date as may be agreed among the Borrower, the Administrative Agent and the undersigned.

The undersigned (a) acknowledges that it has received a copy of the Credit Agreement and the Schedules and Exhibits thereto, together with copies of the most recent financial statements delivered by the Borrower pursuant to the Credit Agreement, and such other documents and information as it has deemed appropriate to make its own credit and legal analysis and decision to become a Lender under the Credit Agreement; and (b) agrees that it will, independently and without reliance upon the Administrative Agent or any other Lender and based on such documents and information as it shall deem appropriate at the time, continue to make its own credit and legal decisions in taking or not taking action under the Credit Agreement.

The undersigned represents and warrants that (i) it is duly organized and existing and it has full power and authority to take, and has taken, all action necessary to execute and deliver this letter and to become a Lender under the Credit Agreement; and (ii) no notices to, or consents, authorizations or approvals of, any Person are required (other than any already given or obtained) for its due execution and delivery of this letter and the performance of its obligations as a Lender under the Credit Agreement.

The undersigned agrees to execute and deliver such other instruments, and take such other actions, as the Administrative Agent may reasonably request in connection with the transactions contemplated by this letter.

The following administrative details apply to the undersigned:

(A) Notice Address:

Legal name: __________________________

Address: _______________________________

_______________________________

_______________________________

Attention: _____________________________

Telephone: (___) _______________________

Facsimile: (___) ______________________

(B) Payment Instructions:

Account No.: ___________________________

At: #9; ___________________________

___________________________

___________________________

Reference: ___________________________

Attention: ___________________________

The undersigned acknowledges and agrees that, on the date on which the undersigned becomes a Lender under the Credit Agreement as set forth in the second paragraph hereof, the undersigned will be bound by the terms of the Credit Agreement as fully and to the same extent as if the undersigned were an original Lender under the Credit Agreement.

Very truly yours,

[NAME OF NEW LENDER]

