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, 2006

Commission file number 1-08246

Southwestern Energy Company

(Exact name of Registrant as specified in its charter)

Delaware (State or other jurisdiction of incorporation or organization)	71-0205415 (I.R.S. Employer Identification No.)
2350 North Sam Houston Parkway East, Suite 125, Houston, Texas (Address of principal executive offices)	77032 (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 $0.01 (including associated stock purchase rights)	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 if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yesx     Noo   

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yeso    Nox   

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. Yesx   Noo   

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 a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act.  (Check one):

Large accelerated filer x Accelerated Filer o Non-accelerated filer o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes o     No x 

The aggregate market value of the voting stock held by non-affiliates of the registrant was $5,111,562,867 based on the New York Stock Exchange – Composite Transactions closing price on June 30, 2006, of $31.16. For purposes of this calculation, the registrant has assumed that its directors and executive officers are affiliates.

As of February 23, 2007, the number of outstanding shares of the registrant’s Common Stock, par value $0.01, was 168,981,002.  

Document Incorporated by Reference

Portions of the registrant’s definitive proxy statement to be filed with respect to the annual meeting of stockholders to be held on or about May 10, 2007 are incorporated by reference into Part III of this Form 10-K.

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SOUTHWESTERN ENERGY COMPANY
ANNUAL REPORT ON FORM 10-K
For Fiscal Year Ended December 31, 2006

TABLE OF CONTENTS

		Page
PART I
Item 1.	Business	3
	Glossary of Certain Industry Terms	20
Item 1A.	Risk Factors	23
Item 1B.	Unresolved Staff Comments	30
Item 2.	Properties	30
Item 3.	Legal Proceedings	32
Item 4.	Submission of Matters to a Vote of Security Holders	33
PART II
Item 5.	Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	34
Item 6.	Selected Financial Data	36
Item 7.	Management's Discussion and Analysis of Financial Condition and Results of Operations
	Overview	38
	Results of Operations	39
	Liquidity and Capital Resources	46
	Critical Accounting Policies	51
	Forward-Looking Information	54
Item 7A.	Quantitative and Qualitative Disclosures about Market Risk	56
Item 8.	Financial Statements and Supplementary Data	58
	Index to Consolidated Financial Statements	58
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	87
Item 9A.	Controls and Procedures	87
Item 9B.	Other Information	87
PART III
Item 10.	Directors, Executive Officers and Corporate Governance	88
Item 11.	Executive Compensation	88
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	88
Item 13.	Certain Relationships and Related Transactions, and Director Independence	88
Item 14.	Principal Accounting Fees and Services	88
PART IV
Item 15.	Exhibits, Financial Statement Schedules	89

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 1A of Part I and to “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Forward-Looking Information” 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 Commis sion, or the SEC, on our website at www.swn.com.  Our corporate governance guidelines and the charters of the Audit, Compensation, Nominating and Governance and Retirement Committees of our Board of Directors are available on our website, and are available in print free of charge to any stockholder upon request.

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PART I

ITEM 1.  BUSINESS

Southwestern Energy Company is an integrated energy company primarily engaged in exploring for and producing natural gas.  We conduct the majority of our exploration and production (E&P) operations in four general regions — the Arkoma Basin, East Texas, the Permian Basin and the onshore Gulf Coast.  We also focus on creating and capturing additional value through our drilling, gathering, marketing and natural gas distribution businesses.  

Our operations are conducted in the following three segments:

1.

Exploration and Production - Our primary business is natural gas and oil exploration, development and production within the United States, with operations principally located in Arkansas, Oklahoma, Texas and New Mexico.  We engage in natural gas and oil exploration and production through our wholly-owned subsidiaries, SEECO, Inc., Southwestern Energy Production Company, or SEPCO, and Diamond “M” Production Company. SEECO operates exclusively in Arkansas, holds a large base of both developed and undeveloped gas reserves and conducts both the ongoing conventional drilling program in the Arkansas part of the Arkoma Basin and the drilling program for the Fayetteville Shale play.  SEPCO conducts development drilling and exploration programs in the Arkoma Basin, Texas and New Mexico.  Diamond “M” has interests in properties in the Permian Basin of Texas.  DeSoto Drilling, Inc., or DDI, a wholly-owned subsidiary of SEPCO, operates drilling rigs in the Fayetteville Shale play and in East Texas.  

2.

Midstream Services - Our Midstream Services segment generates revenue through the marketing of our own gas production and some third-party natural gas and from gathering fees associated with the transportation of natural gas to market.  Our gas marketing subsidiary, Southwestern Energy Services Company, captures downstream opportunities which arise through marketing and transportation activity.  Our gathering subsidiary, DeSoto Gathering Company, L.L.C., engages in gathering activities primarily related to the development of our Fayetteville Shale play.

3.

Natural Gas Distribution - We are also engaged in the distribution and transmission of natural gas.  Our wholly-owned subsidiary, Arkansas Western Gas Company, or Arkansas Western, operates integrated natural gas distribution systems in northern Arkansas serving approximately 151,000 retail customers.  

The vast majority of our operating income and cash flow is derived from our E&P business.  In 2006, 96% of our operating income and 93% of our earnings before interest, taxes, depreciation, depletion and amortization, or EBITDA, were generated from our E&P business.  Our Midstream Services and Natural Gas Distribution segments each generated 2% of our operating income and 1% and 3%, respectively, of our EBITDA in 2006.  In 2005, our E&P, Midstream Services and Natural Gas Distribution segments generated 95%, 3% and 2% of our operating income and 94%, 3% and 3% of our EBITDA, respectively.  In 2004, our E&P, Midstream Services and Natural Gas Distribution segments generated 90%, 5%, and 5% of our operating income and 91%, 3% and 6% of our EBITDA, respectively.  We refer you to “Business — Other Items — Reconciliation of Non-GAAP Measures” in Item 1 of Part I of this Fo rm 10-K for a table that reconciles EBITDA with our net income as derived from our audited financial information.

Our Business Strategy

We are 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 Present Value Index, or 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 projects. Our actual PVI results are utilized to help determine the allocation of our future capital investments.  The key elements of our E&P business strategy are:

·

Exploit and Develop Our Existing Asset Base.  We seek to maximize the value of our existing asset base by developing properties that have production and reserve growth potential while also controlling per unit production costs.  Our primary focus is our Fayetteville Shale play, where we hold approximately 892,000 net acres.  Our large acreage position holds significant production and reserve growth potential.  We intend to aggressively develop our acreage position by accelerating our drilling program and by improving individual well results through the use of advanced technologies and detailed technical analysis of our properties.  In our other operating areas, we intend to

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increase our reserves and production by drilling infill locations, expanding known field limits and selectively recompleting existing wells.   

·

Grow Through New Exploration and Development Activities.  We actively seek to find and develop new conventional natural gas and oil properties with significant exploration and exploitation potential, as well as new unconventional resource plays, which we call New Ventures.  New prospects are evaluated based on repeatability, multi-well potential and land availability as well as other criteria.  Our Fayetteville Shale play began as a New Venture project in 2002.

·

Maximize Efficiency Through Economies of Scale.  In our key operating areas, the concentration of our properties allows us to achieve economies of scale in our drilling and production operations that result in lower costs.  Our new drilling company, DDI, has already achieved a level of economies of scale with respect to the drilling of our wells in the Fayetteville Shale play by operating a fleet of rigs designed specifically for the play. DDI has also utilized smaller truck-mounted rigs to drill the vertical portion of the wellbore, decreasing both the number of drilling days and total well costs.

·

Rationalize Our Property Portfolio.  We actively pursue opportunities to reduce production costs of our properties and improve overall return, including selling marginal properties from our E&P portfolio of assets and acquiring producing properties and leasehold acreage in the regions in which we operate.  We also seek to acquire operational control of properties with significant unrealized exploration and exploitation potential.

Recent Developments

2007 Planned Capital Investments and Production Guidance.  On December 15, 2006, we announced a planned capital investment program for 2007 of $1,341 million, an increase of 42% over our 2006 capital program.  Our 2007 capital program includes $1,237 million for our E&P segment, $84 million for our Midstream Services segment, and $20 million for improvements to our utility systems and for other corporate purposes.  The increased capital program is expected to be primarily funded by internally-generated cash flow, borrowings under our revolving credit facility (discussed below) and/or funds raised in the public debt and equity markets.  We also announced our targeted 2007 oil and gas production of approximately 105.0 to 110.0 Bcfe, an increase of approximately 45% to 50% over our production in 2006.

Amended and Restated Revolving Credit Agreement.  On February 9, 2007, we amended and restated our $500 million unsecured revolving credit facility that was due to expire in January 2010, increasing the borrowing capacity to $750 million, lowering the borrowing costs and extending the maturity date to February 2012.  The amount available under the credit agreement can be increased by up to $250 million in the future upon the agreement of the company and our existing or additional lenders.

Sale and Leaseback of Drilling Rigs. On December 29, 2006, we entered into a sale and leaseback transaction through which we sold 13 drilling rigs and related equipment owned by us to various financial institutions and then leased such drilling rigs and equipment back, along with two additional drilling rigs and related equipment, pursuant to a Master Lease Agreement of the same date with the same institutions as lessors.  We received $127.3 million in cash for the 13 rigs and related equipment and recorded a deferred gain of $7.4 million which will be amortized over the lease term.  

Pipeline Precedent Agreement.  On December 15, 2006, our subsidiary, Southwestern Energy Services Company, or SES, signed a precedent agreement pursuant to which SES will contract for firm gas transportation services on two newly-proposed pipeline laterals and related facilities of Texas Gas Transmission, LLC, a subsidiary of Boardwalk Pipeline Partners, L.P. SES will be a “Foundation Shipper” for the project and will use the proposed laterals and related facilities primarily to deliver gas volumes produced from our operations in the Fayetteville Shale play in central Arkansas. Depending on regulatory approvals, the expected in-service date for both laterals is January 1, 2009.  

Sale of Interest in NOARK.  On May 2, 2006, we sold our 25% interest in NOARK Pipeline System, L.P., or NOARK, a partnership that owns a 723-mile integrated interstate pipeline system known as Ozark Gas Transmission System, to Atlas Pipeline Partners, L.P. for $69.0 million, resulting in a pre-tax gain of $10.9 million.  

Sale of South Louisiana Properties.  During the fourth quarter of 2006, we completed the sale of our remaining South Louisiana properties to a private company for $12.7 million. These properties had proved reserves of 7.0 Bcfe and produced approximately 1.1 Bcfe for the twelve months ended prior to the sale.  As a result of this divestiture, we no longer have producing properties in the South Louisiana area.

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Exploration and Production

We operate our E&P business in four general regions — the Arkoma Basin, East Texas, the Permian Basin and the onshore Gulf Coast.  Our E&P business is organized into asset management teams based on the geographic location of our exploration and development projects.  In addition to our core areas of operations, we actively seek to develop new conventional exploration projects as well as unconventional plays with significant exploration and exploitation potential.

Operating income from our E&P segment was $237.3 million in 2006, up from $234.8 million in 2005 and $164.6 million in 2004.  EBITDA from our E&P segment was $386.4 million in 2006, compared to $325.9 million in 2005 and $231.1 million in 2004.  The increases in both our operating income and EBITDA in 2006 and 2005 were due to increased production volumes and higher realized prices, partially offset by increases in operating costs and expenditures.  We refer you to “Business — Other Items — Reconciliation of Non-GAAP Measures” in Item 1 of Part I of this Form 10-K for a reconciliation of EBITDA with our net income.  

Our estimated proved natural gas and oil reserves were 1,026 Bcfe at December 31, 2006, up from 827 Bcfe at year-end 2005 and 646 Bcfe at year-end 2004.  The overall increase in total reserves in the past three years is primarily due to the discovery and development of the Fayetteville Shale play in Arkansas, the accelerated development of our Overton Field in East Texas and our continued conventional drilling program in the Arkoma Basin.  Our year-end 2006 reserves had a pre-tax PV-10 value of $1,309 million, compared to $1,986 million at year-end 2005 and $1,218 million at year-end 2004.  The after-tax PV-10 was $1,043 million at year-end 2006, $1,421 million at year-end 2005 and $892 million at year-end 2004.  The decrease in the 2006 pre-tax and after-tax PV-10 values of our reserves is primarily due to a lower market price for natural gas at December 31, 2006.  At December 31, 2006, the market pric es for natural gas and crude oil that were used to calculate our PV-10 value were $5.64 per Mcf and $57.25 per barrel, respectively, compared to $10.08 per Mcf and $61.04 per barrel at December 31, 2005 and $6.18 per Mcf and $43.45 per barrel at December 31, 2004.  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 and to the risk factor “Although our estimated natural gas and oil reserve data is independently audited, our estimates may still prove to be inaccurate” in Item 1A of Part I of this Form 10-K and to “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Forward-Looking Information” in Item 7 of Part II of this Form 10-K for a discussion of the risks inherent in utilization of standardized measures and estimated reserve data.

Approximately 95% of our year-end proved reserves were natural gas and 65% were classified as proved developed.  We operate approximately 77% of our reserves, based on our PV-10 value, and our average proved reserves-to-production ratio, or average reserve life, approximated 14.2 years at year-end 2006.  Sales of natural gas production accounted for 91% of total operating revenues for this segment in 2006 and 92% in both 2005 and 2004.  Natural gas production has 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.

Our reserve replacement ratio has exceeded 300% for the last three years including 2006, where our results were primarily driven by reserve additions associated with our Fayetteville Shale play.  In 2006, we replaced 386% of our production volumes by adding 365.5 Bcfe of proved natural gas and oil reserves at a finding and development cost of $2.75 per Mcfe, including a downward reserve revision of 86.6 Bcfe but excluding $94 million of capital invested in drilling rigs and related equipment which were subsequently sold and then leased back. In 2005 and 2004, our reserve replacement

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ratios were 399% and 365%, respectively, and our finding and development costs were $1.71 per Mcfe and $1.43 per Mcfe, respectively, including net downward reserve revisions of 31.7 Bcfe in 2005 and 12.7 Bcfe in 2004 but excluding $35 million in capital invested in drilling rigs in 2005.  The downward reserve revisions during 2006 were primarily due to a comparative decrease in year-end gas prices, combined with performance revisions in our East Texas and conventional Arkoma Basin properties, which were partially offset by an upward performance revision in our Fayetteville Shale properties.  The downward reserve revisions in 2005 and 2004 were primarily due to adjustments to the terminal decline rates for wells at our Overton Field and declines associated with our Gulf Coast properties.  The increase in our finding and development costs primarily reflects the general increase in material costs and oilf ield service costs to drill and complete wells in our key operating areas, and we expect this trend to continue in the future.  For the period ending December 31, 2006, our three-year average reserve replacement ratio was 384%, and our three-year average finding and development cost was $2.04 per Mcfe, including reserve revisions and excluding our investments in drilling rigs.

Our reserve replacement ratio during 2006, excluding the effect of reserve revisions, was 505%, compared to 450% in 2005 and 388% in 2004.  Our finding and development cost, excluding revisions and our investments in drilling rigs, was $2.10 per Mcfe in 2006, compared to $1.51 per Mcfe in 2005 and $1.34 per Mcfe in 2004.  The increases in our finding and development costs during this time period were primarily due to higher costs for drilling and other field services, and we expect this trend to continue in the future.  Excluding reserve revisions and our investments in drilling rigs, our three-year average reserve replacement ratio is 454% and our three-year average finding and development cost is $1.72 per Mcfe.

The following table provides information as of December 31, 2006, related to proved reserves, well count, net acreage, PV-10, and 2006 annual information as to production and capital investments, 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)	277	300	383	51	15	-	1,026
Percent of Total	27%	29%	37%	5%	2%	-	100%
Percent Natural Gas	100%	100%	96%	36%	95%	100%	95%
Percent Proved Developed	78%	27%	80%	89%	100%	100%	65%
Production (Bcfe)	20.1	11.8	32.0	5.8	2.6	-	72.3
Capital Investments (millions)(1)	$97	$388(1)	$204	$25	$7	$46(1)	$767
Total Gross Producing Wells	1,009	162	393	411	38	5	2,018
Total Net Producing Wells	493	145	336	160	16	3	1,153
Total Net Acreage	461,761(2)	766,654(3)	94,076(4)	33,193	12,242	99,301	1,467,227
Net Undeveloped Acreage	271,259(2)	715,895(3)	67,488(4)	4,892	5,017	89,592	1,154,143
PV-10:
Pre-tax (millions)	$470	$158	$537	$114	$29	$1	$1,309
After-tax (millions)	$375	$126	$428	$91	$23	-	$1,043
Percent of Total	36%	12%	41%	9%	2%	-	100%
Percent Operated	82%	99%	75%	45%	57%	100%	77%

(1)  Our Fayetteville Shale play capital investments include $29 million in leasehold acquisition costs and exclude $94 million related to the purchase of drilling rigs and related equipment which was sold in December 2006 as part of a sale and leaseback transaction.  New Ventures capital investments included $3 million relating to drilling wells in the Arkoma Basin that are now part of our Arkoma Conventional program.

(2)  Includes 123,442 net developed acres and 1,930 net undeveloped acres in our Conventional Arkoma Basin operating area that are also within our Fayetteville Shale focus area but not included in the Fayetteville Shale acreage in the table above.

(3)  Assuming we do not drill successful wells to develop the acreage and do not extend the leases in our undeveloped acreage in the Fayetteville Shale play, leasehold expiring over the next three years will be 6,304 net acres in 2007, 19,451 net acres in 2008, and 105,593 net acres in 2009.

(4)  Assuming we do not drill successful wells to develop the acreage and do not extend the leases in our undeveloped acreage in the Angelina River Trend in East Texas, leasehold expiring over the next three years will be 404 net acres in 2007, 20,620 net acres in 2008, and 27,300 net acres in 2009.

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 to the south and east of the traditional Fairway area and west into the Oklahoma

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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 Arkansas as our “conventional Arkoma” drilling program. Our Fayetteville Shale play represents our unconventional drilling program in the Arkoma Basin.  At December 31, 2006, we had approximately 577 Bcf of natural gas reserves in the Arkoma Basin, representing approximately 56% of our total reserves, up from 372 Bcf at year-end 2005 and 247 Bcf at year-end 2004.  

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 277 Bcf of our reserves at year-end 2006 were attributable to our conventional Arkoma wells.  During 2006, we invested $97 million and participated in 84 wells with 54 producers, four dry holes and 26 wells in progress at year-end, resulting in a 93% drilling success rate while adding 51.6 Bcf of gas reserves at a finding and development cost of $4.04 per Mcf, including a net downward reserve revision of 27.5 Bcf primarily related to lower gas prices and an increase in the terminal decline rates for some of our properties.  This compares to finding and development costs of $1.25 per Mcf in 2005 and $1.11 per Mcf in 2004, including net downward reserve revisions of 0.7 Bcf in 2005 and net upwar d reserve revisions of 4.5 Bcf in 2004.  Excluding revisions, finding and development costs would have been $1.89 per Mcf in 2006 and $1.23 per Mcf in both 2005 and 2004.  The increase in our finding costs during this time period was primarily due to higher costs for drilling and other oilfield services.  Our gas production from our conventional drilling program in the Arkoma Basin was 20.1 Bcf during 2006, or approximately 55.1 MMcf per day, compared to 20.2 Bcf in 2005 and 20.1 Bcf in 2004.  Production over this time period has remained fairly constant as our drilling investment is offsetting the natural production decline from existing wells.  

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 $1.74 per Mcf, including revisions (or $1.46 per Mcf excluding revisions), and three-year average production, or lifting, costs of $0.60 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 2006 at $0.64 per Mcf (including production taxes), compared to $0.68 per Mcf in 2005 and $0.48 per Mcf in 2004.    

Our strategy in the Fairway is to continue to delineate new geologic prospects and extend previously identified trends using our extensive expertise in the area.  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 had previously been less explored.  One of these newer areas is our Ranger Anticline prospect area, or Ranger, located at the southern edge of the Arkansas portion of the basin, where we have significantly increased our drilling activity over the last few years.  

Our wells at Ranger have primarily targeted the Upper and Lower Borum tight gas sands between 5,000 and 8,000 feet in depth.  We drilled our first successful well at Ranger in 1997, and as our understanding of the geology at Ranger has grown, the potentially productive area in the field has expanded.  In 2005, we extended the field boundaries to the east approximately nine miles.  In 2006, much of our drilling at Ranger Anticline has focused on the area located between the main producing part of the field and this eastern extension where we have drilled several higher-rate wells.  Wells completed in 2006 had average estimated ultimate gross reserves of 1.9 Bcf per well.

From 1997 through year-end 2006, we successfully drilled 104 out of 118 wells, adding 95.7 net Bcf of reserves at a finding and development cost of $1.52 per Mcf, including reserve revisions.  During 2006, we successfully completed 27 out of 29 wells (excluding 15 wells in progress at year-end 2006), which added 28.8 Bcf of new reserves.  Net production from the field during 2006 was 5.7 Bcf, up from 5.6 Bcf in 2005 and 3.5 Bcf in 2004.  Our average working interest in the 104 successful wells drilled through December 31, 2006, is 77% and our average net revenue interest is 63%.

We continue to increase our acreage position at Ranger and, as of December 31, 2006, we held approximately 16,000 gross developed acres and 58,240 gross undeveloped acres and had regulatory approval for well spacing at a minimum distance of 560 feet between wells. Our average working interest in our gross undeveloped acreage position at Ranger is 46%.  We believe that Ranger holds significant future development potential.

Late in the third quarter of 2005, we drilled the initial exploratory well on our Midway prospect, which is located eleven miles north of Ranger.  The USA #1-24 well encountered pay in the Pennsylvania-age Basham and Borum sands, which are also the producing horizons at Ranger. In 2006, we drilled five offsets to the USA #1-24 discovery.  Four of these six wells are producing while the remaining wells were waiting on pipeline connection.  Depending on the performance of the newly drilled wells, there may be significant drilling potential on our Midway acreage block. At December 31, 2006, we held approximately 28,650 gross acres in our Midway prospect area.

Our conventional Arkoma Basin drilling program continues to be an important focus for our capital program and we intend to allocate funds to our development drilling and workover programs at a level that, at a minimum, maintains our

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production and reserve base in this area.  In 2007, we plan to invest approximately $116 million in the conventional Arkoma program and will drill approximately 100 to 110 wells, including 50 to 60 wells at the Ranger Anticline.

Fayetteville Shale Play.  Our emerging Fayetteville Shale play, which we announced in August 2004, is now the primary focus of our E&P business.  The Fayetteville Shale is an unconventional gas reservoir located on the Arkansas side of the Arkoma Basin, ranging in thickness from 50 to 550 feet and ranging in depth from 1,500 to 6,500 feet.  The 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. Approximately 300 Bcf of our reserves at year-end 2006 were attributable to our Fayetteville Shale play, up from approximately 101 Bcf at year-end 2005.

At December 31, 2006, we held a total of approximately 892,000 net acres in the play area (716,000 net undeveloped acres, 51,000 net developed acres held by Fayetteville Shale production and approximately 125,000 net acres held by conventional production).  Excluding our acreage held by conventional production, our acreage position had an average lease term of 7 years, an average royalty interest of 15% and was obtained at an average cost of $95 per acre.  To date, we have established production from the Fayetteville Shale in 28 separate pilot areas located in eight counties in Arkansas over an area which represents approximately 45% of our total acreage position.  During 2007, we expect to test a large portion of our remaining acreage position to determine its productivity.  During 2006, we also tested gas from both the Moorefield Shale and Chattanooga (Woodford) Shale, which are located beneath the Fayette ville Shale. We believe that approximately 130,000 of our net undeveloped acres also holds potential for the Moorefield Shale.  Our Chattanooga Shale test well is located on our acreage that is held by conventional production in the Fairway area of the basin.

During the third quarter of 2006, the Arkansas Oil and Gas Commission approved statewide field rules in the Fayetteville Shale, the Moorefield Shale, and the Chattanooga Shale as “unconventional sources of supply.”  Under the statewide rules, each drilling unit would consist of a governmental section of approximately 640 acres and operators would be permitted to drill up to 16 wells per drilling unit for each unconventional source of supply.  At December 31, 2006, based on the assumptions contained in the field rule applications for these fields, we estimate that the expected drainage from our horizontal wells will be less than 80 acres per well based on existing microseismic data and reservoir simulation modeling.  We refer you to “Risk Factors — We may have difficulty drilling all of the wells that are necessary to hold our Fayetteville Shale acreage before the initial lease terms expire, wh ich could result in the loss of certain leasehold rights” in Item 1A of Part I of this Form 10-K.

Since 2004, we have increased our capital investments dramatically as we have accelerated our drilling program in the play area.  In 2006, we invested approximately $388 million in our Fayetteville Shale play, which included $316 million to spud 196 wells, $29 million for leasehold acquisition, $14 million for seismic and $29 million in capitalized costs and other expenses.  In 2005, we invested approximately $119 million, which included $67 million to spud 67 wells, $41 million for leasehold acquisition, $4 million for seismic and $7 million in capitalized costs.  In 2004, we invested approximately $28 million, which included $12 million to spud 21 wells, $14 million for leasehold acquisition, and $2 million for other capitalized costs.  

In 2006 and 2005, we also invested $94 million and $35 million, respectively, for the fabrication of 13 new drilling rigs to be used by our subsidiary, DDI, for drilling wells in the play.  These rigs were sold in December 2006 as part of a sale and leaseback transaction pursuant to which we also leased two other newly fabricated rigs.  We have options to repurchase the rigs under the leases as discussed in “Management’s Discussion and Analysis of Financial Condition and Results of Operations.” At December 31, 2006, DDI had 337 employees, compared to 45 employees at December 31, 2005.  We had a total of 19 rigs running in the Fayetteville Shale play at year-end 2006, including 15 rigs capable of drilling horizontal laterals and four smaller rigs which are being utilized to drill the initial vertical section of the horizontal wells.  DDI operates 13 of the 19 rigs we currently have working in t he play.  At year-end 2005, we had three rigs drilling in the Fayetteville Shale play area.

As of December 31, 2006, we had spud a total of 284 wells in the play, 270 of which were operated by us and 14 of which were outside-operated wells.  Of the wells spud, 196 were drilled in 2006, 67 were drilled in 2005, and 21 were drilled in 2004, and 226 of the total wells spud were designated as horizontal wells.  At year-end 2006, 172 wells had been drilled and completed, including 118 horizontal wells.  

Our results to date indicate that optimal development of this large resource will primarily require horizontal wells.  Early in the project’s life, we hydraulically fractured our wells using nitrogen foam fluid systems.  In 2006, we moved away from this completion technique and began using slickwater and crosslinked gel systems to complete our wells. Wells completed using a slickwater or crosslinked gel system have demonstrated improved production performance over the nitrogen foam fractured wells. During 2007, we plan to continue to experiment with new completion techniques, fluid systems and lateral lengths to further optimize the performance of our wells.

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The average initial production test rate for the 90 horizontal wells which were fracture stimulated using either slickwater or crosslinked gel fluids and on production as of December 31, 2006, was 1.5 MMcf per day.  The well costs for our most recently completed horizontal wells have averaged approximately $2.3 million per well.  The horizontal wells drilled through December 31, 2006, have had an average vertical depth of 3,500 feet, an average lateral length of 2,300 feet, and have taken 18 days on average to drill from re-entry to re-entry, after the vertical portion of the wellbore has been drilled.  

Gross production from our operated wells in the Fayetteville Shale play increased from approximately 9 MMcf per day at the beginning of 2006 to approximately 100 MMcf per day by year-end, and could reach up to 300 MMcf per day by the end of 2007.  Our net production from the Fayetteville Shale play was 11.8 Bcf in 2006, compared to 1.8 Bcf in 2005 and 0.1 Bcf in 2004.  Our production in 2007 is estimated to range between 45 and 50 Bcf.  Our total proved net gas reserves booked in the play at year-end 2006 were 300 Bcf from a total of 434 locations, of which 162 were proved developed producing, 9 were proved developed non-producing and 263 were proved undeveloped.  Of the 434 locations, 381 were horizontal. Our proved developed reserves have ranged from 0.2 Bcf to 2.8 Bcf per well and the average gross proved reserves for each of the proved undeveloped wells included in our year-end reserves was approximately 1.15 Bcf per well, up from 0.95 Bcf per well at the end of 2005.  We currently estimate that the average ultimate gross production for these wells will be 1.3 to 1.5 Bcf per horizontal well.  Total proved gas reserves booked in the play in 2005 totaled 101 Bcf fr om a total of 177 locations, of which 54 were proved developed producing, six were proved developed non-producing, and 117 were proved undeveloped.  Total proved gas reserves booked in the play in 2004 totaled approximately 8 Bcf from a total of 20 vertical wells.  

In 2007, we plan to invest $875 million in our Fayetteville Shale play, which includes drilling between 400 and 450 horizontal wells and shooting 3-D seismic over a large portion of our Fayetteville Shale acreage.  We also plan to drill up to seven horizontal wells in the Moorefield Shale and one horizontal well in the Chattanooga Shale.  Our strategy going forward is to increase our production through development drilling while also determining the economic viability of the undrilled portion of our acreage through drilling in new pilot areas.  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 natural gas and oil commodity price environment. As we continue to gather data about the Fayetteville Shale, 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. We refer you to "Risk Factors - Our drilling plans for the Fayetteville Shale play are subject to change" in Item 1A of Part I of this Form 10-K.

East Texas.  Our East Texas operations are primarily located in the Overton Field in Smith County, Texas, and our Angelina River Trend located in southern Nacogdoches County, Texas.

Overton Field - Our original interest in the Overton Field (which was approximately 10,800 gross acres) was acquired in April 2000 for $6 million.  At December 31, 2006, we held approximately 24,400 gross acres with an average working interest in the Overton Field of 96% and average net revenue interest of 77%.  

The Overton Field produces from four Taylor series sands in the Cotton Valley formation at approximately 12,000 feet.  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 2006, we drilled and completed a total of 66 wells, of which 44 were 40-acre spaced wells. This compares to 80 wells drilled and completed in 2005 and 83 wells drilled and completed in 2004.  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 MMcfe in March 2001 to approximately 110 MMcfe at year-end 2006 resulting in net production of 29.8 Bcfe, compared to 26.7 Bcfe during 2005 and 21.8 Bcfe in 2004.  Wells drilled in the field during 2006 averaged approximately $2.3 million to drill and complete, had average initial production rates of approximately 3.0 MMcfe per day and had average estimated ultimate gross reserves of 1.6 Bcfe per well.  Our average production costs (including production taxes) were $0.64 per Mcfe in 2006, compared to $0.56 per Mcfe in 2005 and $0.50 per M cfe in 2004.  The increases in our unit production costs were primarily due to higher compression costs.

Our proved reserves in East Texas increased to 383 Bcfe at year-end 2006, or 37% of our total reserves, of which 367 Bcfe were in our Overton Field.  Our reserves at Overton were up from 353 Bcfe at year-end 2005 and 297 Bcfe at year-end 2004, primarily due to the acceleration of our infill drilling program which began in early 2003.  We invested approximately $155 million at the Overton Field during 2006 which resulted in proved reserve additions of 88.0 Bcfe at a

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finding and development cost of $3.80 per Mcfe, including a net downward reserve revision of 47.2 Bcfe.  The reserve revision related to comparatively lower year-end gas prices and performance revisions in some of our existing wells.  This compares to finding and development costs of $1.91 per Mcfe in 2005 and $1.20 per Mcfe in 2004, including net downward reserve revisions of 18.8 Bcfe and 19.2 Bcfe, respectively.  Excluding such revisions, our finding and development costs at Overton were $1.76 per Mcfe in 2006, $1.56 per Mcfe in 2005, and $1.04 per Mcfe in 2004.  Our finding costs have increased over recent years due to slightly lower reserves per well combined with higher costs for drilling and other oilfield services.  We expect that this trend will continue with future development wells in the field.  Additionally, as we continue to drill proved undeveloped locations at Overton for which the reserves were added in previous years, our finding and development cost per Mcfe will increase in the future.  The average estimated ultimate recovery of gas and oil reserves from new wells completed in 2006 was approximately 1.6 gross Bcfe per well, compared to 1.8 gross Bcfe per well in 2005 and 2.0 gross Bcfe per well in 2004.  The consistent decrease in gross reserves per well is primarily due to our drilling of locations with the highest estimated ultimate recovery earlier in our development program and is expected to continue.    

Angelina River Trend - Our Angelina River Trend is a collection of eight new development areas, located primarily in Angelina and Nacogdoches Counties, Texas.  At December 31, 2006, we held approximately 68,900 gross undeveloped acres and 6,400 gross developed acres.  Our average working interest in this area is 66% and our average net revenue interest is 51%.  Through December 31, 2006, we had drilled 28 wells in this trend primarily targeting the Travis Peak formation.  In 2006, we invested $40 million in the Angelina River Trend and drilled 16 wells, 11 of which were productive and 5 of which were in progress at year-end.  Net production from the area was 1.8 Bcfe in 2006 and 0.9 Bcfe in 2005, with gross initial production rates from wells drilled during 2006 ranging from 1.0 to 5.1 MMcfe per day and estimated proved reserves ranging from 0.2 to 2.1 Bcfe.  During 2006, a large portion of our drilling activity consisted of exploratory tests of our acreage position which resulted in the completion of several marginal wells which lowered our average reserves per well.  The average estimated ultimate recovery of gas and oil reserves from the wells completed in 2006 was approximately 0.8 gross Bcfe per well with an average drilling and completion cost of $2.7 million per well.  

In 2007, we plan to invest approximately $163 million in East Texas, drilling up to 39 wells at our Overton field and we plan on drilling up to 28 wells in our Angelina River Trend, the majority of which are planned offsets to our best existing wells.

Permian Basin. At December 31, 2006, our proved reserves in the Permian Basin were 51 Bcfe, compared to approximately 59 Bcfe at year-end 2005 and 61 Bcfe at year-end 2004.  Our production in the basin during 2006 was 5.8 Bcfe, or approximately 15.9 MMcfe per day, compared to 6.9 Bcfe in 2005 and 7.1 Bcfe in 2004.  The decrease in reserves and production during both 2006 and 2005 was due to the natural decline in these properties, partially offset by our drilling program.  Our production costs (including production taxes) averaged $2.72 per Mcfe in 2006, compared to $1.76 per Mcfe in 2005 and $1.21 per Mcfe in 2004.  The increases in our unit production costs during 2006 were primarily due to higher service costs and increased production taxes resulting from higher oil prices, combined with the decline in our production volumes.  In 2006, we invested $25 million in the Permian Basin and drill ed 12 wells, all of which were successful, resulting in reserve additions of 8.5 Bcfe.  These reserve additions were more than offset by a net downward reserve revision of 10.7 Bcfe related to lower commodity prices at year-end and performance revisions.  Excluding such revisions, our finding and development costs in the Permian Basin were $2.90 per Mcfe in 2006, $2.70 per Mcfe in 2005 and $2.62 per Mcfe in 2004.  The increase in our finding and development costs in both 2006 and 2005 was due to overall higher service costs, and we expect this trend of higher costs to continue.  In 2007, we plan to invest approximately $18 million in our Permian Basin program to drill up to 18 exploration and exploitation wells.

Gulf Coast.  During 2006, our Gulf Coast operations were located in the onshore areas of Texas and Louisiana.  During the fourth quarter of 2006, we completed the sale of our remaining South Louisiana properties to a private company for $12.7 million. These properties had proved reserves of 7.0 Bcfe and produced approximately 1.1 Bcfe annually.  With this divestiture, we no longer have producing properties in the South Louisiana area.  

Proved reserves in our Gulf Coast properties totaled 15 Bcfe at December 31, 2006, compared to approximately 27 Bcfe at year-end 2005 and 39 Bcfe at year-end 2004.  The decline in reserves in 2006 was primarily due to the divestiture of our South Louisiana properties.  The decline in reserves in 2005 was primarily due to the natural decline in these properties, partially offset by new reserve additions from drilling.  Net production from this area in 2006 was 2.6 Bcfe, or approximately 7 MMcfe per day, compared to 3.9 Bcfe in 2005 and 4.6 Bcfe in 2004.  Production costs (including production taxes) averaged $2.00 per Mcfe during 2006, compared to $1.67 per Mcfe during 2005 and $1.39 per Mcfe during 2004.  The increase in our unit production costs over the last three years was primarily due to the decline in production volumes from these properties, as well as general increases in operating costs.   During 2006, we invested $7 million in the Gulf Coast area including approximately $4 million associated with an ongoing 3-D seismic program on our Texas Gulf Coast properties. During 2006, we added 0.2 Bcfe of reserves which were more than offset by downward

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reserve revisions of 2.7 Bcfe.  In 2007, we plan to invest up to $7 million in the Texas Gulf Coast area which includes drilling up to three wells in the area of our current seismic program.  

Other Exploration and New Ventures.  We have personnel dedicated to the research and identification of active and potential plays, focusing on both conventional exploration plays and unconventional plays (including coalbed 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.  

At December 31, 2006, we held 89,592 net undeveloped acres in areas of the United States outside of our core operating areas in connection with New Ventures that we are pursuing.  This compares to 116,633 net undeveloped acres held at year-end 2005 and 47,596 net undeveloped acres held at year-end 2004.  Of the 89,592 net undeveloped acres held at year-end 2006, approximately 48,956 acres are located in Culberson County, Texas, in the Barnett Shale play in the Permian Basin.    

In 2006, we invested approximately $46 million in our New Ventures program and drilled a total of seven exploration wells, of which two were successful, two were dry, and three were in progress at year-end.  The two dry holes that we drilled in 2006 were unsuccessful conventional exploration tests in the Rocky Mountains area.  Our two successful wells were both located in our Barnett Shale play in the Permian Basin.  Additionally in 2006, we began drilling on our recently acquired Riverton coalbed methane project in Caldwell Parish, Louisiana.  We have approximately 11,000 net acres in this project area targeting the Tertiary-age lower Wilcox coals at a depth of approximately 2,800 feet.

In 2005, we invested approximately $26 million in our New Ventures program and drilled a total of six exploration wells, of which three were successful and one was in progress at year-end.  Our three discoveries in 2005 were located in East Texas.  Two of the wells are now included in our East Texas operations as part of our Angelina River Trend development project.  The third East Texas discovery was at our Pines prospect located in Marion County.  Late in the third quarter of 2005, we spudded a deep Arbuckle test in our Midway prospect area northeast of our Ranger Anticline area in the Arkoma Basin.  Although the Arbuckle objective did test natural gas, it did not produce at economic rates.  We completed this well in the uphole Borum and Basham sands, which are producing horizons in the Ranger Anticline area.  In 2005, we drilled an exploration well to test the Jackfork objective in Perry Co unty, Arkansas, which was a dry hole, and a new coalbed methane test in Sweetwater County, Wyoming that was unsuccessful.  In 2004, we invested approximately $2 million in New Ventures, excluding the Fayetteville Shale play, which included drilling one exploration dry hole in another coalbed methane play.  

In 2007, we plan to invest approximately $58 million in various other exploration and New Ventures projects, including drilling up to 10 wells in the Woodford Shale in Oklahoma and up to 30 wells in our new coalbed methane play in northern Louisiana.  

Acquisitions and Divestitures

In 2006, we completed the sale of our remaining South Louisiana properties to a private company for $12.7 million. These properties had proved reserves of 7.0 Bcfe and produced approximately 1.1 Bcfe annually.  With this divestiture, we no longer have producing properties in the South Louisiana area.

In 2006, we acquired additional working interests in our Overton Field for approximately $9 million.  We also acquired interests in a new coalbed methane project located in Caldwell Parish, Louisiana for approximately $9 million.  In total, we purchased 2.9 Bcfe of proved reserves for $18 million at an average cost of $6.09 per Mcfe.  The cost per Mcfe was higher than for prior acquisitions due to the potential existence of future drilling opportunities not currently classified as proved.  

In 2004, we purchased 5.8 Bcfe of proved reserves for $14 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.

Capital Investments

During 2006, we invested a total of $767 million in our primary E&P business activities and $94 million related to the purchase of drilling rigs and related equipment which were sold in December 2006 as part of a sale and leaseback transaction.  During 2006, we participated in drilling 382 wells, 230 of which were successful, 9 were dry and 143 were still in progress at year-end.  Of the 143 wells in progress at year-end, 104 were located in our Fayetteville Shale play.  Our investments focused primarily on our active drilling programs in our Fayetteville Shale play, East Texas, and the  

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conventional Arkoma Basin.  These drilling programs accounted for 45%, 24%, and 11% of our E&P capital investments in 2006, respectively, with approximately $388 million invested in our Fayetteville Shale play, $204 million in East Texas and $97 million in our conventional Arkoma Basin program.  In addition, we invested approximately $25 million in the Permian Basin, $7 million in the Gulf Coast and $46 million in exploration and New Ventures.

Of the $767 million invested in 2006, approximately $196 million was invested in exploratory drilling, $421 million in development drilling and workovers, $70 million for leasehold acquisition and seismic expenditures, $18 million for producing property acquisitions and $62 million in capitalized interest and expenses and other technology-related expenditures.  During 2005, we invested a total of approximately $451 million in our E&P business and participated in 247 wells.  Our investments in 2005 included $35 million related to construction payments on the rigs which were sold in December 2006.  In 2004, we invested $282 million and participated in 204 wells.  The increases in capital investments and wells drilled over the last two years are primarily due to the acceleration of our drilling program in the Fayetteville Shale play.

In 2007, we intend to invest approximately $1,237 million in our E&P program, an increase of approximately 44% over our capital investment level in 2006.  We continue to be focused on our strategy of adding value through the drillbit, as approximately 82% of our 2006 E&P capital is allocated to drilling.  The Fayetteville Shale play is the primary focus of our E&P business, and we plan to significantly increase our activity and investment in the play to approximately $875 million in 2007.  Our capital investments in 2007 will also be focused on our lower-risk conventional drilling programs in East Texas and the Arkoma Basin.  We plan to invest approximately $163 million and $116 million in our East Texas and conventional Arkoma Basin programs, respectively, in 2007.  The remainder of our E&P capital will be allocated to exploitation projects in the Permian Basin ($18 million), the onshor e Texas Gulf Coast ($7 million), and various other exploration and New Venture projects ($58 million).

Of the $1,237 million allocated to our 2007 E&P capital budget, approximately $937 million will be invested in development drilling, $75 million in exploratory drilling, $93 million in seismic and other geological and geophysical expenditures (including approximately $77 million in our Fayetteville Shale play), $46 million in land, and $86 million in capitalized interest and expenses and other 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 Investments” for additional discussion of our planned capital investments in 2007.

Other Revenues

Other revenues and operating income for 2006, 2005 and 2004 also included pre-tax gains of $4.0 million, $3.1 million, and $4.5 million, respectively, related to the sale of gas-in-storage inventory.  