By:_________________________

Title:______________________

Accepted and consented to as of

______________, 20___

JPMORGAN CHASE BANK, N.A.,

as Administrative Agent

By: _____________________________

Name: ___________________________

Title: ____________________________

Table of Contents

Page

ARTICLE I DEFINITIONS 1

1.1 Definitions 1

1.2 Other Interpretive Provisions 12

ARTICLE II THE CREDITS 12

2.1 Commitments 12

2.2 Types of Advances 13

2.3 Minimum Amount of Each Advance 13

2.4 Method of Selecting Types and Interest Periods for New Advances 13

2.5 Conversion and Continuation of Outstanding Advances 13

2.6 Commitment Fee; Voluntary Changes in Aggregate Commitment 14

2.7 Mandatory Reduction of the Aggregate Commitment 15

2.8 Prepayments 15

2.9 Interest Rates, etc 16

2.10 Rates Applicable After Default 16

2.11 Maturity 16

2.12 Method of Payment 16

2.13 Noteless Agreement; Evidence of Indebtedness 17

2.14 Telephonic Notices 17

2.15 Interest Payment Dates; Interest and Fee Basis 17

2.16 Notification of Advances, Interest Rates, Prepayments and Commitment Reductions 18

2.17 Lending Installations 18

2.18 Non-Receipt of Funds by the Administrative Agent 18

2.19 Replacement of Lender 19

2.20 Letters of Credit 19

2.20.1 #9; Issuance 19

2.20.2 #9; Participations 19

2.20.3 #9; Issuance or Modification of Letters of Credit 19

2.20.4 #9; Letter of Credit Fees 20

2.20.5 #9; Reimbursement by Borrower 20

2.20.6 #9; Reimbursement by Lenders 21

2.20.7 #9; Obligations Absolute 21

2.20.8 #9; Actions of Issuer 22

2.20.9 #9; Indemnification 22

2.20.10 Lenders' Indemnification 22

2.20.11 LC Collateral Account 23

2.20.12 Rights as a Lender 23

2.21 Swing Line Loans 23

2.21.1 Amount of Swing Line Loans 23

2.21.2 Method of Borrowing 23

2.21.3 Making of Swing Line Loans 24

2.21.4 Repayment of Swing Line Loans 24

3.1 Yield Protection 25

3.2 Changes in Capital Adequacy Regulations 26

3.3 Availability of Types of Advances 26

3.4 Funding Indemnification 26

3.5 Taxes 27

3.6 Lender Statements; Survival of Indemnity 28

ARTICLE IV CONDITIONS PRECEDENT 29

4.1 Initial Credit Extension 29

4.2 Each Credit Extension 30

ARTICLE V REPRESENTATIONS AND WARRANTIES 30

5.1 Organization 30

5.2 Authorization and Validity 31

5.3 Financial Statements 31

5.4 Subsidiaries 31

5.5 ERISA 31

5.6 Defaults 31

5.7 Accuracy of Information 31

5.8 Regulation U 31

5.9 Taxes 32

5.10 Liens 32

5.11 Compliance with Orders 32

5.12 Litigation 32

5.13 Burdensome Agreements 32

5.14 No Conflict 32

5.15 Title to Properties 33

5.16 Public Utility Holding Company Act 33

5.17 Regulatory Approval 33

5.18 Negative Pledge 33

5.19 Investment Company Act 33

5.20 Compliance with Laws 33

ARTICLE VI COVENANTS 33

6.1 Information 33

6.2 Affirmative Covenants 36

6.2.1 Reports and Inspection 36

6.2.2 Conduct of Business 36

6.2.3 Insurance 36

6.2.4 Taxes 37

6.2.5 Compliance with Laws 37

6.2.6 Maintenance of Properties 37

6.2.7 Additional Guarantors 37

6.3 Negative Covenants 37

6.3.1 Merger and Sale of Assets 37

6.3.2 Liens 39

6.3.3 Subsidiary Guarantors 41

6.3.4 Investments 41

6.3.5 Indebtedness of Subsidiaries 42

6.4 Financial Covenants 42

6.4.1 Debt to Capitalization Ratio 42

6.4.2 Interest Coverage Ratio 42

6.4.3 Net Worth 42

ARTICLE VII DEFAULTS 42

7.1 Events of Default 42

7.1.1 Representations and Warranties 42

7.1.2 Payment Default 43

7.1.3 Breach of Certain Covenants 43

7.1.4 Other Breach of this Agreement 43

7.1.5 ERISA 43

7.1.6 Cross-Default 43

7.1.7 Voluntary Bankruptcy, etc 43

7.1.8 Involuntary Bankruptcy, etc 43

7.1.9 Judgments 44

7.1.10 Environmental Matters 44

7.1.11 Subsidiary Guaranty 44

ARTICLE VIII ACCELERATION, WAIVERS, AMENDMENTS AND REMEDIES; RELEASES OF GUARANTORS 44

8.1 Acceleration 44

8.2 Amendments 45

8.3 Preservation of Rights 45

8.4 Releases of Guarantors 46

ARTICLE IX GENERAL PROVISIONS 46

9.1 Survival of Representations 46

9.2 Governmental Regulation 46

9.3 Headings 46

9.4 Entire Agreement 46

9.5 Several Obligations; Benefits of this Agreement 46

9.6 Expenses; Indemnification 46

9.7 Numbers of Documents 47

9.8 Accounting 47

9.9 Severability of Provisions 47

9.10 Nonliability of Lenders 47

9.11 Confidentiality 48

9.12 Nonreliance 48

9.13 Disclosure 48

ARTICLE X THE ADMINISTRATIVE AGENT 48

10.1 Appointment; Nature of Relationship 48

10.2 Powers 49

10.3 General Immunity 49

10.4 No Responsibility for Loans, Recitals, etc 49

10.5 Action on Instructions of Lenders 49

10.6 Employment of Agents and Counsel 50

10.7 Reliance on Documents; Counsel 50

10.8 Administrative Agent's Reimbursement and Indemnification 50

10.9 Notice of Default 51

10.10 Rights as a Lender 51

10.11 Lender Credit Decision 51

10.12 Successor Administrative Agent 51

10.13 Delegation to Affiliates 52

10.14 Other Agents 52

ARTICLE XI SETOFF; RATABLE PAYMENTS 52

11.1 Setoff 52

11.2 Ratable Payments 53

ARTICLE XII BENEFIT OF AGREEMENT; ASSIGNMENTS; PARTICIPATIONS 53

12.1 Successors and Assigns 53

12.2 Participations 53

12.2.1 Permitted Participants; Effect 53

12.2.2 Voting Rights 54

12.3 Assignments 54

12.3.1   Permitted Assignments 54

12.3.2  Effect; Effective Date 54

12.4 Dissemination of Information 55

12.5 Tax Treatment 55

ARTICLE XIII NOTICES 55

ARTICLE XIV COUNTERPARTS 56

ARTICLE XV CHOICE OF LAW; CONSENT TO JURISDICTION; WAIVER OF JURY TRIAL; MAXIMUM INTEREST RATE 56

15.1 CHOICE OF LAW 56

15.2 CONSENT TO JURISDICTION 56

15.3 WAIVER OF JURY TRIAL 56

15.4 Maximum Interest Rate 57

ARTICLE XVI AMENDMENT AND RESTATEMENT OF EXISTING AGREEMENT 57

ARTICLE XVII USA PATRIOT ACT NOTIFICATION 58

End of TOC - Do not delete this paragraph!