Sales and Major Customers

Our daily natural gas equivalent production averaged 198.1 MMcfe in 2006, up 19% from 167.1 MMcfe in 2005 and 148.2 MMcfe in 2004, and we produced a total of 72.3 Bcfe in 2006, up from 61.0 Bcfe in 2005 and 54.1 Bcfe in 2004.  Our natural gas production was 68.1 Bcf in 2006, compared to 56.8 Bcf in 2005 and 50.4 Bcf in 2004.  The increase in 2006 production resulted primarily from a 10.0 Bcf increase in production related to our Fayetteville Shale play and a 4.0 Bcfe increase in production from East Texas, partially offset by a decrease in production from our Gulf Coast and the Permian Basin properties.  The increase in production in 2005 resulted primarily from a 5.8 Bcfe increase in production from East Texas, and a 1.9 Bcf increase in our Arkoma production (including a 1.7 Bcf increase in production from the Fayetteville Shale play).  Production during 2005 was reduced by the effects of curtailment of a p ortion of our Overton Field production due to repairs of a transmission line that is not operated by us and by the effects of Hurricane Katrina. Combined, these events reduced our production by approximately 1.0 Bcfe.  The increase in 2004 production resulted primarily from an 8.2 Bcfe increase in production from our Overton Field, a 1.3 Bcfe increase in our Arkoma Basin production, and 3.2 Bcfe from our River Ridge discovery in New Mexico.  

We also produced 698,000 barrels of oil in 2006, compared to 705,000 barrels of oil in 2005 and 618,000 barrels of oil in 2004.  Our oil production decreased during 2006 due to the sale of our South Louisiana properties in the fourth quarter.  Our oil production increased in 2005 due to increased oil production from East Texas and the Permian Basin.  

For 2007, we are targeting our total natural gas and crude oil production to be approximately 105.0 Bcfe to 110.0 Bcfe, which equates to a growth rate of approximately 45% to 50% above our 2006 production volumes.

The vast majority of our gas production and all of our oil production is sold to unaffiliated purchasers.  Unaffiliated sales of gas and oil production are conducted under contracts that reflect current short-term prices and are

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subject to seasonal price swings.  These combined gas and oil sales to unaffiliated purchasers accounted for 92% of total E&P revenues in 2006, 90% in 2005, and 89% in 2004.  In 2006, the largest unaffiliated purchaser accounted for approximately 10% of total E&P revenues.

Our utility subsidiary, Arkansas Western, also purchases a portion 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” for further discussion of these contracts.  Sales to Arkansas Western accounted for approximately 7% of total E&P revenues in 2006, 9% in 2005, and 10% in 2004.  SEECO’s sales to Arkansas Western were 4.7 Bcf in 2006, compared to 5.1 Bcf in 2005 and 5.4 Bcf in 2004.  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 competitive bids.  SEECO’s gas production provided approximately 36% of the utility’s requirements in 2006, 38% in 2005, and 40% in 2004.  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 Western’s distribution system.

We expect future increases in sales of our gas production to come primarily from sales to unaffiliated purchasers.  Future sales to Arkansas Western will be dependent upon our success in obtaining gas supply contracts from them.  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 realized an average wellhead price of $6.55 per Mcf for our natural gas production in 2006, compared to $6.51 per Mcf in 2005 and $5.21 per Mcf in 2004, including the effect of hedges.  Our hedging activities increased our average gas price $0.18 in 2006 and decreased our average gas price $1.22 per Mcf in 2005 and $0.59 per Mcf in 2004.  Our average oil price realized was $58.36 per barrel in 2006, compared to $42.62 in 2005 and $31.47 per barrel in 2004, including the effect of hedges.  Our hedging activities lowered our average oil price $4.81 per barrel in 2006, $11.75 per barrel in 2005, and $9.08 per barrel in 2004.

We periodically enter into various hedging and other financial arrangements with respect to a portion of our projected natural gas and crude oil production in order to support certain desired levels of cash flow 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, 2006, we had hedges in place on 65.0 Bcf, or approximately 60% to 65% of our targeted 2007 gas production, and 35.0 Bcf of our expected 2008 gas production.  Subsequent to December 31, 2006 and prior to February 23, 2007, we hedged 12.5 Bcf of 2007, 11.0 Bcf of 2008 and 4.0 Bcf of 2009 gas production under fixed price swaps with average prices of $8.03, $7.65 and $7.29 per Mcf, respectively.  Additionally, we hedged 2.0 Bcf of 2007, 11.0 Bcf of 2008 and 4.0 Bcf of 2009 gas production using costless collars. The collars relating to 2007 production have a weighted average floor and ceiling price of $8.00 and $10.00 per Mcf, respectively; the collars relating to 2008 production have a weighted average floor and ceiling price of $8.00 and $10.26 per Mcf, respectively; and the collars relating to 2009 production have a weighted average floor and ceiling price of $7.63 and $10.00 per Mcf, respectively. As of February 19, 2007, we have hedged approximately 75% of our 2007 anticipated gas production level. We refer you to Item 7A of this Form 10-K, “Quantitative and Qualitative Disclosures About Market Risks,” for further information regarding our hedge position at December 31, 2006.

Disregarding the impact of hedges, the average price received for our gas production has historically been approximately $0.30 to $0.50 per Mcf lower than average NYMEX spot market prices.  However, during both 2006 and 2005, widening market differentials caused the difference in our average price received to be approximately $0.90 per Mcf lower than average spot market prices.  Assuming a NYMEX commodity price of $7.00 per Mcf of gas for 2007, our differential for the average price received for our gas production is expected to be approximately $0.65 to $0.70 per Mcf below the NYMEX Henry Hub index price, including the impact of our basis hedges.  Assuming a NYMEX commodity price of $60.00 per barrel of oil for 2007, we expect the average price received for our oil production during 2007 to be approximately $1.00 per barrel lower than average spot market prices, as market differentials reduce the average prices received.

Competition

All phases of the oil and gas industry are highly competitive.  We compete in the acquisition of properties, the search for and development of reserves, the production and sale of natural gas and oil and the securing of 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.

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Competition in Arkansas has increased in recent years due largely to the development of improved access to interstate pipelines and our discovery of the Fayetteville Shale play.  The competition for new leases in the Fayetteville Shale play has become especially intense.  Due to our significant leasehold acreage position in Arkansas and our long-time presence and reputation in the 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 also 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.

Commencing in 1992, the FERC issued a series of orders (collectively, “Order No. 636”), which require interstate pipelines to provide transportation separately, 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.  Starting in 2000, the FERC issued a series of 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 chang es 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 results of operations to date.

We cannot predict whether and to what extent any market reforms initiated by the FERC or any new energy legislation will achieve the goal of increasing competition, lessening preferential treatment and enhancing transparency in markets in which our natural gas is sold.  However, we do not believe that we will be disproportionately affected as compared to other natural gas producers and marketers by any action taken by the FERC or any other legislative body.

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.  

Impact of Federal Regulation of Sales of Natural Gas 

Historically, the sale of natural gas in interstate commerce has 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.  

The natural gas industry historically has been heavily regulated and from time to time proposals are introduced by Congress and the FERC and judicial decisions are rendered that impact the conduct of business in the natural gas industry.  There can be no assurance that the less stringent regulatory approach recently pursued by the FERC and Congress will continue.

Midstream Services

Our Midstream Services segment generates revenue through the marketing of our own gas production and third-party natural gas and through gathering fees associated with the transportation of natural gas to market. Our operating income from this segment was $4.1 million on revenues of $475.2 million in 2006, compared to $5.7 million on revenues of $459.9 million in 2005 and $3.2 million on revenues of $315.0 million in 2004. The increases in revenues are largely attributable to increased volumes marketed, higher purchased gas costs and increased gathering revenues.  The decrease in operating income during 2006 was due to increased operating costs and expenses that resulted from increased staffing and other costs associated with our growing gathering activities, and a decrease in the margin generated by our marketing activities caused in part by increased volatility of locational market differentials in our core operating are as.

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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.  We marketed 72.7 Bcf of natural gas in 2006, compared to 61.9 Bcf in 2005 and 57.0 Bcf in 2004. Of the total volumes marketed, purchases from our E&P subsidiaries accounted for 72% in 2006, 76% in 2005, and 77% in 2004.  

Gas Gathering

In 2004, we formed a new subsidiary, DeSoto Gathering Company, L.L.C., that engages in gathering activities related to the development of our Fayetteville Shale play.  In 2006, we invested approximately $48.7 million related to these activities and had gathering revenues of $7.9 million, compared to $15.8 million invested and revenues of $1.0 million in 2005.  Gathering revenues and expenses for this segment are expected to grow substantially over the next few years as gathering systems for our Fayetteville Shale play are expanded to support the development of this play.

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.

Regulation

On March 15, 2006, the Department of Transportation, or the DOT, issued new rules pertaining to certain gathering lines. We do not expect compliance with these new rules to have a material adverse impact on our operations.

Natural Gas Distribution

We distribute natural gas to approximately 151,000 customers in northern Arkansas through our subsidiary, Arkansas Western Gas Company. Our utility is focused on capitalizing on the expanding economy and growth in customers in its Northwest Arkansas service territory.  Approximately 67% of Arkansas Western’s customers are located in the Fayetteville-Springdale-Rogers MSA, which the U.S. Census Bureau named as the 6^th fastest growing MSA in the United States in 2001.  In 2003, the Center for Business and Economic Research at the University of Arkansas estimated that the population of the Fayetteville-Springdale-Rogers MSA should continue to grow approximately 3% per year until 2025.  In February 2006, the Milken Institute named Northwest Arkansas as the 8^th “Best Performing City” in the United States, based upon job creation and local economic growth, attributable in part to th e presence of Wal-Mart Stores, Inc., one of the largest public corporations in the world, and other large corporations such as Tyson Foods and J.B. Hunt Transportation.  

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Operating income for our natural gas distribution business was $4.5 million in 2006, compared to $4.9 million in 2005 and $8.5 million in 2004.  EBITDA generated by our utility segment was $10.5 million in 2006, compared to $11.7 million in 2005 and $15.2 million in 2004.  The decrease in 2006 and 2005 operating income and EBITDA resulted primarily from warmer than normal weather and increased operating costs and expenses, which more than offset a rate increase that became effective October 31, 2005.  In September 2006, Arkansas Western filed an application for a general rate increase.  Any increased approved is expected to take effect in July 2007.  We refer you to “Business — Other Items — Reconciliation of Non-GAAP Measures” in Item 1 of Part I of this Form 10-K for a table that reconciles EBITDA with our net income as derived from our audited fin ancial information.  In recent years, Arkansas Western has experienced customer growth of approximately 3% annually in its Northwest Arkansas service territory, while it has experienced 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.

Gas Purchases and Supply

Arkansas Western purchases its system gas supply through a competitive bidding process and directly at the wellhead under long-term contracts with flexible pricing provisions.  In 2006, SEECO successfully bid on gas supply packages representing approximately 53% of the requirements for Arkansas Western for 2007, compared to approximately 44% for 2005 and 55% for 2004.  The contracts awarded to SEECO expire in 2008.

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 3% 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.

Arkansas Western has a 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 are billed or credited, as appropriate, to customers in subsequent months.

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 gas distribution segment hedged 3.1 Bcf, 4.2 Bcf and 4.5 Bcf, respectively, in 2006, 2005, and 2004, which had the effect of increasing its total gas supply costs by $7.7 million, $2.4 million, and $1.1 million, respectively.  At December 31, 2006, Arkansas Western had 3.1 Bcf of future gas purchases hedged at an average purchase price of $8.83 per Mcf.  We refer you to Item 7A of this Form 10-K, “Quantitative and Qualitative Disclosures About Market Risk,” and Note 8 to the consolidated financial statements for additional information.

Markets and Customers

Arkansas Western provides natural gas to approximately 134,000 residential, 17,000 commercial, and 170 industrial customers, while also providing gas transportation services to approximately 113 end-use and off-system customers.  Total gas throughput in 2006 was 21.9 Bcf, compared to 23.2 Bcf in 2005 and 25.0 Bcf in 2004.  The lower volumes in both 2006 and 2005 primarily resulted from warmer weather and customer conservation brought about by high gas prices in recent years. Weather in 2006 was 17% warmer than normal and 8% warmer than in 2005.  Weather in 2005 was 9% warmer than normal and 1% colder than in 2004.

Residential and Commercial.  Approximately 89% of the utility's revenues in 2006 were from residential and commercial markets.  Residential and commercial customers combined accounted for 56% of total gas throughput for the gas distribution segment in 2006, compared to 57% in 2005 and 2004.  Gas volumes sold to residential customers were 7.5 Bcf in 2006, compared to 8.1 Bcf in 2005 and 8.5 Bcf in 2004.  Gas sold to commercial customers totaled 4.7 Bcf in 2006, compared to 5.1 Bcf in 2005 and 5.7 Bcf in 2004.  The fluctuations in gas volumes sold to both residential and commercial

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customers were driven primarily by warmer 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 that might result from weather variations during the winter heating season.

Industrial and End-use Transportation.  Deliveries to Arkansas Western’s industrial and end-use transportation customers were 9.6 Bcf in 2006, 10.0 Bcf in 2005, and 9.8 Bcf in 2004.  No industrial customer accounts for more than 10% 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 0.1 Bcf in 2006, less than 0.1 Bcf in 2005 and were 1.0 Bcf in 2004, all to the Ozark Gas Transmission System.  As of December 31, 2006, a total of 112 customers used the end-use 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 rates and operations are regulated by the APSC and Arkansas Western must obtain the approval of the APSC in order to increase the rates it charges to its customers.  Arkansas Western operates through municipal franchises that are perpetual by virtue of state law but may not be exclusive within a geographic area.

On September 25, 2006, Arkansas Western filed an application with the APSC for a general rate increase of approximately $13.1 million.  The filing requests a capital structure using the modified balance sheet approach inclusive of a 50/50 debt-to-equity ratio and a 10.79% return on equity (ROE).  The APSC approved an allowed ROE of 9.7% in Arkansas Western’s 2005 rate increase.  In this rate case, Arkansas Western hopes to resolve the issues associated with recovery of lost revenues resulting from energy efficiency programs and declining consumption per customer.  Any increase approved is expected to take effect in July 2007.  Arkansas Western’s last rate increase of $4.6 million annually was effective October 31, 2005.  Rate increase requests, which may be filed in the future, will depend on APSC ratemaking policies, customer growth, increases in operating expenses, and additional invest ment in property, plant and equipment.

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 been required to unbundle residential sales services from transportation services in an effort to promote greater competition.  There is no such legislation in Arkansas and no regulatory directives related to natural gas are presently pending.  In recent years, there have been efforts by the Arkansas legislature and the APSC concerning the issues of deregulation of the retail sale of electricity and a large-user access program for electric service choice.  Legislation adopted in 2001 for deregulation of the retail sale of electricity was repealed in 2003 and no legislative action has been taken regarding implementing a large-user access program.

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.

On January 12, 2006, the APSC initiated a notice of inquiry regarding a rulemaking for developing and implementing energy efficiency programs.  Following a collaborative process, the APSC issued Energy Efficiency Rules on January 11, 2007.  These rules require all gas and electric utilities, excluding electric cooperatives, to file energy efficiency plans and programs with the APSC.  Quick start or pilot programs are to be implemented by late 2007, and comprehensive programs are to be implemented in 2009.  Utilities will recover the costs of energy efficiency programs from their customers.  The APSC will address lost revenues associated with these programs in the utilities’ rate cases.

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In December 2006, the APSC issued new affiliate transactions rules.  In January 2007, Arkansas Western and other utilities requested rehearing of these rules.  On February 16, 2007, the APSC issued an order granting a rehearing and staying the implementation of the affiliate transaction rules pending further review.  A public hearing on this issue is scheduled for March 27, 2007.  Arkansas Western anticipates that these rules, if not modified on rehearing, will increase its regulatory costs and overall cost of service.

Gas distribution revenues in future years will be impacted by APSC policies, 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” in Item 1A of Part I of this Form 10-K for a discussion of the impact of government regulation on our natural gas distribution business.

Transportation and Other

On May 2, 2006, we sold our 25% interest in NOARK Pipeline System, Limited Partnership (NOARK), a partnership that owns a 723-mile integrated interstate pipeline system known as Ozark Gas Transmission System, to Atlas Pipeline Partners, L.P. for $69.0 million, resulting in a pre-tax gain of $10.9 million.  In connection with the sale, we assumed $39.0 million of partnership debt that we had previously guaranteed.  Our share of NOARK’s results of operations was a pre-tax gain of $0.9 million in 2006 prior to the sale, compared to a pre-tax gain of $1.6 million in 2005 and a pre-tax loss of $0.4 million in 2004.  The pre-tax gain in both 2006 and 2005 was primarily due to the increase in volumes transported and higher transportation rates collected for those volumes.  The pre-tax loss in 2004 was due primarily to a $0.4 negative adjustment from the operator of the pipeline for prior period allocati ons of income and expenses to the partners.  

Historically, our other operations have consisted of the activities of our wholly-owned subsidiary, A. W. Realty Company, a company with real estate development activities concentrated on tracts of land located near our offices in Fayetteville, Arkansas.  There were no sales of commercial real estate in 2006.  During 2005, we sold approximately 1.6 acres of commercial real estate for a pre-tax gain of $0.4 million.  During 2004, we sold 45.5 acres of commercial real estate for a pre-tax gain of $5.8 million.  These amounts were reflected in “Gas transportation and other” revenues in our income statement.  As of December 31, 2006, A. W. Realty Company owned an interest in approximately 15 acres of undeveloped real estate.

Other Items

Reconciliation of Non-GAAP Measures

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

We believe that 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, 2006, 2005 and 2004:

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2006	E&P	Midstream  Services	Natural Gas Distribution	Other	Total
Net income	$ 151,157	$ 2,976	$ 2,190	$ 6,313	$ 162,636
Depreciation, depletion and amortization	143,500	1,773	6,428	94	151,795
Net interest expense	508	-	171	-	679
Provision for income taxes	91,276	554	1,698	5,871	99,399
EBITDA	$ 386,441	$     5,303	$   10,487	$   12,278	$  414,509
2005
Net income	$ 144,349	$ 2,962	$ 203	$ 246	$ 147,760
Depreciation, depletion and amortization	89,229	303	7,010	99	96,641
Net interest expense	8,416	1,054	4,429	1,141	15,040
Provision for income taxes	83,921	1,668	11	831	86,431
EBITDA	$ 325,915	$     5,987	$   11,653	$      2,317	$  345,872
2004
Net income	$ 96,307	$ 2,000	$ 2,617	$ 2,652	$ 103,576
Depreciation, depletion and amortization	68,065	67	6,696	91	74,919
Net interest expense	11,537	-	4,461	994	16,992
Provision for income taxes	55,197	1,151	1,471	1,959	59,778
EBITDA	$ 231,106	$     3,218	$   15,245	$     5,696	$ 255,265

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 statutes.  These laws and regulations require permits for drilling wells and the maintenance of bonding requirements in order to drill or operate wells and also regulate the spacing and location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, the plugging and abandoning of wells, the prevention and cleanup of pollutants and other matters.  We maintain insurance against costs of clean-up operations, but we are not fully insured against all such risks.  Although future environmental obligations are not expected to have a material impact on the results of our operations or financial condition, there c an be no assurance that future developments, such as increasingly stringent environmental laws or enforcement thereof, will not cause us to incur material environmental liabilities or costs.

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 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 cooper ate 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

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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 pa int 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 w aste disposed of or released by prior owners or operators) or property contamination (including groundwater contamination by prior owners or operators), or to perform remedial plugging or closure operations to prevent future contamination.   

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

Employees

At December 31, 2006, we had 1,278 total employees, including 364 employed by our natural gas utility and 337 employed by our drilling company.  None of our employees were covered by a collective bargaining agreement at year-end 2006.  We believe that our relationships with our employees are good.

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.

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“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 — 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.

“Fracture stimulation” A process whereby fluids mixed with proppants are injected into a wellbore under pressure in order to fracture, or crack open, reservoir rock, thereby allowing oil and/or natural gas trapped in the reservoir rock to travel through the fractures and into the well for production.

“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.

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“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.

“Present Value Index” or “PVI” A measure that is computed for projects by dividing the dollars invested into the PV-10 resulting from the investment.

“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.

“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.

 “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 1A.  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 and “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Forward-Looking Information.”

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.

Natural gas and oil prices have recently been at or near their highest historical levels.  A substantial or extended decline in natural gas and oil prices would have a material adverse effect on our financial position, our results of operations, our access to capital and the quantities of natural gas and oil that may be economically produced by us.  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.

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

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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 relatively short period of time.  Once a write-down is taken, it cannot be reversed in future periods even if natural gas and oil prices increase.

If natural gas and oil prices decline below levels at December 31, 2006, 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 stockholders' 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. Our planned capital expenditures for 2007 are expected to significantly exceed the net cash generated by our operations.  We expect to borrow under our credit facility to fund capital expenditures that are in excess of our net cash flow and cash on hand.  Our ability to borrow under our credit facility is subject to certain conditions.  At December 31, 2006, we were in compliance with the borrowing conditions of our credit facility.  If we are not in compliance with the terms of our credit facility in the future, we may not be able to borrow under it to 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 resou rces 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 or sale could have a material adverse effect on our results and future operations.

Working interest owners of some of our properties may be unwilling or unable to cover their portion of development costs, which could change our exploration and development plans.  

Some of our working interest owners may have difficulties obtaining the capital needed to finance their activities, or may believe that estimated drilling and completion costs are excessive. As a result, these working interest owners may be unable or unwilling to pay their share of well costs as they become due. These problems could cause us to change our development plans for these properties.

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 our major properties in detail and independently develop reserve estimates.  The estimates of Netherland, Sewell & Associates, Inc. may differ significantly on an individual property basis from our estimates. When, in the aggregate, such differences are within 10%, Netherland, Sewell & Associates, Inc. is generally satisfied that the estimates of proved reserves are reasonable.  

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 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 Board of Directors.  There are 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 from estimated quantities of proved natural gas and oil reserves (in the aggregate and for a particular geographic location), production, revenues, taxes and development and operating expenditures.  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 2006, our reserves were revised downward by 86.6 Bcfe, primarily due to lower prevailing oil and gas prices at year-end combined with performance revisions in some of our East Texas and conventional Arkoma Basin properties, which were partially offset by an upward performance revision in our Fayettev ille Shale properties.  In 2005, our reserves were revised downward by 31.7 Bcfe, primarily due to unexpected declines associated with our Gulf Coast properties and minor changes to decline rates for our wells at the Overton Field.  In 2004, reserves were revised downward by 12.7 Bcfe due primarily to slightly higher decline rates related to some of the wells in our Overton Field in East Texas.  These revisions represented no greater than 8% 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, 2006, approximately 35% 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.  Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Forward-Looking Information” in Item 7 of Part II of this Form 10-K for additional information regarding the uncertainty of reserve estimates.

Our future level of indebtedness and the terms of our financing arrangements may adversely affect operations and limit our growth.

At December 31, 2006, we had long-term indebtedness of only $137.8 million and we had no borrowings under our revolving credit facility.  However, we have significantly increased our planned capital expenditures for 2007 and currently expect to incur significant additional indebtedness in order to fund a portion of these expenditures.  See also our risk factor headed “We may have difficulty financing our planned capital expenditures which could adversely affect our growth,” above.

The terms of the indenture relating to our outstanding senior notes, our revolving credit facility and the master lease agreement relating to our drilling rigs, which we collectively refer to as our “financing agreements,” impose 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 one or more of the following:

·

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 off-balance sheet obligations, and the covenants contained in our financing agreements, could have important consequences for our operations, including:

·

requiring us to dedicate a substantial portion of our cash flow from operations to required payments, 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.

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Our ability to comply with the covenants and other restrictions in our financing agreements 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 obligations under those agreements, and in the case of the master lease agreement, loss of use of our drilling rigs.  We may not have sufficient funds to make such payments.  If we are unable to satisfy our obligations with 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, to meet our lease obligations, or that future borrowings, equity financings or proceeds from the sale of assets will be available to pay or refinance such debt or obligations.  The terms of our financing agreements 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, 2006, we had drilled and completed 172 wells relating to our Fayetteville Shale play. The majority of these wells were drilled across an area that represents approximately 45% 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 natural gas and oil commodity price environment.  The determination as to whether we continue to drill wells in the Fayetteville Shale may depend on any one or more of the following factors:

·

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;

·

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

·

the extent to which we are able to effectively operate the drillings rigs we acquire; 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.

We may have difficulty drilling all of the wells that are necessary to hold our Fayetteville Shale acreage before the initial lease terms expire, which could result in the loss of certain leasehold rights.

Approximately 131,348 net acres of our Fayetteville Shale acreage will expire in the next three years if we do not drill successful wells to develop the acreage or otherwise take action to extend the leases.  As discussed above under “Our drilling plans for the Fayetteville Shale play are subject to change,” our ability to drill wells depends on a number of

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factors, including certain factors that are beyond our control.  The number of wells we will be required to drill to retain our leasehold rights will be determined by field rules established by the Arkansas Oil and Gas Commission or the AOGC.  During the third quarter of 2006, the AOGC approved statewide field rules in the Fayetteville Shale, the Moorefield Shale, and the Chattanooga Shale as “unconventional sources of supply.”  Under the statewide rules, each drilling unit will consist of a governmental section of approximately 640 acres and operators will be permitted to drill up to 16 wells per drilling unit for each unconventional source of supply.  To the extent that these field rules prevent us from successfully drilling wells in certain areas, we may not be able to drill the wells required to maintain our leasehold rights for certain of our Fayetteville Shale acreage.

If our Fayetteville Shale drilling program fails to produce a significant supply of natural gas, our investments in our gas gathering operations could be lost and our commitments for transportation on pipelines could make the sale of our gas uneconomic, which could have an adverse effect on our results of operations, financial condition and cash flows.

As of December 31, 2006, we had invested approximately $49 million in our gas gathering operations and we intend to invest approximately $84 million in 2007.  Our gas gathering business will largely rely on gas sourced in our Fayetteville Shale play area in Arkansas.  In addition, we have signed a precedent agreement committing us to a portion of the transportation fees related to new pipelines being built for our Fayetteville Shale play area by Texas Gas Transmission, LLC, a subsidiary of Boardwalk Pipeline Partners, LP.  We have also entered into firm transportation agreements with Ozark Gas Transmission to transport up to 220,000 MMBtu per day of gas volumes from our Fayetteville Shale play over the next three years and up to an additional 50,000 MMBtu per day over the next two years.  If our Fayetteville Shale drilling program fails to produce a significant supply of natural gas, our investments in our g as gathering operations could be lost, and we could be forced to pay transportation fees on pipeline capacity that we would not be using.  These events could have an adverse effect on our results of operations, financial condition and cash flows.

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 a lso from wells that are productive but do not produce sufficient net reserves to return a profit after deducting drilling, operating and other costs.  In addition, wells 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 strateg ies.

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

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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 23% of our gas and oil properties, based on PV-10 value, are operated by other companies.  Our dependence on the operator and other working interest owners for these projects and our limited ability to influence operations and associated costs could materially adversely affect the realization of our targeted returns on capital in drilling or acquisition activities and our targeted production growth rate.  The success and timing of drilling, development and exploitation activities on properties operated by others depend on a number of factors that 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.

Our ability to sell our natural gas and crude oil production could be materially harmed if we fail to obtain adequate services such as transportation and processing.

Our ability to bring natural gas and crude oil production to market depends on a number of factors including the availability and proximity of pipelines, gathering systems and processing facilities. In some of the areas where we have operations, we deliver natural gas and crude oil through gathering systems and pipelines that we do not own.  These facilities may be temporarily unavailable due to market conditions or mechanical reasons, or may not be available to us in the future.  Any significant change affecting these facilities or our failure to obtain access to them on acceptable terms could restrict our ability to conduct normal operations.

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Shortages of oilfield 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.  During the last half of 2006, we had difficulty obtaining additional well completion services due to a shortage of completion crews in our Fayetteville Shale play area, which resulted in a higher inventory of wells that had been drilled but were awaiting completion.  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 i n 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 have made significant investments in our drilling rig operations; however, we are still dependent on third party drilling companies.  We also lack experience in operating drilling rigs.

We have made significant investments in our drilling rig operations, including commitments to lease 15 drilling rigs and hiring, as of December 31, 2006, 337 employees for our drilling subsidiary, DeSoto Drilling, Inc. (DDI).  The 15 drilling rigs will not be sufficient to meet the needs of our drilling program and we will still be dependent upon third-party rig providers in order to execute our drilling program in 2007 and beyond.  There can be no assurance that the commencement of our drilling rig operations will not have an adverse effect on our relationships with our existing third-party rig providers or our ability to secure third-party rigs from other providers.  We may also compete with third-party rig providers for qualified personnel, which could adversely affect our relationships with rig providers. If our existing third-party rig providers discontinue their relationships with us, we may not be able to secure alternative rigs on a timely basis, or at all.  Even if we are able to secure alternative rigs, there can be no assurance that replacement rigs will be of equivalent quality or that pricing and other terms will be favorable to us.  If we are unable to secure third-party rigs or if the terms are not favorable to us, our financial condition and results of operations could be adversely affected.

In addition, we had no experience prior to 2006 in operating drilling rigs.  We cannot assure you that we will be able to continue to attract and retain qualified field personnel to operate our drilling rigs or to otherwise effectively conduct our drilling operations.  If we are unable to retain qualified personnel or to effectively conduct our drilling operations, our financial and operating results may be adversely affected.

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.

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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, 2006, we had hedges on approximately 60% to 65% of our targeted 2007 natural gas production.  Our price risk management activities increased revenues by $8.7 million in 2006, and reduced revenues by $77.2 million in 2005 and $35.6 million in 2004.  To the extent that we engage in hedging activities, we may be prevented from realizing the benefits of price increases above the levels of the hedges.  

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

·

our production is less than expected;

·

there is a widening of price differentials between delivery points for our production and the delivery point assumed in the hedge arrangement;

·

the counterparties to our futures contracts fail to perform the contracts; or

·

a sudden, unexpected event materially impacts natural gas or oil prices.

In addition, future market price volatility could create significant changes to the hedge positions recorded on our financial statements.  We refer you to “Quantitative and Qualitative Disclosures about Market Risk” in Item 7A of Part II of this Form 10-K.

Our certificate of incorporation, bylaws, and stockholder rights plan contain provisions that could make it more difficult for someone to either acquire us or affect a change of control.

Our stockholder rights plan, together with certain provisions of our certificate of incorporation and bylaws, could discourage an effort to acquire us, gain control of the company, or replace members of our executive management team. These provisions could potentially deprive our stockholders of opportunities to sell shares of our common stock at above-market prices.

ITEM 1B. UNRESOLVED STAFF COMMENTS.

None.

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 investments, we refer you to “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Capital Investments.”  We also refer you to Item 6, “Selected Financial Data,” of Part II of this Form 10-K for information concerning natural gas and oil produced.

The following information is provided to supplement the information that is presented in Item 8 of Part II of this Form 10-K.  For a further description of our natural gas and oil properties, we refer you to “Business — Exploration and Production.”

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Leasehold acreage as of December 31, 2006:

	Undeveloped		Developed
	Gross	Net	Gross	Net
Conventional Arkoma(1)	378,939	271,259	296,929	190,502
Fayetteville Shale Play(2)	1,027,840	715,895	61,440	50,759
East Texas(3)	85,714	67,488	35,793	26,588
Permian Basin	12,333	4,892	92,957	28,301
Gulf Coast	11,574	5,017	18,989	7,225
Exploration and New Ventures	92,198	89,592	14,384	9,709
	1,608,598	1,154,143	520,492	313,084

(1) Includes 123,442 net developed acres and 1,930 net undeveloped acres that are within our Fayetteville Shale focus area that are not included under the Fayetteville Shale Play.

(2) Assuming that we do not drill successful wells to develop the acreage and do not extend the leases in our undeveloped acreage in the Fayetteville Shale play, leasehold expiring over the next three years will be 6,304 net acres in 2007, 19,451 net acres in 2008, and 105,593 net acres in 2009.

(3) Assuming that we do not drill successful wells to develop the acreage and do not extend the leases in our undeveloped acreage in the Angelina River Trend in East Texas, leasehold expiring over the next three years will be 404 net acres in 2007, 20,620 net acres in 2008, and 27,300 net acres in 2009.

Producing wells as of December 31, 2006:

	Gas		Oil		Total		Gross Wells Operated
	Gross	Net	Gross	Net	Gross	Net
Conventional Arkoma	1,009	493	-	-	1,009	493	444
Fayetteville Shale Play	162	145	-	-	162	145	158
East Texas	391	334	2	2	393	336	294
Unconventional	5	3	-	-	5	3	5
Permian Basin	137	23	274	137	411	160	48
Gulf Coast	33	15	5	1	38	16	7
	1,737	1,013	281	140	2,018	1,153	956

Wells drilled during the year:

	Exploratory
	Productive Wells		Dry Holes		Total
Year	Gross	Net	Gross	Net	Gross	Net
2006	48.0	40.0	4.0	2.3	52.0	42.3
2005	15.0	13.4	2.0	1.8	17.0	15.2
2004	16.0	15.2	5.0	3.7	21.0	18.9

	Development
	Productive Wells		Dry Holes		Total
Year	Gross	Net	Gross	Net	Gross	Net
2006	182.0	138.8	5.0	3.4	187.0	142.2
2005	182.0	141.7	6.0	3.3	188.0	145.0
2004	150.0	113.0	9.0	2.8	159.0	115.8

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Wells in progress as of December 31, 2006:

	Gross	Net
Exploratory	67.0	53.5
Development	76.0	54.0
Total	143.0	107.5

During 2006, we were required to file Form 23, “Annual Survey of Domestic Oil and Gas 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 consolidated financial statements in Item 8 to this Form 10-K. The primary differences are that Form 23 reports gross reserves, including the royalty owners’ share, and includes reserves for only those properties of which we are the operator.

Miles of Pipe:

The following table provides information concerning miles of pipe of our Natural Gas Distribution segment as of December 31, 2006.  For a further description of Arkansas Western's properties, we refer you to “Business — Natural Gas Distribution.”

	Total
Gathering	393
Transmission	1,033
Distribution	4,266
	5,692

Our Midstream Services segment has 212 miles of pipe in its gathering systems located in Arkansas.

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 pr operties that we operate, we conduct a thorough title examination and perform curative work with respect to significant defects before proceeding with operations.  We have performed a thorough title examination with respect to substantially all of our active properties that we operate.

ITEM 3.  LEGAL PROCEEDINGS  

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

We are subject to litigation and claims that have arisen in the ordinary course of business. Management believes, individually or in aggregate, such litigation and claims will not have a material adverse impact on our financial position or our results of operations but these matters are subject to inherent uncertainties and management's view may change in the future. If an unfavorable final outcome were to occur, there exists the possibility of a material impact on our financial position and the results of operations for the period in which the effect becomes reasonably estimable. We accrue for such items when a liability is both probable and the amount can be reasonably estimated.

A lawsuit was filed against us in 2001 alleging a breach of an agreement to indemnify the other party against settlement payments related to our Boure' prospect in Louisiana. The allegations were contested and, in 2002, we were granted a motion for summary judgment by the trial court. The case was appealed to the First Court of Appeals in Houston, Texas, which subsequently transferred the appeal to the Thirteenth Court of Appeals in Corpus Christi. The appeal was

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briefed and argued during 2003. On April 14, 2005, the Thirteenth Court of Appeals reversed the orders of the trial court and rendered judgment denying our motion for summary judgment and granting the motion for summary judgment of the other party. Our motion for rehearing with the Thirteenth Court of Appeals was denied on May 19, 2005. In August of 2005, we filed a petition for review with the Texas Supreme Court. In October of 2005, the Texas Supreme Court invited additional briefing by the parties. In March of 2006, the Texas Supreme Court requested that both parties submit full briefing on the merits of the case.  After receiving full briefing from both sides in July 2006, our petition for review with the Texas Supreme Court was denied on December 1, 2006, and the case has been remanded to the trial court for further disposition.  Should the other party prevail in the case, we could be required to pa y approximately $2.1 million, plus pre-judgment interest and attorney's fees. Based on an assessment of this litigation by us and our legal counsel, we accrued a loss in the fourth quarter of 2006.

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

None.   

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	62	10
Greg D. Kerley	Executive Vice President and Chief Financial Officer	51	17
Richard F. Lane	Executive Vice President, and President, Southwestern Energy Production Company and SEECO, Inc.	49	8
Mark K. Boling	Executive Vice President, General Counsel and Secretary	49	5
Gene A. Hammons	President, Southwestern Midstream Services Company	61	2
Alan N. Stewart	President, Arkansas Western Gas Company	62	3

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 Executive Vice President of Southwestern Energy Company and promoted to President, SEECO, Inc. and Southwestern Energy Production Company in December 2005.  He was appointed to the position of Executive Vice President, SEECO, Inc. and Southwestern Energy Production Company 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.

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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. Hammons was promoted to President of Southwestern Midstream Services Company in December 2005.  He joined the company in July 2005 as Vice President of Southwestern Midstream Services Company.  Prior to joining us, he provided consulting services to clients in the natural gas industry.  Previously, Mr. Hammons was employed by El Paso Natural Gas Company and Burlington Resources and held managerial positions in facility design and installation, gathering management and marketing over the course of his combined 28-year tenure.  

Mr. Stewart was promoted to President of Arkansas Western Gas Company in December 2005.  He joined the company in March 2004 as Executive Vice President of Arkansas Western Gas Company.  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.

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.”  On February 23, 2007, the closing price of our stock was $40.37 and we had 2,391 stockholders of record.  The following table presents the high and low sales prices for closing market transactions as reported on the New York Stock Exchange, which prices have been adjusted as appropriate to reflect the two-for-one stock splits effected in June 2005 and November 2005.

	Range of Market Prices
Quarter Ended	2006		2005		2004
March 31	$43.42	$29.33	$15.47	$11.22	$6.11	$4.84
June 30	$39.97	$24.80	$23.49	$14.20	$7.17	$5.97
September 30	$37.47	$27.95	$37.18	$24.78	$10.60	$7.42
December 31	$42.59	$27.86	$41.15	$31.30	$13.73	$10.33

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

Issuer Purchases of Equity Securities

We did not repurchase any shares of our equity securities during the fourth quarter of 2006.

Recent Sales of Unregistered Securities

We did not sell any unregistered equity securities during 2006.

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STOCK PERFORMANCE GRAPH

The following graph compares for the last five years, the performance of our common stock to the S&P MidCap 400 Index and the Dow Jones U.S. Exploration & Production Index (previously known as the Dow Jones Oil — Secondary Index).  The chart assumes that the value of the investment in our common stock and each index was $100 at December 31, 2001, and that all dividends were reinvested.  The stock performance shown on the graph below is not indicative of future price performance.

	12/31/01	12/31/02	12/31/03	12/31/04	12/31/05	12/31/06
Southwestern Energy Company	100	110	230	487	1,382	1,348
Dow Jones U.S. Exploration & Production	100	102	134	190	314	331
S&P MidCap 400 Index	100	85	116	135	152	168

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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, 2006. 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.”

	2006		2005		2004		2003		2002
	(in thousands except share, per share, stockholder data and percentages)
Financial Review Operating revenues
Exploration and production	$	491,545	$	403,234	$	286,924	$	176,245	$	122,207
Midstream services		475,207		459,890		314,977		201,976		131,067
Gas distribution and other		172,655		179,375		158,698		140,829		116,297
Intersegment revenues		(376,295)		(366,170)		(283,462)		(191,649)		(108,069)
		763,112		676,329		477,137		327,401		261,502
Operating costs and expenses
Gas purchases - midstream services		128,387		124,730		60,804		39,428		37,927
Gas purchases - gas distribution		79,363		82,689		64,311		52,585		48,388
Operating and general		132,691		101,500		78,231		70,479		64,600
Depreciation, depletion and amortization		151,290		96,211		73,674		55,948		53,992
Taxes, other than income taxes		25,109		25,279		17,830		11,619		10,090
		516,840		430,409		294,850		230,059		214,997
Operating income		246,272		245,920		182,287		97,342		46,505
Interest expense, net		(679)		(15,040)		(16,992)		(17,311)		(21,466)
Other income (expense)		17,079		4,784		(362)		797		(566)
Minority interest in partnership		(637)		(1,473)		(1,579)		(2,180)		(1,454)
Income before income taxes and accounting change		262,035		234,191		163,354		78,648		23,019
Income taxes
Current		-		-		-		-		-
Deferred		99,399		86,431		59,778		28,896		8,708
		99,399		86,431		59,778		28,896		8,708
Income before accounting change		162,636		147,760		103,576		49,752		14,311
Cumulative effect of adoption of accounting principle		-		-		-		(855)		-
Net income	$	162,636	$	147,760	$	103,576	$	48,897	$	14,311
Return on equity		11.3%		13.3%		23.1%		14.3%		8.1%
Net cash provided by operating activities	$	429,937	$	304,482	$	237,897	$	109,099	$	77,574
Net cash used in investing activities	$	(630,006)	$	(452,918)	$	(285,448)	$	(161,656)	$	(64,469)
Net cash provided by (used in) financing activities	$	19,291	$	370,906	$	47,509	$	52,144	$	(15,056)
Common Stock Statistics(1) Earnings per share:
Basic	$	0.97	$	0.98	$	0.72	$	0.37	$	0.14
Diluted	$	0.95	$	0.95	$	0.70	$	0.36	$	0.14
Cash dividends declared and paid per share	$	-	$	-	$	-	$	-	$	-
Book value per average diluted share	$	8.38	$	7.10	$	3.03	$	2.49	$	1.70
Market price at year-end	$	35.05	$	35.94	$	12.67	$	5.98	$	2.86
Number of stockholders of record at year-end		2,412		2,126		2,022		2,026		2,079
Average diluted shares outstanding		171,287,750		156,309,039		147,851,088		136,951,736		104,208,952

⁽¹⁾

 2004, 2003, and 2002 restated to reflect two-for-one stock splits effected in June and November 2005.