SCHEDULES
Schedule 1A Commitments
Schedule 1B Pricing Schedule

Schedule 5.4 Subsidiaries
Schedule 5.12 Litigation
Schedule 5.18 Negative Pledges
Schedule 6.2 Insurance

EXHIBITS

Exhibit A Form of Borrowing Notice
Exhibit B Form of Opinion of Counsel to Borrower
Exhibit C Form of Assignment Agreement
Exhibit D Form of Money Transfer Instructions
Exhibit E Form of Note
Exhibit F Form of Subsidiary Guaranty
Exhibit G Form of Compliance Certificate

Exhibit H Form of Increase Request

EX-10

SOUTHWESTERN ENERGY COMPANY

NON-QUALIFIED STOCK OPTION

(Not Transferable)

        THIS CERTIFIES, that SOUTHWESTERN ENERGY COMPANY, an Arkansas corporation (the "Company"), has, as of the ___ day of _________, _______, granted to ____________________ (the "Participant"), a Non-Qualified Stock Option to purchase ______ shares (the "Optioned Shares") of the Company's Common Stock ($.10 par value) ("Company Stock") on the terms and conditions of the SOUTHWESTERN ENERGY COMPANY 2004 STOCK INCENTIVE PLAN, as may be amended from time to time (the "Plan").

        This Non-Qualified Stock Option is granted under and pursuant to the Plan and is subject to the conditions and limitations set forth in the Plan as the same may be amended from time to time. All of the terms and provisions of the Plan, as amended from time to time, are incorporated herein by reference and nothing herein contained shall be deemed to vary or be given effect as modifying the terms of the Plan.

        Except as otherwise provided in the Plan, this Non-Qualified Stock Option shall be exercisable only in accordance with the provisions of this Certificate and the Plan.

        The exercise price of the Optioned Shares shall be $______ per share.

        This Non-Qualified Stock Option is not transferable except by will or the laws of descent and distribution.

        This Non-Qualified Stock Option shall be exercisable in whole or in part; provided, that no partial exercise shall be for an aggregate exercise price of less than $1,000. The partial exercise of this Non-Qualified Stock Option shall not cause the expiration, termination or cancellation of the remaining portion hereof.

        This Non-Qualified Stock Option shall be exercised by delivering notice to the Company's principal office, to the attention of its Secretary, no less than one business day in advance of the effective date of the proposed exercise. Such notice shall be accompanied by this Certificate, shall specify the number of Optioned Shares with respect to which this Non-Qualified Stock Option is being exercised and the effective date of the proposed exercise and shall be signed by the Participant. The Participant may withdraw such notice at any time prior to the close of business on the business day immediately preceding the effective date of the proposed exercise.

        Payment for Optioned Shares purchased upon the exercise of this Non-Qualified Stock Option shall be made on the effective date of such exercise in accordance with the terms of the Plan.

        THIS NON-QUALIFIED STOCK OPTION SHALL FIRST BECOME EXERCISABLE WITH RESPECT TO THE FOLLOWING PERCENTAGE OF THE TOTAL SHARES SUBJECT HERETO ON THE FOLLOWING DATES:

Percentage of Total Shares First Date on Which Such Percentage of Total Shares Becomes Exercisable

        THIS NON-QUALIFIED STOCK OPTION SHALL BECOME FULLY VESTED AT THE EARLIER OF ______________ ____ OR UPON THE PARTICIPANT'S RETIREMENT PROVIDED PARTICIPANT HAS REACHED NORMAL RETIREMENT AGE (SIXTY-FIVE (65)), AS DEFINED IN THE SOUTHWESTERN ENERGY COMPANY PENSION PLAN. PROVIDED, HOWEVER, UPON THE OCCURRENCE OF A CHANGE IN CONTROL, IF AND TO THE EXTENT IT STILL IS OUTSTANDING, THIS NON-QUALIFIED STOCK OPTION SHALL BECOME FULLY AND IMMEDIATELY EXERCISABLE AND SHALL REMAIN EXERCISABLE UNTIL ITS EXPIRATION, TERMINATION OR CANCELLATION PURSUANT TO THE TERMS OF THE PLAN.

        THIS NON-QUALIFIED STOCK OPTION SHALL EXPIRE AND BE VOID AND SHALL NOT BE EXERCISABLE AFTER THE EXPIRATION OF SEVEN (7) YEARS FROM THE DATE AS OF WHICH IT WAS GRANTED AND MAY BE EXERCISED ONLY IN THE MANNER PROVIDED IN THE PLAN. THIS NON-QUALIFIED STOCK OPTION SHALL BE SUBJECT TO EARLIER TERMINATION, EXPIRATION OR CANCELLATION AS PROVIDED IN THE PLAN.