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	2006		2005		2004		2003		2002
Capitalization (in thousands)
Total debt	$	137,800	$	100,000	$	325,000	$	278,800	$	342,400
Common stockholders' equity(1)		1,434,643		1,110,304		447,677		341,561		177,488
Total capitalization	$	1,572,443	$	1,210,304	$	772,677	$	620,361	$	519,888
Total assets	$	2,379,069	$	1,868,524	$	1,146,144	$	890,710	$	740,162
Capitalization ratios:
Debt		8.8%		8.3%		42.1%		44.9%		65.9%
Equity		91.2%		91.7%		57.9%		55.1%		34.1%
Capital Investments (in millions) (2)
Exploration and production
Exploration and development	$	767.4	$	416.2	$	282.0	$	170.9	$	85.2
Drilling rigs (3)		93.6		35.1		-		-		-
		861.0		451.3		282.0		170.9		85.2
Midstream services		48.7		15.8		-		-		-
Gas distribution		11.2		10.9		7.3		8.2		6.1
Other		21.5		5.1		5.7		1.1		0.8
	$	942.4	$	483.1	$	295.0	$	180.2	$	92.1
Exploration and Production
Natural gas:
Production, Bcf		68.1		56.8		50.4		38.0		36.0
Average price per Mcf, including hedges	$	6.55	$	6.51	$	5.21	$	4.20	$	3.00
Average price per Mcf, excluding hedges	$	6.37	$	7.73	$	5.80	$	5.15	$	3.11
Oil:
Production, MBbls		698		705		618		531		682
Average price per barrel, including hedges	$	58.36	$	42.62	$	31.47	$	26.72	$	21.02
Average price per barrel, excluding hedges	$	63.17	$	54.37	$	40.55	$	29.66	$	23.94
Total gas and oil production, Bcfe		72.3		61.0		54.1		41.2		40.1
Lease operating expenses per Mcfe	$	.66	$	.48	$	.38	$	.39	$	.45
General and administrative expenses per Mcfe	$	.58	$	.46	$	.36	$	.41	$	.32
Taxes other than income taxes per Mcfe	$	.30	$	.37	$	.28	$	.22	$	.19
Proved reserves at year-end:
Natural gas, Bcf		978.9		772.3		594.5		457.0		374.6
Oil, MBbls		7,898		9,079		8,508		7,675		6,784
Total reserves, Bcfe		1,026.3		826.8		645.5		503.1		415.3
Midstream Services
Gas volumes marketed		72.7		61.9		57.0		42.7		45.5
Natural Gas Distribution
Sales and transportation volumes, Bcf		21.8		23.2		24.0		24.7		25.1
Off-system transportation (4)		0.1		-		1.0		0.3		2.2
Total volumes delivered		21.9		23.2		25.0		25.0		27.3
Customers at year-end:
Residential		133,679		130,654		127,622		124,776		122,906
Commercial		17,151		16,996		16,815		16,623		16,448
Industrial		173		170		175		174		189
		151,003		147,820		144,612		141,573		139,543
Degree days		3,413		3,744		3,678		3,969		3,950
Percent of normal		83%		91%		90%		99%		98%

⁽¹⁾  Stockholders' equity included accumulated other comprehensive income of $31.5 million in 2006 ($41.4 million income related to our cash flow hedges and a $9.9 million loss related to our pension liability and adoption of Statement on Financial Standards No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans”).  Stockholders’ equity included accumulated other comprehensive losses of $104.9 million in 2005 ($99.8 related to our cash flow hedges and $5.1 million related to our pension plan),  $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).

⁽²⁾ Capital investments for 2006, 2005, 2004 and 2003 included $88.9 million, $28.1 million, $3.9 million and $12.0 million, respectively, related to the change in accrued expenditures between years.

⁽³⁾ The drilling rigs and related equipment were sold in December 2006 as part of a sale and leaseback transaction.

⁽⁴⁾2005 off-system transportation volumes were less than 0.1 Bcf.

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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 Item 1A, “Risk Factors” in Part I 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.  Historical per share information provided for years prior to 2005, in “Item 6. Selected Financial Data,” financial statements, footnotes and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” has been adjusted to reflect the two-for-one stock splits effected on June 3, 2005 and November 17, 2005.

OVERVIEW

Southwestern Energy Company is an independent energy company primarily focused on natural gas. Our primary business is the exploration, development and production of natural gas and crude oil within the United States, with operations principally located in Arkansas, Oklahoma, Texas, and New Mexico. We are also focused on creating and capturing additional value at and beyond the wellhead through our established natural gas distribution and marketing businesses and our expanding gathering activities. Our marketing and our gas gathering businesses are collectively referred to as our Midstream Services.  We operate principally in three segments: Exploration and Production (E&P), Midstream Services and Natural Gas Distribution.

Our business strategy is focused on providing long-term growth in the net asset value of our business, which we achieve in our E&P business through the drillbit. In our E&P 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 E&P projects. Our actual PVI results are utilized to help determine the allocation of our future capital investments.  

We derive the vast majority of our operating income and cash flow from the natural gas production of our E&P business and expect this to continue in the future.  We expect that growth in our operating income and revenues will primarily depend on natural gas prices and our ability to increase our natural gas production.  In recent years, there has been significant price volatility in natural gas and crude oil prices due to a variety of factors we cannot control or predict.  These factors, which include weather conditions, political and economic events, and competition from other energy sources, impact supply and demand for natural gas, which determines the pricing.  In addition, the price we realize for our gas production is affected by our hedging activities as well as locational differences in market prices.  Our ability to increase our natural gas production is dependent upon our ability to economically find and produce natu ral gas, our ability to control costs and our ability to market natural gas on economically attractive terms to our customers.

In 2006, our gas and oil production increased 19% to 72.3 Bcfe. Gas and oil production increased 13% to 61.0 Bcfe in 2005. The increase in 2006 production primarily resulted from an increase in production from our Fayetteville Shale play.

We reported net income of $162.6 million in 2006, or $0.95 per share on a fully diluted basis, up 10% from the prior year. Net income in 2005 increased approximately 43% to $147.8 million, or $0.95 per share, compared to 2004. The increase in net income in 2006 was a result of increased production volumes in our E&P segment, a gain on the sale of our NOARK investment and decreased interest expense, partially offset by increased operating costs and expenses. The increase in net income in 2005 was a result of increased production volumes and higher realized natural gas and oil prices in our E&P segment. Our cash flow from operating activities increased 41% to $429.9 million in 2006, primarily due to increased production volumes in our E&P segment. Cash flow from operating activities in 2005 increased 28% to $304.5 million compared to 2004. Operating income for our E&P segment was $237.3 million in 2006, $234.8 million in 2005, and $164.6 mil lion in 2004. Operating income for our E&P segment increased marginally in 2006 as increased production volumes from our Fayetteville Shale play and East Texas were largely offset by increased operating costs and expenses. Operating income for our E&P segment increased in 2005 due to increased production volumes and higher realized prices. Operating income for our Midstream Services segment decreased 28% to $4.1 million in 2006 and increased 80% to $5.7 million in 2005, compared to prior years. Operating income for our Midstream Services segment decreased in 2006 as increased gathering revenues were more than offset by increased operating costs and expenses and a decrease in the margin generated by our marketing activities. Operating income for our Midstream Services segment increased in 2005 primarily due to favorable natural gas price opportunities along with increased volumes marketed. Operating income for our Natural Gas Distribution segment was $4.5 million in 2006, compared to $4.9 million in 2 005 and $8.5 million in 2004. The

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decrease in operating income for our Natural Gas Distribution segment in 2006 resulted primarily from warmer weather and increased operating costs and expenses, partially offset by increased rates implemented in October 2005. The decrease in operating income for our Natural Gas Distribution segment in 2005 resulted primarily from warmer weather and increased operating costs and expenses.  Customer conservation in recent years has also impacted operating income for this segment.

On May 2, 2006, we sold our 25% partnership interest in NOARK to Atlas Pipeline Partners, L.P., for $69.0 million. As part of the transaction, we assumed $39.0 million of debt obligations of NOARK Pipeline Finance, L.L.C., which we had previously guaranteed. We recognized a pre-tax gain of $10.9 million ($6.7 million after tax) in the second quarter relating to the transaction.

In our E&P segment, we achieved a reserve replacement ratio of 386% in 2006 at a finding and development cost of $2.75 per Mcfe, including reserve revisions, but excluding $93.6 million of capital invested in acquiring drilling rigs. Our year-end reserves grew 24% to 1,026.3 Bcfe, up from 826.8 Bcfe at the end of 2005. Our results were primarily fueled by our Fayetteville Shale play in Arkansas.

Our capital investments totaled $942.4 million in 2006, an increase of 95% compared to the prior year. Our 2005 capital investments were up 64% to $483.1 million. We invested $861.0 million in our E&P segment in 2006 (including $93.6 million invested in drilling rigs), compared to $451.3 million in 2005 and $282.0 million in 2004.  Funds for our 2006 capital investments were provided by cash flow from operations, cash equivalents from our equity offering in 2005, $69.0 million of proceeds from the sale of our investment in NOARK and cash proceeds of $127.3 million from a sale/leaseback transaction to monetize our investment in 13 drilling rigs. As a result, our total debt-to-capitalization ratio increased slightly to 9% at December 31, 2006 from 8% at December 31, 2005.

For 2007, our planned capital investments are $1.3 billion, an increase of 42% over 2006 capital spending.  The capital investments for 2007 include $1.2 billion for our E&P segment, $84 million for our Midstream Services segment and $20 million for improvements to our utility system and other corporate purposes. The $1.2 billion of exploration and production investments includes $875 million for the development of our Fayetteville Shale play. We continue to be focused on our strategy of adding value through the drillbit, as approximately 82% of our 2007 E&P capital is allocated to drilling. In addition to the planned investments in the Fayetteville Shale play, our E&P investments in 2007 will be focused on our lower-risk development drilling programs in East Texas and other conventional drilling in the Arkoma Basin. In 2007, we are targeting production to be approximately 105.0 Bcfe to 110.0 Bcfe, compared to 72.3 Bcfe in 2006, an increase of approximately 45% to 50%. We expect our capital investments in 2007 to be funded by cash flow from operations, cash equivalents at December 31, 2006, borrowings under our recently amended revolving credit facility and/or funds raised in the public debt and equity markets.

We expect growth in our reported production volumes and our oil and gas reserve quantities in 2007 given the current commodity price environment and our continued success in our Fayetteville Shale project.  We also believe we will have access to sufficient capital to carry out our plans while maintaining an acceptable balance between debt and equity financing.

RESULTS OF OPERATIONS

Exploration and Production

	Year Ended December 31,
	2006	2005	2004
Revenues (in thousands)	$ 491,545	$ 403,234	$ 286,924
Operating income (in thousands)	$ 237,307	$ 234,759	$ 164,585
Gas production (Bcf)	68.1	56.8	50.4
Oil production (MBbls)	698	705	618
Total production (Bcfe)	72.3	61.0	54.1
Average gas price per Mcf, including hedges	$ 6.55	$ 6.51	$ 5.21
Average gas price per Mcf, excluding hedges	$ 6.37	$ 7.73	$ 5.80
Average oil price per Bbl, including hedges	$ 58.36	$ 42.62	$ 31.47
Average oil price per Bbl, excluding hedges	$ 63.17	$ 54.37	$ 40.55
Average unit costs per Mcfe:
Lease operating expenses	$ 0.66	$ 0.48	$ 0.38
General & administrative expenses	$ 0.58	$ 0.46	$ 0.36
Taxes other than income taxes	$ 0.30	$ 0.37	$ 0.28
Full cost pool amortization	$ 1.90	$ 1.42	$ 1.20

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Revenues, Operating Income and Production

Revenues. Revenues for our E&P segment increased 22% in 2006 to $491.5 million due to a 20% increase in gas production volumes. Revenues increased 41% in 2005 to $403.2 million, primarily due to higher prices received for our natural gas and oil production and increased gas production. We expect our production volumes to continue to increase primarily due to the development of our Fayetteville Shale play in Arkansas.  Gas and oil prices are difficult to predict and are subject to wide price fluctuations.  As of February 23, 2007, we have hedged 79.5 Bcf, 57.0 Bcf and 8.0 Bcf of our 2007, 2008 and 2009 gas production, respectively, to help limit our exposure to price fluctuations. Revenues for 2006, 2005 and 2004 also include pre-tax gains of $4.0 million, $3.1 million and $4.5 million, respectively, related to the sale of gas-in-storage inventory.

Operating Income. Operating income from our E&P segment was $237.3 million in 2006, compared to $234.8 million in 2005, as revenues from increased production volumes were largely offset by increased operating costs and expenses. Operating income was up 43% in 2005 compared to 2004 due to an increase in revenue primarily driven by increased production volumes and higher realized prices.

Production. Gas and oil production was up approximately 19% to 72.3 Bcfe in 2006 and up 13% to 61.0 Bcfe in 2005, compared to prior periods. The increase in 2006 was the result of a 10.0 Bcf increase in production from our Fayetteville Shale play and a 4.0 Bcf increase in our East Texas production, partially offset by declines in production from our Permian and Gulf Coast properties. Our production in the Fayetteville Shale play in 2006 was negatively impacted in the last part of the year by a shortage of pressure pumping equipment and completion crews in the play area. Additional equipment and crews are now available in the play area and are currently keeping pace with our drilling activity. The increase in 2005 production resulted from a 5.4 Bcfe increase in production from our Overton Field in East Texas and a 1.9 Bcfe increase in production from the Fayetteville Shale. Production during 2005 was reduced by the effect of the curtailment of a por tion of our Overton Field production due to repairs of a transmission line and by the effect of Hurricane Katrina. Combined, these events reduced our production by an estimated 1.0 Bcfe.

Gas sales to unaffiliated purchasers were up 23% to 63.4 Bcf in 2006 and up 15% to 51.7 Bcf in 2005, compared to the prior years. 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 decreased 7% to 4.7 Bcf in 2006 and decreased 6% to 5.1 Bcf in 2005. We expect future increases in demand for our gas production to come from sales to unaffiliated purchasers. We are unable to predict changes in the market demand and price for natural gas, including weather-related changes affecting demand of both affiliated and unaffiliated customers for our production.

During the fourth quarter of 2006, we completed the sale of our remaining South Louisiana properties to a private company for $12.7 million.  These properties had proved reserves of 7.0 Bcfe and produced approximately 1.1 Bcfe annually.  With this divestiture, we no longer have producing properties in the South Louisiana area.

We are targeting 2007 gas and oil production of 105.0 to 110.0 Bcfe, an increase of 45% to 50% over our 2006 production. Based on early production histories and modeling and assuming continued positive results, approximately 45.0 to 50.0 Bcf of our 2007 targeted gas production is projected to come from our activities in the Fayetteville Shale play. Although we expect production volumes in 2007 to increase, we cannot guarantee our longer-term success in discovering, developing, and producing reserves, including with respect to our Fayetteville Shale play. 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 1A 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.

Commodity Prices

We periodically enter into various hedging and other financial arrangements with respect to a portion of our projected natural gas and crude oil production in order to ensure certain desired levels of cash flow and to minimize the impact of price fluctuations, including fluctuations in locational market differentials (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, increased slightly to $6.55 per Mcf in 2006 and increased 25% to $6.51 per Mcf in 2005. 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 increased the average gas price $0.18 per Mcf in 2006, compared to reductions of $1.22 per Mcf in 2005 and $0.59 per Mcf in 2004. In recent years, locational differences in marke t prices for natural gas have been wider than historically experienced. Disregarding the impact of hedges, historically

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the average price received for our gas production was approximately $0.30 to $0.50 per Mcf lower than average NYMEX spot market prices due to the locational market differentials. However, during both 2006 and 2005, widening market differentials caused the difference in our average price received for our gas production to be approximately $0.90 per Mcf lower than spot market prices.  Assuming a NYMEX commodity price for 2007 of $7.00 per Mcf of gas, our differential for the average price received for our gas production is expected to be approximately $0.65 to $0.70 per Mcf below the NYMEX Henry Hub index price, including the impact of our basis hedges.  As of December 31, 2006, we have financially protected future gas production volumes of 64.3 Bcf in 2007 and 38.1 Bcf in 2008 from the impact of widening basis differentials through our hedging activities and sales arrangements.  

In addition to the basis hedges discussed above, at December 31, 2006, we had NYMEX commodity price hedges in place on 65.0 Bcf of 2007 and 35.0 Bcf of 2008 expected future gas production.  Subsequent to December 31, 2006 and prior to February 23, 2007, we hedged 12.5 Bcf of 2007, 11.0 Bcf of 2008 and 4.0 Bcf of 2009 gas production under fixed price swaps with a sales price ranging from $7.29 to $8.62. Additionally, we hedged 2.0 Bcf of 2007, 11.0 Bcf of 2008 and 4.0 Bcf of 2009 gas production under costless collars with floor prices ranging from $7.25 to $8.50 per Mcf and ceiling prices ranging from $9.07 to $10.95 per Mcf.  As of February 19, 2007, we have hedged approximately 75% of our 2007 anticipated gas production level.

We realized an average price of $58.36 per barrel, including the effects of hedges, for our oil production for the year ended December 31, 2006, up approximately 37% from the prior year. The 2005 realized average price of $42.62 per barrel, including the effects of hedges, for our oil production was up 35% from 2004. The average price we received for our oil production in 2006, 2005 and 2004 was reduced by $4.81, $11.75 and $9.08 per barrel, respectively, due to the effects of our hedging activities. Assuming a NYMEX commodity price of $60.00 per barrel of oil for 2007, we expect the average price received for our oil production during 2007 to be approximately $1.00 per barrel lower than average spot market prices, as market differentials reduce the average prices received.

Operating Costs and Expenses

Lease operating expenses per Mcfe for the E&P segment were $0.66 in 2006, compared to $0.48 in 2005 and $0.38 in 2004. Lease operating expenses per unit of production increased in 2006 due primarily to increases in gathering and other costs related to our operations in the Fayetteville Shale play. We expect our per unit operating cost for this segment to range between $0.82 and $0.87 per Mcfe in 2007 due to increased production volumes from the Fayetteville Shale play. Additionally, inflationary pressures continue to have an impact in all of our operating areas.

General and administrative expenses per Mcfe for this segment were $0.58 in 2006, up from $0.46 in 2005 and $0.36 in 2004. The increases in general and administrative costs per Mcfe in 2006 and 2005 were due primarily to increased payroll and related costs associated with the expansion of our E&P operations due to the Fayetteville Shale play and to increased incentive compensation costs. We added 494 new employees during 2006, most of which were hired in our E&P segment, and we expect to hire an additional 171 employees in 2007. Approximately 300 of the total new hires during 2006 were employed by our drilling company. We expect our cost per unit for general and administrative expenses to decline in 2007 and to range between $0.41 and $0.46 per Mcfe. The expected decrease in per unit costs is due to increased production volumes from our Fayetteville Shale play and a reduced rate of expansion in our E&P workforce. Fu ture changes in our general and administrative expenses for this segment are primarily dependent upon our salary costs, level of pension expense, stock-based compensation expensing under Statement on Financial Accounting Standards No. 123R “Share-Based Payment” (FAS 123R) and the amount of incentive compensation paid to our employees. For eligible employees, a portion of incentive compensation is based on the achievement of certain operating and performance results, including targeted cash flow, production, proved reserve additions, present value added for each dollar of capital invested, and lease operating expenses and general and administrative expenses per unit of production, while another portion is discretionary based upon an employee’s performance. Additional discretionary awards may also be awarded under the incentive compensation plan. See “Critical Accounting Policies” below for further discussion of pension expense, and “Adoption of Accounting Principles” below f or further discussion of stock-based compensation expensing under FAS 123R.

Our full cost pool amortization rate averaged $1.90 per Mcfe for 2006, $1.42 per Mcfe for 2005 and $1.20 per Mcfe for 2004. The amortization rate is impacted by reserve additions and the costs associated with those additions, revisions of previous reserve estimates due to both price and well performance, write-downs that result from full cost ceiling tests and the level of unevaluated costs excluded from amortization. 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 amount of future reserves attributed to our Fayetteville Shale play. Unevaluated costs excluded from amortization were

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$166.8 million at the end of 2006, compared to $122.3 million at the end of 2005 and $47.2 million at the end of 2004. The increase in unevaluated costs since December 31, 2004 resulted primarily from an increase in our undeveloped leasehold acreage related to our Fayetteville Shale play and increased drilling activity.

We utilize the full cost method of accounting for costs related to the exploration, development and acquisition of oil and natural gas 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. These capitalized costs are subject to a ceiling test that 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 the 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 companie s 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.  However, commodity price increases subsequent to the end of a reporting period but prior to the release of periodic reports may be utilized to calculate the ceiling value of reserves. At December 31, 2006, 2005 and 2004, our unamortized costs of natural gas and oil properties did not exceed this ceiling amount. At December 31, 2006, our standardized measure was calculated based upon quoted market prices of $5.64 per Mcf for Henry Hub gas and $57.25 per barrel for West Texas Intermediate oil, adjusted for market differentials, and included approximately $135.2 million related to the positive effects of future cash flow hedges of gas production. At December 31, 2005, our standardized measure was calculated based upon quoted market prices of $10.08 per Mcf for Henry Hub gas and $61.04 per barrel for West Texas Intermediate oil, a nd 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. A decline in natural gas and oil prices from year-end 2006 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.

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 were minimal due to low inflation rates. However, since 2001, as commodity prices have increased, the impact of inflation has intensified in our E&P segment as shortages in drilling rigs, third-party services and qualified labor have risen due to increased activity levels in the natural gas and oil industry. This impact will continue to increase to the extent commodity prices remain high or further increase. We have endeavored to mitigate rising costs by obtaining vendor pricing commitments for multiple projects and by offering performance bonuses related to increased economic efficiencies.

Taxes other than income taxes per Mcfe were $0.30 in 2006, $0.37 in 2005 and $0.28 in 2004, and vary from year to year primarily due to changes in severance and ad valorem taxes that result from the fluctuations in commodity prices.

The timing and amount of production and reserve additions attributed to our Fayetteville Shale play could have a material impact on our per unit costs; if production or reserves additions are lower than projected, our per unit costs would increase.

Midstream Services

	Year Ended December 31,
	2006	2005	2004
Revenues (in millions)	$  475.2	$  459.9	$  315.0
Gas purchases (in millions)	$  458.9	$  451.1	$  310.7
Operating costs and expenses (in millions)	$    12.2	$      3.1	$      1.1
Operating income (in millions)	$      4.1	$      5.7	$      3.2
Gas volumes marketed (Bcf)	72.7	61.9	57.0

Revenues from our Midstream Services segment were up 3% in 2006 and up 46% in 2005, as compared to prior years. The increase in revenues in 2006 resulted from increased marketing and gathering activities. The increase in 2005 revenues was primarily due to an increase in natural gas commodity prices. Increases and decreases in marketing revenues due to changes in commodity prices are largely offset by corresponding changes in gas purchase expense. Midstream Services had gathering revenues of $7.9 million in 2006, related to its gathering systems in Arkansas, compared to $1.0 million in 2005. Gathering revenues and expenses for this segment are expected to continue to grow in the future as reserves related to our Fayetteville Shale play are developed and production increases. Operating income from our Midstream Services segment decreased 28% in 2006 and increased 80% in 2005. The decrease in 2006 was due to increased operating co sts and expenses that resulted from increased staffing and other costs associated with our growing gathering activities, and a decrease in the margin generated by our marketing activities caused in part by increased volatility of locational market differentials in our core operating areas. Operating income from natural gas marketing

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activities fluctuates depending on the margin we are able to generate between the purchase of the commodity and the ultimate disposition of the commodity. In 2005, we were able to generate higher margins on our marketing efforts.  We marketed 72.7 Bcf in 2006, compared to 61.9 Bcf in 2005 and 57.0 Bcf in 2004. The increase in volumes marketed in 2006 and 2005 resulted from marketing our increased production volumes, largely related to our Fayetteville Shale play and our Overton Field in East Texas. Additionally in 2006, volumes marketed for third parties increased due to production growth in areas where we have historically provided marketing services to other working interest owners. Of the total volumes marketed, production from our E&P subsidiaries accounted for 72% in 2006, 76% in 2005 and 77% in 2004. We enter into hedging activities from time to time with respect to our gas marketing activities to prov ide margin protection. We refer you to “Quantitative and Qualitative Disclosures About Market Risk” and Note 8 to the financial statements for additional information.

On April 10, 2006, our Midstream Services unit entered into a three-year firm transportation agreement with Ozark Gas Transmission System to transport volumes increasing to 175,000 MMBtu per day in the later stages of the contract.  On August 22, 2006, we amended the agreement to increase the maximum volumes transported from 175,000 MMBtu per day to 220,000 MMBtu per day in the later stages of the contract. Additionally, on January 25, 2007, we entered into a separate two-year firm transportation agreement with Ozark Gas Transmission System to transport volumes of 50,000 MMBtu per day. On December 15, 2006, one of our Midstream Services subsidiaries entered into a precedent agreement pursuant to which we will contract for firm gas transportation services on two newly-proposed pipeline laterals and related facilities of Texas Gas Transmission, LLC (Texas Gas), a subsidiary of Boardwalk Pipeline Partners, LP.  Depending on regulatory approvals, th e expected in-service date for both laterals is January 1, 2009. See “Contractual Obligations and Contingent Liabilities and Commitments” below for further discussion.

Over the next several years, we expect our gathering revenues and operating expenses to increase significantly as our E&P segment grows its production volumes from the development of our Fayetteville Shale play.

Natural Gas Distribution

	Year Ended December 31,
	2006	2005	2004
	($ in thousands except for per Mcf amounts)
Revenues	$ 172,207	$ 178,482	$ 152,449
Gas purchases	$ 112,922	$ 120,852	$   97,274
Operating costs and expenses	$   54,811	$   52,719	$   46,659
Operating income	$     4,474	$     4,911	$     8,516
Deliveries (Bcf)
Sales and end-use and off-system transportation	21.9	23.2	25.0
Sales customers at year-end	151,003	147,820	144,612
Average sales rate per Mcf	$     12.30	$     11.85	$       9.39
Heating weather - degree days	3,413	3,744	3,678
Percent of normal	83%	91%	90%

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. Revenues for 2006 decreased 4% to $172.2 million and revenues for 2005 increased 17% to $178.5 million. The decrease in 2006 gas distribution revenues was primarily due to lower sales volumes as a result of warmer weather. The increase in 2005 gas distribution revenues was primarily due to higher average sales rates as a result of higher gas prices and the effects of a $4.6 million annual rate increase implemented in October 2005.

Operating income for our Natural Gas Distribution segment decreased 9% in 2006 and decreased 42% in 2005. The decrease in 2006 operating income resulted primarily from warmer weather and increased operating costs and expenses partially offset by the effects of the rate increase implemented in October 2005. The decrease in 2005 operating income for this segment resulted primarily from increased operating costs and expenses. 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. Weather during 2006 in the utility's service territory was 17% warmer than normal and 8% warmer than the prior year. Weather during 2005 in the utility's service territory was 9% warmer than normal and 1% colder than the prior year.

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Deliveries and Rates

In 2006, Arkansas Western sold 13.4 Bcf to its customers at an average rate of $12.30 per Mcf, compared to 14.4 Bcf at $11.85 per Mcf in 2005 and 15.5 Bcf at $9.39 per Mcf in 2004. Additionally, Arkansas Western transported 8.4 Bcf in 2006, compared to 8.8 Bcf in 2005 and 8.5 Bcf in 2004 for its end-use customers. The decreases in volumes sold in 2006 and 2005 primarily resulted from warmer than normal weather and customer conservation brought about by high gas prices in recent years. 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.  

Arkansas Western has a transportation contract with Ozark Gas Transmission System for approximately 66,900 MMBtu per day of firm capacity that expires in 2014. Deliveries are made by the pipeline to portions of Arkansas Western’s distribution systems and to the interstate pipelines with which it interconnects.

Operating Costs and Expenses

The changes in purchased gas costs for the Natural 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 2006 to $54.8 million from $52.7 million in 2005. The increase was primarily due to an increase in general and administrative expenses due to increased salaries and incentive compensation costs. Operating costs and expenses for 2005, net of purchased gas costs, increased to $52.7 million from $46.7 million in 2004 due primarily to a $2.8 million increase in general and administrative expenses due to increased salaries and incentive compensation costs, and a $1.3 million increase in transmission expense as a result of higher fuel costs. Future changes in our general and administrative expenses for this segment are primarily dependent upon our salary costs, level of pens ion expense, stock-based compensation expensing under FAS 123R and the amount of incentive compensation paid to our employees. See “Critical Accounting Policies” and “Adoption of Accounting Principles” below for further discussion of pension expense and stock-based compensation expensing, respectively.

Inflation impacts our Natural 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 Natural Gas Distribution segment.

Regulatory Matters

Arkansas Western’s 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. Although its rates for gas delivered to its retail customers are not regulated by the FERC, its transmission and gathering pipeline systems are subject to the FERC’s regulations concerning open access transportation.

In October 2005, in response to Arkansas Western’s request for a $9.7 million rate increase, the APSC approved a rate increase totaling $4.6 million annually, exclusive of costs to be recovered through Arkansas Western’s purchase gas adjustment clause. The rate increase was effective for deliveries made to customers on or after October 31, 2005. The request relating to the October 2005 increase assumed a rate of return of 11.5% and a capital structure of 50% debt and 50% equity. The APSC order provided for an allowed return on equity of 9.7% and an assumed capital structure of 54% debt and 46% equity. In its order approving the rate increase, the APSC stated that it would consider in future generic proceedings, certain regulatory changes including a streamlined rate case process, a revenue decoupling mechanism designed to encourage efficiency and conservation, and a performance based methodology designed to allow a var iable return on equity adjustment within a reasonable range. On September 25, 2006, our Natural Gas Distribution segment filed with the APSC an application to modify its general rates and charges. The application seeks to increase annual operating revenues by $13.1 million, a 6.8% annual increase.  The APSC has 10 months to render a decision on the application. Any increase approved is expected to take effect in July 2007.

On January 12, 2006, the APSC initiated a notice of inquiry regarding a rulemaking for developing and implementing energy efficiency programs.  Following a collaborative process, the APSC issued energy efficiency rules on January 11, 2007.  These rules require all gas and electric utilities, excluding electric cooperatives, to file energy efficiency plans and programs with the APSC.  Quick start or pilot programs are to be implemented by late 2007, and comprehensive

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programs are to be implemented in 2009.  Utilities will recover the costs of these programs from their customers.  The APSC will address lost revenues associated with these programs in the utilities’ future rate cases. We have not yet determined the effect of these rules on our future operations and have not included any revenue loss in our pending rate case.

On December 19, 2006, the APSC issued affiliate transactions rules.  In January 2007, Arkansas Western and other utilities requested a rehearing of these rules.  On February 16, 2007, the APSC issued an order granting a rehearing and staying the implementation of the affiliate transaction rules pending further review.  A public hearing on this issue is scheduled for March 27, 2007.  Arkansas Western anticipates that these rules, if not modified on rehearing, will increase its regulatory costs and overall cost of service.

Rate increase requests, which may be filed in the future, will depend on APSC policies, customer growth, increases in operating expenses and additional investment in property, plant and equipment.

Transportation

On May 2, 2006, we sold our 25% partnership interest in NOARK Pipeline System, Limited Partnership (NOARK) to Atlas Pipeline Partners, L.P. for $69.0 million and recognized a pre-tax gain of approximately $10.9 million ($6.7 million after-tax) in the second quarter relating to the transaction. We recorded pre-tax income from operations related to our investment in NOARK of $0.9 million in 2006, compared to $1.6 million in 2005 and a pre-tax loss of $0.4 million in 2004. Income from operations and the gain on the sale in the second quarter of 2006 were recorded in other income in our statements of operations. We refer you to Note 7 to the consolidated financial statements for additional discussion.

Other Revenues

In 2006, 2005 and 2004, other revenues included pre-tax gains of $4.0 million, $3.1 million and $4.5 million, respectively, related to the sale of gas-in-storage inventory. Other revenues for 2005 and 2004 also included pre-tax gains of $0.4 million and $5.8 million, respectively, related to sales of undeveloped real estate.

Interest Expense and Interest Income

Interest costs, net of capitalization, were down 95% to $0.7 million in 2006 and down 11% to $15.0 million in 2005, both as compared to prior years. Interest expense decreased in 2006 due to decreased debt levels resulting from our equity offering in September 2005 and increased capitalized interest. Interest expense decreased in 2005 due primarily to increased capitalized interest. We refer you to “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Financing Requirements” and Note 2 to the consolidated financial statements for further discussion of our debt. Interest capitalized increased to $11.8 million in 2006, up from $6.0 million in 2005 and $2.8 million in 2004. Changes in capitalized interest are primarily due to the level of investment in unevaluated properties and the capitalization of interest during the construction phase of our drilling rigs in our E&P segment. Costs excluded from amortization in the E&P segment increased to $166.8 million at December 31, 2006, compared to $122.3 million at December 31, 2005. Total capital investments for our E&P segment were $861.0 million in 2006, up from $451.3 million in 2005.

During 2006 and 2005, we earned interest income of $6.3 million and $3.4 million, respectively, related to our cash investments. These amounts are recorded in other income. We did not have any interest income in 2004.

Income Taxes

In 2006, the state of Texas enacted legislation to replace its method of taxing businesses from a capital based tax to a tax on modified gross revenue. Although this change in taxation method was not effective until 2007, the provisions of Statement on Financial Accounting Standards No. 109, “Accounting for Income Taxes” (FAS 109), required us to record in 2006 the impact that this change has on our liability for deferred taxes. As a result, we recorded additional income tax expense of $1.8 million, net of federal income tax effect, in the second quarter of 2006. This one-time adjustment increased our effective tax rate to approximately 37.9% for 2006, compared to 36.9% in 2005, and 36.6% in 2004. Other than the change resulting from Texas taxes discussed above, the changes in the provision for deferred income taxes recorded each period result primarily from the level of income before income taxes, adjusted for perman ent differences.

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Pension Expense

We recorded an expense of $4.0 million in 2006 for our pension and other postretirement benefit plans, compared to $2.3 million in 2005 and $2.2 million in 2004. The amount of pension expense recorded is determined by actuarial calculations and is also impacted by the funded status of our plans. During 2006, $3.4 million was contributed to our pension plans and $0.4 million was contributed to our other postretirement plans. As of December 31, 2006, we have adopted Statement of Financial Accounting Standards No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans”, or FAS 158. See “Adoption of Accounting Principles” below and Note 4 to the consolidated financial statements for further discussion of FAS 158. For further discussion of our pension plans, we refer you to Note 4 to the consolidated financial statements and “Critical Accounting Policies” below.  

Adoption of Accounting Principles

In September 2006, the FASB issued Statement of Financial Accounting Standards No. 157, “Fair Value Measurements”, or FAS 157. This Statement defines fair value as used in numerous accounting pronouncements, establishes a framework for measuring fair value in generally accepted accounting principles and expands disclosure related to the use of fair value measures in financial statements. The Statement is to be effective for our financial statements issued in 2008; however, earlier application is encouraged. We are currently evaluating the timing of adoption and the impact that adoption might have on our financial position or results of operations.

During the fourth quarter of 2006, we adopted FAS 158 which requires us to recognize the funded status of each defined pension benefit plan, retiree health care and other postretirement benefit plans and post employment benefit plans on the balance sheet. Each over-funded plan is recognized as an asset and each under-funded plan is recognized as a liability. The initial impact of the adoption of the standard as well as subsequent changes in the funded status is recognized as a component of accumulated comprehensive loss in the statement of stockholders equity. Additional minimum pension liabilities and related intangible assets are also derecognized upon adoption of the new standard. FAS 158 requires initial application for fiscal years ending after December 15, 2006. As a result of the application of FAS 158, we have recorded a liability of $13.8 million on our balance sheet in order to recognize the funded status of our pension and other postretirement benefit plans. We have also recorded our unrecognized prior service costs and unrecognized gains and losses from changes in plan assumptions as a component of other comprehensive income (loss).  See Note 4 of our financial statements for further information on the impact of this standard on our financial statements.

In July 2006, the FASB issued FASB Interpretation No. 48 “Accounting for Uncertainty in Income Taxes – an interpretation of FASB Statement No. 109”, or FIN 48, to clarify certain aspects of accounting for uncertain tax positions, including issues related to the recognition and measurement of those tax positions. This interpretation is effective for fiscal years beginning after December 15, 2006. We are in the process of evaluating the impact of the adoption of this interpretation; however, we do not expect any material impacts on our results of operations and financial condition.

In September 2006, the Securities and Exchange Commission, or the SEC, issued Staff Accounting Bulletin No. 108, or SAB 108. Due to diversity in practice among registrants, SAB 108 expresses SEC staff views regarding the process by which misstatements in financial statements are evaluated for purposes of determining whether financial statement restatement is necessary. SAB 108 is effective for fiscal years ending after November 15, 2006. The adoption of SAB 108 had no impact on our financial position or our reported results from operations.

LIQUIDITY AND CAPITAL RESOURCES

We depend primarily on internally-generated funds, our unsecured revolving credit facility (discussed below under “Financing Requirements”) and funds accessed through public debt and equity markets as our primary sources of liquidity. In February 2007, we amended our revolving credit facility and may now borrow up to $750 million from time to time. The amount available under our revolving credit facility may be increased to $1 billion at any time upon our agreement with our existing or additional lenders. As of December 31, 2006 and December 31, 2005, we had no indebtedness outstanding under our revolving credit facility. During 2007, we expect to draw on a portion of the funds available under our credit facility to fund our planned capital investments (discussed below under “Capital Investments”), which are expected to exceed the net cash generated by our operations and cash investments that we had at December 31, 2006 that related to the proceeds from our December 2006 sale/leaseback transaction, as discussed below under “Off-Balance Sheet Arrangements.”

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In September 2005, we consummated an underwritten offering of 9,775,000 shares of our common stock pursuant to an effective shelf registration statement filed with the SEC. The net proceeds of the offering were used to pay down outstanding indebtedness under our revolving credit facility, to pay our 6.70% Notes due December 2005 and to fund capital investments.  

Net cash provided by operating activities increased 41% to $429.9 million in 2006, compared to a 28% increase in 2005 to $304.5 million. 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 2006 and 2005 due mainly to increased net income, adjusted for increased depreciation, depletion and amortization expense and increased deferred income taxes generated by our E&P segment. Net cash from operating activities provided 46% of our cash requirements for capital investments in 2006, 63% in 2005 and 81% in 2004.

At December 31, 2006, our capital structure consisted of 9% debt and 91% equity. We believe that our operating cash flow, cash investments at December 31, 2006 and borrowings under our credit facility will be adequate to meet our capital and operating requirements for 2007, however, we may also raise funds in the public debt and equity markets to meet a portion of our cash requirements.

Our cash flow from operating activities is highly dependent upon the market prices that we receive for our gas and oil production. The price received for our production is also influenced by our commodity hedging activities, as more fully discussed in Note 8 to the financial statements included in this Form 10-K and Item 7A, “Quantitative and Qualitative Disclosures about Market Risk.” Natural gas and oil prices are subject to wide fluctuations. As a result, we are unable to forecast with certainty our future level of cash flow from operations. We adjust our discretionary uses of cash dependent upon cash flow available.

Capital Investments

Our capital investments increased 95% to $942.4 million in 2006 and 64% to $483.1 million in 2005. Capital investments included $88.9 million in 2006, $28.1 million in 2005 and $3.9 million in 2004 related to accrued expenditures. Capital investments for 2006 in our E&P Segment included $767.4 million related to our primary business activities and $93.6 million related to the purchase of drilling rigs and related equipment which were sold in December 2006 as part of a sale and leaseback transaction. Our capital investments in 2005 also included $35.1 million related to construction payments on the rigs that were sold in 2006. Our E&P segment expenditures included $8.6 million for the acquisition of interests in natural gas and oil producing properties in 2006 and $14.2 million in 2004.

	2006	2005	2004
	(in thousands)
Exploration and production
Exploration and development	$   767,400	$  416,161	$  281,988
Drilling rigs	93,641	35,128	-
	861,041	451,289	281,988
Midstream services	48,660	15,840	-
Natural gas distribution	11,232	10,908	7,298
Other	21,474	5,014	5,704
	$   942,407	$  483,051	$  294,990

Our capital investments for 2007 are planned to be $1,341 million, consisting of $1,237 million for exploration and production, $84 million for midstream services, and $20 million for gas distribution system improvements and general purposes. We expect to allocate $875 million of our 2007 E&P capital to our Fayetteville Shale play. Our planned level of capital investments in 2007 will allow us to significantly accelerate our drilling activity in the Fayetteville Shale, continue the development of our Overton Field and Angelina River Trend 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 Natural Gas Distribution segment. As discussed above, our 2007 capital investment program is expected to be fund ed through cash flow from operations, cash investments at December 31, 2006, and borrowings under our revolving credit facility. We may also raise funds in the public debt and equity markets to fund a portion of our capital investment program. We may adjust the level of 2007 capital investments dependent upon our level of cash flow generated from operations and our ability to borrow under our credit facility.

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Financing Requirements

Our total debt outstanding was $137.8 million at December 31, 2006 and $100.0 million at December 31, 2005. Our revolving credit facility was amended in February 2007 increasing our borrowing capacity to $750 million, with an accordion feature for an additional $250 million, lowering our borrowing cost and extending the maturity date to February 2012. At December 31, 2006 and December 31, 2005, we had no outstanding debt under our revolving credit facility. The interest rate on the facility is calculated based upon our public debt rating and is currently 87.5 basis points over LIBOR. The Credit Facility is guaranteed by our subsidiaries, Southwestern Energy Production Company, SEECO, Inc. and Southwestern Energy Services Company. The Credit Facility requires additional subsidiary guarantors if certain guaranty coverage levels are not satisfied. Our publicly traded notes were downgraded on August 1, 2006 by Standard and Poor’s to BB+ with a stable out look from BBB- with a negative outlook. We have a Corporate Family Rating of Ba2 by Moody’s, and our publicly traded notes were rated Ba3 by Moody’s under Moody’s Loss Given Default Assessment on September 19, 2006. Any future downgrades in our public debt ratings could increase our cost of funds under the credit facility. We do not expect our current ratings to impact our ability to obtain acceptable financing terms if we elect to access the public debt market in the future.

Our revolving credit facility contains covenants which impose certain restrictions on us. Under the credit agreement, we may not issue total debt in excess of 60% of our total capital, must maintain a certain level of stockholders’ 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 all of the covenants of our credit agreement at December 31, 2006. Although we do not anticipate any violations of our financial covenants, our ability to comply with those covenants 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.

At December 31, 2006, our capital structure consisted of 9% debt and 91% equity, with a ratio of EBITDA to interest expense of 610.5. Stockholders’ equity in the December 31, 2006 balance sheet includes an accumulated other comprehensive gain of $41.4 million related to our hedging activities that is required to be recorded under the provisions of Statement on Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities” (FAS 133), and a loss of $9.9 million related to changes in our pension liability and the adoption FAS 158. The amount recorded for FAS 133 is based on current market values of our hedges at December 31, 2006, 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 with the physical delivery of sales volumes hedged. Our credit facility’s financial covenants wit h respect to capitalization percentages exclude the effects of non-cash entries that result from FAS 133 and FAS 158 and the non-cash impact of any full cost ceiling write-downs. Our capital structure at December 31, 2006 would remain at 9% debt and 91% equity without consideration of the accumulated other comprehensive gain and loss related to FAS 133 and FAS 158.

As part of our strategy to ensure a certain level of cash flow to fund our operations, we have hedged approximately 75% of our expected 2007 gas 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 their current levels throughout 2007, our capital expenditure plans do not change and we do not issue equity, we will increase our long-term debt in 2007 by approximately $700 to $750 million. If commodity prices significantly decrease, we may decrease and/or reallocate our planned capital investments.

Off-Balance Sheet Arrangements

On December 29, 2006, we sold 13 of our existing drilling rigs and assigned our right to purchase two other drilling rigs to be delivered and related equipment to various financial institutions and leased the rigs from the buyers for an initial term of eight years from January 1, 2007 with aggregate rental payments of $19.6 million annually. We received proceeds of $127.3 million. This transaction was recorded as a sale and operating leaseback with an aggregate deferred gain of $7.4 million on the sale which will be amortized against the lease payments over the lease term. Subject to certain conditions, we have options to purchase the rigs and related equipment from the lessors at the end of the 84^th month of the lease term at an agreed upon price or at the end of the lease term for its then fair market value.  Additionally, we have the option to renew the lease for a negotiated renewal term at a periodic rental equal to the fair market re ntal value of the rigs as determined at the time of renewal. In accordance with our accounting procedures, the portion of the lease payments that represent drilling costs for our working interest in wells are capitalized to the full cost pool.