        Pursuant to Sections 6(e)(2) and 6(e)(3) of the Plan, and notwithstanding anything to the contrary contained in this Certificate concerning the effect of termination of employment, if Participant's employment with Southwestern terminates for death, disability, or retirement, the Non-Qualified Stock Option granted hereunder shall remain exercisable until the first anniversary of such termination; provided, however, that no Non-Qualified Stock Option shall be exercisable after the expiration of its original term.

        By accepting this Certificate, the Participant agrees to all of the terms and conditions of the Plan as the same may be amended from time to time, and acknowledges that the Participant may review a complete copy of the Plan, which is on file in the office of the Secretary of Southwestern Energy Company, 2350 N. Sam Houston Parkway East, Suite 300, Houston, TX 77032.

2

        IN WITNESS WHEREOF, the Company has issued this Non-Qualified Stock Option Certificate by its undersigned duly authorized officer as of the ____ day of _____________, _______.

	SOUTHWESTERN ENERGY COMPANY
ATTEST: (Seal)	By:
By:
		(Participant)

3

EX-21

EXHIBIT 21

LIST OF SUBSIDIARIES

Subsidiary Name	State of Incorporation or Organization
Arkansas Western Gas Company	Arkansas
Seeco, Inc.	Arkansas
Southwestern Energy Production Company	Arkansas
Diamond "M" Production Company	Delaware
Southwestern Energy Services Company	Arkansas
Southwestern Energy Pipeline Company	Arkansas
A.W. Realty Company	Arkansas
Overton Partners, L.P.	Texas

EX-23

EXHIBIT 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We hereby consent to the incorporation by reference in the Registration Statements on Form S-8 (File Nos. 333-03787, 333-03789, 333-64961, 333-96161, 333-42494, 333-69720, 333-100702, 333-101160, 333-110140 and 333-121720) and Form S-3 (File Nos. 033-63895 and 333-101658) of Southwestern Energy Company of our report dated March 4, 2005 relating to the financial statements, management's assessment of the effectiveness of internal control over financial reporting and the effectiveness of internal control over financial reporting, which appears in this Form 10-K.

 
/s/ PricewaterhouseCoopers LLP

Tulsa, Oklahoma
March 8, 2005

EX-23

Exhibit 23.2

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS AND GEOLOGISTS

As independent petroleum engineers, we hereby consent to the reference in this Form 10-K of Southwestern Energy Company to our Firm's name and our Firm's audit of the proved oil and gas reserve quantities as of December 31, 2004, and to the incorporation by reference of our Firm's name and review into Southwestern Energy Company's previously filed Registration Statements on Form S-8 (File Nos. 333-03787, 333-03789, 333-64961, 333-96161, 333-42494, 333-69720, 333-100702, 333-101160 and 333-110140) and Form S-3 (File No. 333-101658).

NETHERLAND, SEWELL & ASSOCIATES, INC.
By	/s/ J. CARTER HENSON, JR.
	J. Carter Henson, Jr.
	Senior Vice President

Houston, Texas
February 23, 2005

EX-31

EXHIBIT 31.1

CERTIFICATION

I, Harold M. Korell, Chief Executive Officer of Southwestern Energy Company, certify that:
	1. I have reviewed this annual report on Form 10-K of Southwestern Energy Company;
	2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
	3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
	4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:
		(a.) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
		(b.) designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
		(c.) evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
		(d.) disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's control over financial reporting; and
	5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent function):
		(a.) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
		(b.) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.
Date:	March 8, 2005		/s/ HAROLD M. KORELL
				Harold M. Korell
				Chief Executive Officer

EX-31

EXHIBIT 31.2

CERTIFICATION

I, Greg D. Kerley, Chief Financial Officer of Southwestern Energy Company, certify that:
	1. I have reviewed this annual report on Form 10-K of Southwestern Energy Company;
	2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
	3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
	4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:
		(a.) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
		(b.) designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
		(c.) evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
		(d.) disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's control over financial reporting; and
	5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent function):
		(a.) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
		(b.) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.
Date:	March 8, 2005		/s/ GREG D. KERLEY
				Greg D. Kerley
				Chief Financial Officer

EX-32

EXHIBIT 32

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

          Pursuant to section 906 of the Sarbanes-Oxley Act of 2002 (subsections (a) and (b) of section 1350, chapter 63 of title 18, United States Code), each of the undersigned officers of Southwestern Energy Company, an Arkansas corporation (the "Company"), does hereby certify that:

          The Annual Report on Form 10-K for the year ended December 31, 2004 (the "Form 10-K") of the Company fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934 and information contained in the Form 10-K fairly presents, in all material respects, the financial condition and results of operations of the Company.

Dated: March 8, 2005	/s/ HAROLD M. KORELL
	Harold M. Korell
	Chief Executive Officer
Dated: March 8, 2005	/s/ GREG D. KERLEY
	Greg D. Kerley
	Chief Financial Officer