On May 2, 2006, we sold our 25% partnership interest in NOARK to Atlas Pipeline Partners, L.P. for $69.0 million. As part of the transaction, we assumed and recorded $39.0 million of debt obligations of NOARK Pipeline

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Finance, L.L.C., which we had previously guaranteed as part of the financing of NOARK. At December 31, 2006, the balance of these debt obligations was $37.8 million.  We did not advance funds to NOARK in 2006 or 2005, and we did not derive any liquidity, capital resources, market risk support or credit risk support from our investment in NOARK.

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, 2006 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 (1)	$ 137,800	$    1,200	$  62,400	$   2,400	$   71,800
Interest on senior notes (2)	67,353	10,140	16,986	10,530	29,697
Operating leases (3)	21,475	4,905	8,588	5,234	2,748
Unconditional purchase    obligations (4)	-	-	-	-	-
Operating agreements (5)	127,014	61,928	60,766	4,320	-
Rental compression (6)	90,517	18,046	37,359	28,110	7,002
Demand charges (7)	125,225	21,663	41,796	30,085	31,681
Rig Leases (8)	156,671	19,584	39,168	39,168	58,751
Other obligations (9)	22,522	21,790	732	-	-
	$ 748,577	$ 159,256	$ 267,795	$  119,847	$ 201,679

⁽¹⁾

Debt includes $37.8 million of 7.15% Notes due 2018 and requires semi-annual principal payments of $0.6 million.

⁽²⁾ Interest on the senior notes includes interest through 2009 on the $60 million notes that are due in 2027 and putable at the holder’s option in 2009.

⁽³⁾ We lease certain office space and equipment under non-cancelable operating leases expiring through 2013.

⁽⁴⁾

Our Natural Gas Distribution 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, 2006 totaled 0.7 Bcf, comprised of 0.4 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.

⁽⁵⁾ Our E&P segment has commitments for up to $100.8 million in termination fees related to rig operator agreements and up to $3.7 million in termination fees related to rig servicing agreements in the event that the agreements are terminated.  Additionally, our E&P segment has secured rig moving services by committing monthly take-or-pay amounts of $938,000, expiring in December 2008.

⁽⁶⁾ Our E&P and Midstream Services segments have commitments for approximately $90.5 million of compressor rental fees associated primarily with our Fayetteville Shale play and our Overton operations.

⁽⁷⁾

Our Midstream Services segment has commitments for approximately $42.0 million of demand transportation charges related to the Fayetteville Shale play. Our Natural Gas Distribution segment has commitments for approximately $80.8 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 commitments for approximately $2.4 million of demand transportation charges.

⁽⁸⁾

Our E&P segment has commitments related to the leasing of fifteen drilling rigs through 2014.

⁽⁹⁾

Our other significant contractual obligations include approximately $13.1 million related to seismic services, approximately $4.1 million for funding of benefit plans and approximately $1.7 million for 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 liabilities for us or increase or accelerate our contingent liabilities. Substantially all of our employees are covered by defined benefit and postretirement benefit plans. Our return on the assets of these plans, when combined with other factors including an increase in employees, resulted in an increase in pension expense and our required funding of the plans for 2006 and 2005. At December 31, 2006, we recognized a liability of $13.8 million as a result of the underfunded status of our pension and other postretirement benefit plans.  We expect to record pension expense of $5.7 million and a postretirement benefit expense of $0.7 million in 2007. See Note 4 to the consolidated financial statements and “Critical Accounting Policies” below for additional information.

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On April 10, 2006, our Midstream Services unit entered into a three-year firm transportation agreement with Ozark Gas Transmission System to transport volumes increasing to 175,000 MMBtu per day in the later stages of the contract.  On August 22, 2006, we amended the agreement to increase the maximum volumes transported from 175,000 MMBtu per day to 220,000 MMBtu per day in the later stages of the contract. Additionally, on January 25, 2007 our Midstream Services unit entered into a separate two-year firm transportation agreement with Ozark Gas Transmission System to transport volumes of 50,000 MMBtu per day.

On December 15, 2006, one of our Midstream Services subsidiaries entered into a precedent agreement pursuant to which we will contract for firm gas transportation services on two newly-proposed pipeline laterals and related facilities of Texas Gas Transmission, LLC (Texas Gas), a subsidiary of Boardwalk Pipeline Partners, LP. We will be a “Foundation Shipper” for the project and will use the proposed laterals and related facilities primarily to deliver gas volumes produced from Southwestern’s operations in its Fayetteville Shale play in central Arkansas. Depending on regulatory approvals, the expected in-service date for both laterals is January 1, 2009. The first lateral line (Fayetteville Lateral) will originate in Conway County, Arkansas, and connect to Texas Gas’ mainline system in Coahoma County, Mississippi. The Fayetteville Lateral will be a minimum of 36” in diameter and would have an estimated ultimate capacity of up to 1 .1 Bcf per day. The second lateral (Greenville Lateral) will originate at the Texas Gas mainline system near Greenville, Mississippi, and extend eastward to interconnect with various interstate pipelines. The firm transportation agreements entered into by us pursuant to the precedent agreement will have an initial term of ten years and, over time, will enable us to transport up to 500,000 MMBtu per day on the Fayetteville Lateral and up to 400,000 MMBtu per day on the Greenville Lateral. We will also have the option to acquire up to 300,000 MMBtu per day of additional capacity on the Fayetteville Lateral and up to 240,000 MMBtu per day of additional capacity on the Greenville Lateral. Upon execution and delivery of the firm transportation agreements contemplated by the precedent agreement, our Midstream Services segment would have additional demand charges of $503.5 million that would be payable over the ten-year term of the agreements.

On December 29, 2006, we sold 13 of our existing drilling rigs and assigned our right to purchase two other drilling rigs to be delivered and related equipment to various financial institutions and leased the rigs from the buyers for an initial term of eight years from January 1, 2007 with aggregate rental payments of $19.6 million annually. We received proceeds of $127.3 million. This transaction was recorded as a sale and operating leaseback with an aggregate deferred gain of $7.4 million on the sale which will be amortized against the lease payments over the lease term. Subject to certain conditions, we have options to purchase the rigs and related equipment from the lessors at the end of the 84^th month of the lease term at an agreed upon price or at the end of the lease term for its then fair market value.  Additionally, we have the option to renew the lease for a negotiated renewal term at a periodic rental equal to the fair market re ntal value of the rigs as determined at the time of renewal. In accordance with our accounting procedures, the portion of the lease payments that represent drilling costs for our working interest in wells is capitalized to the full cost pool.

We are subject to litigation and claims that arise in the ordinary course of business. Management believes, individually or in aggregate, such litigation and claims will not have a material adverse impact on our financial position or our results of operations but these matters are subject to inherent uncertainties and management's view may change in the future. If an unfavorable final outcome were to occur, there exists the possibility of a material impact on our financial position and the results of operations for the period in which the effect becomes reasonably estimable.

A lawsuit was filed against us in 2001 alleging a breach of an agreement to indemnify the other party against settlement payments related to our Boure' prospect in Louisiana. The allegations were contested and, in 2002, we were granted a motion for summary judgment by the trial court. The case was appealed to the First Court of Appeals in Houston, Texas, which subsequently transferred the appeal to the Thirteenth Court of Appeals in Corpus Christi. The appeal was briefed and argued during 2003. On April 14, 2005, the Thirteenth Court of Appeals reversed the orders of the trial court and rendered judgment denying our motion for summary judgment and granting the motion for summary judgment of the other party.  Our motion for rehearing with the Thirteenth Court of Appeals was denied on May 19, 2005. In August of 2005, we filed a petition for review with the Texas Supreme Court.  In October of 2005, the Texas Supreme Cour t invited additional briefing by the parties.  In March of 2006, the Texas Supreme Court requested that both parties submit full briefing on the merits of the case.  After receiving full briefing from both sides, our petition for review with the Texas Supreme Court was denied on December 1, 2006, and the case has been remanded to the trial court for further disposition.  Should the other party prevail in the case, we could be required to pay approximately $2.1 million, plus pre-judgment interest and attorney's fees.  Based on an assessment of this litigation by us and our legal counsel, we accrued a loss in the fourth quarter of 2006.

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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 $55.0 million at the end of 2006 and positive working capital of $158.7 million at the end of 2005. Current assets at December 31, 2006 and 2005 included $42.0 and $222.4 million, respectively, of cash equivalents. The cash equivalents resulted from the proceeds of our drilling rig sale/leaseback in 2006 and from our equity offering in 2005, respectively. Current liabilities increased $76.5 million, due primarily to an increase in accounts payable related to our level of drilling activity, partially offset by a decrease in our current hedging liability at December 31, 2006.

CRITICAL ACCOUNTING POLICIES

Natural Gas and Oil Properties

We utilize the full cost method of accounting for costs related to the exploration, development and acquisition of oil and natural gas 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. These capitalized costs are subject to a ceiling test that 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 the 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 companie s 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.  However, commodity price increases subsequent to the end of a reporting period but prior to the release of periodic reports may be utilized to calculate the ceiling value of reserves. At December 31, 2006, 2005 and 2004, our unamortized costs of natural gas and oil properties did not exceed this ceiling amount. At December 31, 2006, our standardized measure was calculated based upon quoted market prices of $5.64 per Mcf for Henry Hub gas and $57.25 per barrel for West Texas Intermediate oil, adjusted for market differentials. The ceiling value calculated at December 31, 2006 includes approximately $135.2 million related to the positive effects of future cash flow hedges of gas production. At December 31, 2005, our standardized measure was calculated based upon quoted market prices of $10.08 per Mcf for Henry Hub gas and $61.04 per barrel for West Texas Intermediate oil, and 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. A decline in natural gas and oil prices from year-end 2006 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.

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. Natural gas pricing has historically been unpredictable and any 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 president of our E&P subsidiaries.  Final authority over the estimates of our proved reserves rests with our Board of Directors.  In each of the past three years, performance revisions to our proved reserve estimates rep resented no greater than 5% 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 65% of our total reserve base at December 31, 2006. 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 natura l gas and oil reserves and projecting future rates of production and timing of development expenditures

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as many factors are beyond our control.  We refer you to “Although our estimated natural gas and oil reserve data is independently audited, our estimates may still prove to be inaccurate.” in Item 1A, “Risk Factors,” of Part I of this Form 10-K for a more detailed discussion of these uncertainties, risks and other factors.

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 our Board of Directors.  In conducting its audit, the engineers and geologists of Netherland, Sewell & Associates study our major properties in detail and independently develop reserve estimates.  For the year-ended December 31, 2006, 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 95% 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, 2006 were $1,308.7 million and 1,026.3 Bcfe. An assumed decrease of $1.00 per Mcf in the December 31, 2006 gas price used to price our reserves would have resulted in an approximate $190 million decline in our future cash flows discounted at 10%, adjusted for the effects of commodity hedges, and an approximate decrease of 23 Bcfe of our reported reserves. Under this assumption, our unamortized costs would have exceeded the ceiling of proved natural gas and oil reserves. The decline in reserve quantities, assu ming this decrease in gas price, would have the impact of increasing 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 and capitalized costs.

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 60% 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, as amended by FAS 138 and FAS 149, and are recorded at fair value in our financial statements. We have established the fair value of derivative instruments using data provided by our counterparties in conjunction with assumptions 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 derivative not qualifying for hedge accounting treatment or any ineffective portion of a properly designated hedge is recognized immediately in ear nings. For the year ended December 31, 2006, we recorded a loss of $25.8 million related to basis differential swaps that did not qualify for hedge accounting which was partially offset by a $20.2 million gain related to the change in estimated ineffectiveness of our commodity cash flow hedges. We did not enter into any interest rate swaps in 2006, 2005 and 2004.  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 Item 7A of Part II of 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

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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.

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, 2006 benefit obligation and the periodic benefit cost to be recorded in 2007, the discount rate assumed is 6.0%. For the 2007 periodic benefit cost, the expected return assumed is 8.0%. This compares to a discount rate of 5.5% and an expected return of 8.25% used in 2006.  

Using the assumed rates discussed above, we recorded pension expense of $4.0 million in 2006 and $2.3 million in 2005 related to our pension and other postretirement benefit plans. With the adoption of FAS 158 in December 2006, we recognized a liability of $13.8 million at December 31, 2006, compared to $8.6 million at December 31, 2005 related to our pension and other postretirement benefit plans. During 2006, we also funded $3.8 million to our pension and other postretirement benefit plans. In 2007, we expect to fund $4.1 million to our pension and other postretirement benefit plans and recognize pension expense of $5.7 million and a postretirement benefit expense of $0.7 million. Assuming a 1% change in the 2006 rates (lower discount rate and lower rate of return), we would have recorded pension expense of $4.6 million in 2006.

On September 29, 2006, FAS 158 was issued requiring, among other things, the recognition of the funded status of each defined pension benefit plan, retiree health care and other postretirement benefit plans and postemployment benefit plans on the balance sheet.

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, assuming normal weather patterns, 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 9.6 Bcf at $3.89 per Mcf at December 31, 2006, compared to 8.5 Bcf at $3.78 per Mcf at December 31, 2005.

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 Natural Gas Distribution segment, especially during periods of colder weather. As a result, demand fees paid by the Natural 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 a write down of our gas in storage carrying cost.

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

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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 market conditions and prices for natural gas and oil (including regional basis differentials);

·

the timing and extent of our success in discovering, developing, producing and estimating reserves;

·

the economic viability of, and our success in drilling, our large acreage position in the Fayetteville Shale play, overall as well as relative to other productive shale gas plays;

·

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

·

the costs and availability of oilfield personnel services and drilling supplies, raw materials, and equipment and services, including pressure pumping equipment and crews in the Arkoma basin;

·

our ability to fund our planned capital investments;

·

our future property acquisition or divestiture activities;

·

the effects of weather;

·

increased competition;

·

the impact of federal, state and local government regulation;

·

the financial impact of accounting regulations and critical accounting policies;

·

the comparative cost of alternative fuels;

·

conditions in capital markets and changes in interest rates, and;

·

any other factors listed in the reports we have filed and may file with the SEC.

We caution you that forward-looking statements contained in this Form 10-K 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 Item 1A of Part I of this Form 10-K.

Estimates of our proved natural gas and oil reserves and the estimated future net revenues from such reserves are based upon various assumptions, including assumptions required by the SEC relating to natural gas and oil prices, drilling and operating expenses, capital investments, taxes and availability of funds. The process of estimating natural gas and oil

54 SWN

reserves is complex. This process requires significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir. Therefore, these estimates are inherently imprecise.

Actual future production, natural gas and oil prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable natural gas and oil reserves will most likely vary from those estimated. Such variances may be material. Any significant variance could materially affect the estimated quantities and present value of reserves set forth in this Form 10-K. Our properties may also be susceptible to hydrocarbon drainage from production by other operators on adjacent properties. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing natural gas and oil prices and other factors, many of which are beyond our control.

At December 31, 2006, approximately 35% of our estimated proved reserves were proved undeveloped and 5% were proved developed non-producing. Proved undeveloped reserves and proved developed non-producing reserves, by their nature, are less certain than proved developed producing reserves. Estimates of reserves in the non-producing categories are nearly always based on volumetric calculations rather than the performance data used to estimate producing reserves. Recovery of proved undeveloped reserves requires significant capital investments and successful drilling operations. Recovery of proved developed non-producing reserves requires capital investments to recomplete into the zones behind pipe and is subject to the risk of a successful recompletion. Production revenues from proved undeveloped and proved developed non-producing reserves will not be realized, if at all, until sometime in the future. The reserve data assumes that we will make significant capital investments to develop our reserves. Although we have prepared estimates of our natural gas and oil reserves and the costs associated with these reserves in accordance with industry standards, we cannot assure you that the estimated costs are accurate, that development will occur as scheduled or that the actual results will be as estimated.

You should not assume that the present value of future net cash flows referred to in this Form 10-K is the current fair value of our estimated natural gas and oil reserves. In accordance with SEC requirements, the estimated discounted future net cash flows from proved reserves are generally based on prices and costs as of the date of the estimate. Actual future prices and costs may be materially higher or lower than the prices and costs as of the date of the estimate. Any changes in consumption by gas purchasers or in governmental regulations or taxation could also affect actual future net cash flows. The timing of both the production and the expenses from the development and production of natural gas and oil properties will affect the timing of actual future net cash flows from proved reserves and their present value. In addition, the 10% discount factor, which is required by the SEC to be used in calculating discounted fut ure net cash flows for reporting purposes, is not necessarily the most accurate discount factor for our company.

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 Risk

Our financial instruments that are exposed to concentrations of credit risk consist primarily of trade receivables and derivative contracts associated with commodities hedging. Concentrations of credit risk with respect to receivables are limited due to the large number of our customers and their dispersion across geographic areas. No single customer accounted for greater than 4% of accounts receivable at December 31, 2006.  In addition, please see the discussion of credit risk associated with commodities hedging below.

Interest Rate Risk

The following table provides information on our financial instruments that are sensitive to changes in interest rates. The table presents the principal cash payments for our debt obligations and related weighted-average interest rates by expected maturity dates. At December 31, 2006, we had no borrowings outstanding under our revolving 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
	2007	2008	2009	2010	2011	Thereafter	Total	12/31/06
	($ in millions)
Fixed Rate	$ 1.2	$ 1.2	$ 61.2	$ 1.2	$ 1.2	$ 71.8	$ 137.8	$ 141.7
Average Interest Rate	7.15%	7.15%	7.62%	7.15%	7.15%	7.18%	7.37%	-

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 p rice 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, 2006, the fair value of these financial instruments was a $58.1 million asset.

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Production and Marketing

	Volume	Weighted Average Price to be Swapped ($)	Weighted Average Floor Price ($)	Weighted Average Ceiling Price ($)	Weighted Average Basis Differential ($)	Fair Value at Dec 31, 2006 ($ in millions)
Natural Gas (Bcf):
Fixed Price Swaps:
2007	32.5	7.83	-	-	-	27.3
2008	13.0	8.78	-	-	-	8.2
Floating Price Swaps:
2007	0.2	(7.61)	-	-	-	(0.4)
2008	-	-	-	-	-	-
Costless Collars:
2007	34.0	-	6.93	12.34	-	26.0
2008	22.0	-	7.92	13.15	-	14.0
Basis Swaps:
2007	31.9	-	-	-	(0.53)	(4.1)
2008	30.1	-	-	-	(0.48)	(2.6)
Matched-Basis Swaps:
2007	32.4	-	-	-	(0.47)	(0.9)
2008	8.0	-	-	-	(0.73)	(1.3)
Regulatory Swaps:
2007	3.1	(8.83)	-	-	-	(8.1)
2008	-	-	-	-	-	-

At December 31, 2006, we had outstanding fixed-price basis differential swaps on 32.4 Bcf of 2007, and 8.0 Bcf of 2008 gas production that qualified for hedge accounting treatment.  At December 31, 2006, we also had outstanding fixed-price basis differential swaps on 31.9 Bcf of 2007 and 30.1 Bcf of 2008 gas production that did not qualify for hedge accounting treatment.  For the year ended December 31, 2006, we recorded a loss of $25.8 million related to the differential swaps that did not qualify for hedge accounting treatment which was partially offset by a $20.2 million gain related to the change in estimated ineffectiveness of our cash flow hedges.  

At December 31, 2005, we had outstanding fixed-price basis differential swaps on 13.0 Bcf of 2006, 29.9 Bcf of 2007 and 2.0 Bcf of 2008 gas production that qualified for hedge accounting treatment.  At December 31, 2005, we had outstanding fixed-price basis differential swaps on 25.3 Bcf of 2006 and 10.0 Bcf of 2007 gas production that did not qualify for hedge accounting treatment.  For the year ended December 31, 2005, we recorded a gain of $19.1 million related to the differential swaps that did not qualify for hedge accounting treatment which was partially offset by a $9.4 million loss related to the change in estimated ineffectiveness of our cash flow hedges.

At December 31, 2005, we had outstanding natural gas price swaps on total notional volumes of 7.9 Bcf at a weighted average price of $6.64 per Mcf of 2006 gas production and 12.0 Bcf at a weighted average price of $6.66 per Mcf of 2007 gas production. Outstanding oil price swaps at December 31, 2005 on 120 MBbls were yielding us an average price of $37.30 per barrel during 2006. At December 31, 2005, we also had outstanding natural gas price swaps on total notional gas purchase volumes of 0.7 Bcf in 2006 for which we paid an average fixed price of $13.03 per Mcf.

At December 31, 2005, we had collars in place on 43.0 Bcf in 2006, 28.0 Bcf in 2007 and 2.0 in 2008 of gas production. The collars relating to 2006 production had a weighted average floor and ceiling price of $5.47 and $10.13 per Mcf, respectively. The collars relating to 2007 production have a weighted average floor and ceiling price of $6.64 and $11.19 per Mcf, respectively. The collars relating to 2008 production have a weighted average floor and ceiling price of $8.00 and $19.40 per Mcf, respectively.

Subsequent to December 31, 2006 and prior to February 23, 2007, we hedged 12.5 Bcf of 2007, 11.0 Bcf of 2008 and 4.0 Bcf of 2009 gas production under fixed price swaps with a sales price ranging from $7.29 to $8.62. Additionally, we hedged 2.0 Bcf of 2007, 11.0 Bcf of 2008 and 4.0 Bcf of 2009 gas production under costless collars with floor prices ranging from $7.25 to $8.50 per Mcf and ceiling prices ranging from $9.07 to $10.95 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	59
Report of Independent Registered Public Accounting Firm	59
Statements of Operations for the years ended December 31, 2006, 2005 and 2004	61
Balance Sheets as of December 31, 2006 and 2005	62
Statements of Cash Flows for the years ended December 31, 2006, 2005 and 2004	63
Statements of Changes in Stockholders’ Equity and Comprehensive Income (Loss) for the years ended December 31, 2006, 2005 and 2004	64
Notes to Consolidated Financial Statements, December 31, 2006, 2005 and 2004	66

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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, 2006.  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, 2006, 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, 2006 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 Stockholders of

Southwestern Energy Company:

We have completed integrated audits of Southwestern Energy Company’sconsolidated financial statements and of its internal control over financial reporting as of December 31, 2006, 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 at December 31, 2006 and 2005, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2006 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 misst atement.  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.

Internal control over financial reporting

Also, in our opinion, management’s assessment, included in Management's Report on Internal Control Over Financial Reporting appearing in Item 8, that the Company maintained effective internal control over financial reporting as of December 31, 2006 based 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, 2006, 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 financial reporting and for its assessment of the effectiveness of internal control over financial r eporting.  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

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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 assura nce regarding prevention or timely 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.

/s/ PricewaterhouseCoopers LLP

PricewaterhouseCoopers LLP

Tulsa, Oklahoma

February 28, 2007

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STATEMENTS OF OPERATIONS

Southwestern Energy Company and Subsidiaries

	For the years ended December 31,
	2006		2005		2004
	(in thousands, except share/per share amounts)
Operating revenues:
Gas sales	$	572,354	$	503,111	$	375,460
Gas marketing		136,698		132,690		65,127
Oil sales		40,742		30,026		19,461
Gas transportation and other		13,318		10,502		17,089
		763,112		676,329		477,137
Operating costs and expenses:
Gas purchases - midstream services		128,387		124,730		60,804
Gas purchases - gas distribution		79,363		82,689		64,311
Operating expenses		66,579		52,850		42,157
General and administrative expenses		66,112		48,650		36,074
Depreciation, depletion, and amortization		151,290		96,211		73,674
Taxes, other than income taxes		25,109		25,279		17,830
		516,840		430,409		294,850
Operating income		246,272		245,920		182,287
Interest expense:
Interest on long-term debt		11,099		19,791		18,335
Other interest charges		1,402		1,254		1,461
Interest capitalized		(11,822)		(6,005)		(2,804)
		679		15,040		16,992
Other income (expense)		17,079		4,784		(362)
Income before income taxes and minority interest		262,672		235,664		164,933
Minority interest in partnership		(637)		(1,473)		(1,579)
Income before income taxes		262,035		234,191		163,354
Provision for income taxes:
Current		-		-		-
Deferred		99,399		86,431		59,778
		99,399		86,431		59,778
Net income	$	162,636	$	147,760	$	103,576
Basic earnings per share (1)		$0.97		$0.98		$0.72
Diluted earnings per share (1)		$0.95		$0.95		$0.70
Weighted average common shares outstanding: (1)
Basic		167,303,141		150,892,602		142,902,404
Effect of:
Stock options		3,476,701		4,512,564		4,060,404
Restricted stock awards		507,908		903,873		888,280
Diluted		171,287,750		156,309,039		147,851,088

⁽¹⁾

2004 restated to reflect two-for-one stock splits effected in June and November 2005.

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

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BALANCE SHEETS

Southwestern Energy Company and Subsidiaries

	December 31,
	2006		2005
	(in thousands)
ASSETS
Current assets
Cash and cash equivalents	$	42,927	$	223,705
Accounts receivable		131,370		128,948
Inventories, at average cost		62,488		49,513
Deferred income tax benefit		-		29,700
Hedging asset - FAS 133		64,082		17,467
Other		22,969		11,731
Total current assets		323,836		461,064
Investments		-		17,100
Property, plant and equipment, at cost
Gas and oil properties, using the full cost method, including $166,826,844
in 2006 and $122,300,659 in 2005 excluded from amortization		2,651,427		1,897,613
Gas distribution systems		226,067		216,644
Construction-in-progress  - drilling rigs		- -		35,128
Gathering systems		51,836		15,742
Gas in underground storage		32,254		32,254
Other		77,702		45,234
		3,039,286		2,242,615
Less: Accumulated depreciation, depletion and amortization		1,022,786		872,218
		2,016,500		1,370,397
Other assets		38,733		19,963
	$	2,379,069	$	1,868,524
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities
Current portion of long-term debt	$	1,200	$	-
Accounts payable		266,023		154,385
Taxes payable		16,088		14,519
Advances from partners and customer deposits		31,941		7,624
Hedging liability - FAS 133		23,864		112,293
Over-recovered purchased gas costs		10,580		7,323
Current deferred income taxes		19,162		-
Other		10,002		6,242
Total current liabilities		378,860		302,386
Long-term debt		136,600		100,000
Other liabilities
Deferred income taxes		370,522		254,528
Long-term hedging liability		4,902		60,442
Pension liability		11,697		7,902
Other		30,811		21,349
		417,932		344,221
Commitments and contingencies
Minority interest in partnership		11,034		11,613
Stockholders' equity
Common stock, $0.01 par value in 2006, $0.10 par value in 2005; authorized
540,000,000 shares in 2006 and 220,000,000 shares in 2005, issued
168,953,893 in 2006 and 168,452,336 in 2005		1,690		16,845
Additional paid-in capital		740,609		711,196
Retained earnings		660,857		498,221
Accumulated other comprehensive income (loss)		31,487		(104,874)
Common stock in treasury, at cost, 1,217,284 shares in 2005		- -		(3,390)
Unamortized cost of restricted shares issued under stock incentive
plan, 707,142 shares in 2005		- -		(7,694)
		1,434,643		1,110,304
	$	2,379,069	$	1,868,524

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

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STATEMENTS OF CASH FLOWS

Southwestern Energy Company and Subsidiaries

	For the years ended December 31,
	2006		2005		2004
	(in thousands)
Cash flows from operating activities
Net income	$	162,636	$	147,760	$	103,576
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		152,519		97,652		75,377
Deferred income taxes		99,399		86,431		59,778
Unrealized (gain) loss on derivatives		5,579		(9,666)		2,639
Stock-based compensation expense		5,164		1,906		1,973
Equity in (income) loss of NOARK partnership		(925)		(1,635)		433
Gain on sale of investment in partnership and other property		(10,285)		(445)		(5,802)
Minority interest in partnership		(579)		(245)		(268)
Change in assets and liabilities:
Accounts receivable		(2,422)		(42,680)		(27,725)
Inventories		(12,975)		(17,265)		(2,741)
Under/over-recovered purchased gas costs		3,258		5,911		2,519
Accounts payable		20,742		32,837		26,052
Advances from partners and customer deposits		24,317		1,513		(653)
Other assets and liabilities		(16,491)		2,408		2,739
Net cash provided by operating activities		429,937		304,482		237,897
Cash flows from investing activities
Capital expenditures		(850,910)		(453,859)		(291,101)
Investment in NOARK partnership		-		-		(2,059)
Proceeds from sale/leaseback of drilling rigs		127,288		-		-
Proceeds from sale of investment in partnership and other property		92,465		1,519		7,121
Other items		1,151		(578)		591
Net cash used in investing activities		(630,006)		(452,918)		(285,448)
Cash flows from financing activities
Issuance of common stock		-		579,956		-
Debt retirement		(1,200)		(125,000)		-
Payments on revolving long-term debt		(267,700)		(563,800)		(395,100)
Borrowings under revolving long-term debt		267,700		463,800		441,300
Debt issuance costs		-		(1,180)		(1,514)
Excess tax benefit for stock-based compensation		14,609		-		-
Change in bank drafts outstanding		2,009		11,860		(2,347)
Proceeds from exercise of common stock options		3,873		5,270		5,170
Net cash provided by financing activities		19,291		370,906		47,509
Increase (decrease) in cash and cash equivalents		(180,778)		222,470		(42)
Cash and cash equivalents at beginning of year		223,705		1,235		1,277
Cash and cash equivalents at end of year	$	42,927	$	223,705	$	1,235

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

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

Southwestern Energy Company and Subsidiaries

	Common Stock(1)			Additional Paid-In Capital(1)		Retained Earnings		Accumulated Other Comprehensive Income (Loss)		Common Stock in Treasury		Unamortized Restricted Stock Awards		Total
	Shares Issued	Amount
	(in thousands)
Balance at December 31, 2003	148,902	$	14,890	$	112,352	$	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	-		-		-		-		-		-		1,972		1,972
Balance at December 31, 2004	148,902	$	14,890	$	117,586	$	350,461	$	(19,816)	$	(9,156)	$	(6,288)	$	447,677
Comprehensive income: Net income	-		-		-		147,760		-		-		-		147,760
Change in value of derivatives	-		-		-		-		(81,044)		-		-		(81,044)
Change in value of pension liability	-		-		-		-		(4,014)		-		-		(4,014)
Total comprehensive income	-		-		-		-		-		-		-		62,702
Issuance of common stock	19,550		1,955		578,001		-		-		-		-		579,956
Exercise of stock options	-		-		11,821		-		-		5,526		-		17,347
Issuance of restricted stock	-		-		3,909		-		-		368		(4,277)		-
Cancellation of restricted stock	-		-		(121)		-		-		(128)		249		-
Amortization of restricted stock	-		-		-		-		-		-		2,622		2,622
Balance at December 31, 2005	168,452	$	16,845	$	711,196	$	498,221	$	(104,874)	$	(3,390)	$	(7,694)	$	1,110,304
Comprehensive income: Net income	-		-		-		162,636		-		-		-		162,636
Change in value of derivatives	-		-		-		-		141,230		-		-		141,230
Change in value of pension liability	-		-		-		-		2,372		-		-		2,372
Total comprehensive income	-		-		-		-		-		-		-		306,238
Adoption of FAS 158	-		-		-		-		(7,241)		-		-		(7,241)
Adoption of FAS 123(R)	-		-		(7,694)		-		-		-		7,694		-
Tax benefit for stock-based compensation	-		-		14,609		-		-		-		-		14,609
Stock-based compensation - FAS123(R)	-		-		6,857		-		-		3		-		6,860
Common stock par value adjustment	-		(15,160)		15,160		-		-		-		-		-
Exercise of stock options	494		5		927		-		-		2,941		-		3,873
Issuance of restricted stock	8		-		(513)		-		-		513		-		-
Cancellation of restricted stock	-		-		67		-		-		(67)		-		-
Balance at December 31, 2006	168,954	$	1,690	$	740,609	$	660,857	$	31,487	$	-	$	-	$	1,434,643

⁽¹⁾ 2003 and 2004 restated to reflect the two-for-one stock splits effected on June 3, 2005 and November 17, 2005.

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

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STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY AND COMPREHENSIVE INCOME (LOSS)

Southwestern Energy Company and Subsidiaries

RECONCILIATION OF ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

	For the years ended December 31,
	2006		2005		2004
	(in thousands)
Balance, beginning of year	$	(104,874)	$	(19,816)	$	(12,520)
Current period reclassification to earnings		(2,326)		67,481		21,119
Current period ineffectiveness		(12,726)		5,969		1,006
Current period change in derivative instruments		156,282		(154,494)		(28,922)
Current period change in pension liability		(4,082)		(4,014)		(499)
Current period change in other postretirement benefit liability		(787)		-		-
Balance, end of year	$	31,487	$	(104,874)	$	(19,816)

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Southwestern Energy Company and Subsidiaries

December 31, 2006, 2005 and 2004

(1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Nature of Operations and Consolidation

Southwestern Energy Company (Southwestern or the Company) is an independent 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 (E&P) activities are concentrated in Arkansas, Texas, New Mexico and Oklahoma. Southwestern’s marketing and gas gathering business (Midstream Services) is concentrated in its core areas of operations. The Natural Gas Distribution segment operates in northern Arkansas and its customers consist of residential, commercial and industrial users of natural gas.

The consolidated financial statements include the accounts of Southwestern and its wholly-owned subsidiaries, including Southwestern Energy Production Company (SEPCO), SEECO, Inc., Arkansas Western Gas Company, Southwestern Midstream Services Company (SMS), Diamond “M” Production Company and A.W. Realty Company. The consolidated financial statements also include the results for (i) Overton Partners, L.P., of which SEPCO is the sole general partner, (ii) DeSoto Drilling Inc., (iii) Angelina Gathering Company, L.L.C., and (iv) DeSoto Gathering Company, L.L.C. All significant intercompany accounts and transactions have been eliminated. Prior to the sale of its interest, the Company accounted 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 Reg ulation,” 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.

Effective June 30, 2006, Southwestern Energy Company reincorporated from Arkansas to Delaware. As a result of the reincorporation, the par value of the Company’s common stock changed to $0.01 per share. The reincorporation did not result in any change in the Company’s business, management, employees, fiscal year, assets or liabilities.

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, 2006, the estimated fair value of the minority ownership position of the partnership does not exceed the minority interest of $11.0 million r eflected in the accompanying balance sheet.

Rig Sale/Leaseback

On December 29, 2006, the Company sold 13 of its existing drilling rigs and assigned its right to purchase two other drilling rigs to be delivered and related equipment to various financial institutions and leased the rigs from the buyers for an initial term of eight years from January 1, 2007 with aggregate rental payments of $19.6 million annually. The Company received proceeds of $127.3 million. This transaction was recorded as a sale and operating leaseback with an aggregate deferred gain of $7.4 million on the sale which will be amortized against the lease payments over the lease term. Subject to certain conditions, the Company has options to purchase the rigs and related equipment from the lessors at the end of the 84^th month of the lease term at an agreed upon price or at the end of the lease term for its then fair market value.  Additionally, the Company has the option to renew the lease for a negotiated renewal term at a periodic rental equal to the fair market rental value of the rigs as determined at the time of renewal. In accordance with the Company’s accounting

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procedures, the portion of the lease payments that represent drilling costs for its working interest in wells is capitalized to the full cost pool.

Property, Depreciation, Depletion and Amortization

Gas and Oil Properties. The Company utilizes the full cost method of accounting for costs related to the exploration, development and acquisition of oil and natural gas 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. These capitalized costs are subject to a ceiling test that 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 the 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. However, commodity price increases subsequent to the end of a reporting period but prior to the release of periodic reports may be utilized to calculate the ceiling value of reserves. At December 31, 2006, 2005 and 2004, the Company’s unamortized costs of natural gas and oil properties did not exceed this ceiling amount. At December 31, 2006, the Company’s standardized measure was calculated based upon quoted market prices of $5.64 per Mcf for Henry Hub gas and $57.25 per barrel for West Texas Intermediate oil, adjusted for market differentials, and included approximately $135.2 million related to the positive effects of future cash flow hedges of gas production. At December 31, 2005, the Company’s standardized measure was calculated based upon quoted market prices of $10.08 pe r Mcf for Henry Hub gas and $61.04 per barrel for West Texas Intermediate oil, and at December 31, 2004, the 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. A decline in natural gas and oil prices from year-end 2006 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.

Gathering Systems. The Company’s investment in gathering systems is primarily related to its Fayetteville Shale play in Arkansas.  These assets are being depreciated on a straight-line basis over 25 years.

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 1.2% to 4.2%.

Other property, plant and equipment is depreciated using the straight-line method over estimated useful lives ranging from 7 to 24 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.

Construction-in-Progress – Drilling Rigs. In 2005, the Company entered into agreements to fabricate ten new land drilling rigs which were in process at December 31, 2005.  These rigs were included in the December 2006 rig sale/leaseback transaction discussed above.

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 Natural 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, investments in gathering systems until these assets are placed in service and on drilling rigs during their construction phase. 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.  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 requires that the fair value

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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 following table summarizes the Company’s 2006 and 2005 activity related to asset retirement obligations:

	2006		2005
	(in thousands)
Asset retirement obligation at January 1	$	9,229	$	8,565
Accretion of discount		401		326
Obligations incurred		1,152		436
Obligations settled		(645)		(1,553)
Revisions of estimates		408		1,455
Asset retirement obligation at December 31	$	10,545	$	9,229
Current liability		593		358
Long-term liability		9,952		8,871
Total asset retirement obligation at December 31	$	10,545	$	9,229

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 fourth quarter of 2005, the gas distribution subsidiary received regulatory approval from the Arkansas Public Service Commission (APSC) of a rate increase totaling $4.6 million annually, exclusive of costs to be recovered through the utility’s purchase gas adjustment clause. The rate increase was effective for deliveries made to customers on or after October 31, 2005.

Gas Production Revenue and Imbalances

The E&P 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, 2006, the Company had overproduction of 1.2 Bcf valued at $3.5 million and underproduction of 1.5 Bcf valued at $4.4 million. At December 31, 2005, the Company had overproduction of 1.2 Bcf valued at $3.6 million and underproduction of 1.4 Bcf valued at $4.1 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, 2006 was $328.6 million with expiration dates in 2020 through 2026.

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 speculative 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

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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 comprehensive income (loss) to the extent that they are effective in offsetting the changes in the cash flows of the hedged item.  In contrast, gains and losses from the ineffective portion of swap agreements and options as well as those that do not qualify for hedge accounting treatment 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 the year ended December 31, 2006, 5,351,809 of the Company’s outstanding options with an average exercise price of $3.57 were included in the calculation of diluted shares.  Options for 440,431 shares were excluded from the calculation because they would have had an antidilutive effect.  All of the Company’s 7,126,465 outstanding options at December 31, 2005 with a weighted average exercise price of $4.34 were included in the calculation of diluted shares.  In addition, all of the Company& #146;s 8,884,512 outstanding options at December 31, 2004 with a weighted average exercise price of $3.18 were included in the calculation of diluted shares.

For the year ended December 31, 2006, the number of restricted stock shares included in the calculation of diluted shares was 310,617.  Restricted shares of 168,115 were excluded from the calculation because they would have had an antidilutive effect.  All of the Company’s 707,142 and 1,281,031 non-vested restricted stock shares for 2005 and 2004, respectively were included in the calculation. The number of options, options prices, and the number of restricted shares for 2004 reflect the two-for-one stock splits effected in each of the second and fourth quarters of 2005.

Accounting for Stock-Based Compensation

In December 2004, the FASB issued Statement on Financial Accounting Standards No. 123R “Share-Based Payment” (FAS 123R). FAS 123R requires that companies recognize compensation expense equal to the fair value of stock options or other share based payments. We adopted this standard during the year ended December 31, 2006 using the modified prospective method. See Note 9 of our consolidated financial statements for a description of the impact of this standard on our financial statements.

Accounting for Defined Benefit Pension and Other Postretirement Plans

In September 2006, Statement of Financial Accounting Standards No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans” (FAS 158) was issued. FAS 158 requires, among other things, the recognition of the funded status of each defined pension benefit plan, retiree health care and other postretirement benefit plans and postemployment benefit plans on the balance sheet. We adopted FAS 158 as of December 31, 2006. See Note 4 for additional information.

 (2) DEBT

Debt balances as of December 31, 2006 and 2005 consisted of the following:

	2006		2005
	(in thousands)
Current portion of long-term debt:
7.15% Senior Notes due 2018	$	1,200	$	-
Long-term:
7.625% Senior Notes due 2027, putable at the holders' option in 2009	$	60,000	$	60,000
7.21% Senior Notes due 2017		40,000		40,000
7.15% Senior Notes due 2018		36,600		-
Total long-term debt		136,600		100,000
Total debt	$	137,800	$	100,000

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In February 2007, the Company amended its unsecured revolving credit facility increasing the borrowing capacity to $750 million, lowering the borrowing cost and extending the maturity date to 2012. The amount available under the revolving credit facility may be increased to $1 billion at any time upon the Company’s agreement with its existing or additional lenders. The Company had no indebtedness outstanding under its revolving credit facility at December 31, 2006 and December 31, 2005. The interest rate on the amended credit facility is calculated based upon our debt rating and is currently 87.5 basis points over the current London Interbank Offered Rate (LIBOR). The Credit Facility is guaranteed by the Company’s subsidiaries, Southwestern Energy Production Company, SEECO, Inc. and Southwestern Energy Services Company. The Credit Facility requires additional subsidiary guarantors if certain guaranty coverage levels are not satisfied. 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 stockholders' 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, 2006, the Company’s capital structure consisted of 9% debt and 91% equity and it was in compliance with the covenants of its debt agreements.

The 7.15% senior notes were assumed in 2006 upon the sale of the Company’s general partnership interest in NOARK.  The Company had previously guaranteed the notes.

The 7.625% senior notes are putable at the holders’ option in 2009. Other than the 7.625% senior notes, aggregate maturities of long-term debt for each of the years ending December 31, 2007 through 2011 are $1.2 million per year for the 7.15% senior notes. Total interest payments were $10.8 million in 2006, $20.3 million in 2005 and $18.3 million in 2004.

(3) INCOME TAXES

The provision for income taxes included the following components:

	2006		2005		2004
	(in thousands)
Federal:
Current	$	-	$	-	$	-
Deferred		90,186		79,845		55,995
State:
Current		-		-		-
Deferred		9,320		6,698		3,899
Investment tax credit amortization		(107)		(112)		(116)
Provision for income taxes	$	99,399	$	86,431	$	59,778

The provision for income taxes was an effective rate of 37.9% in 2006, 36.9% in 2005 and 36.6% in 2004. 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:

	2006		2005		2004
	(in thousands)
Expected provision at federal statutory rate of 35%	$	91,712	$	81,967	$	57,174
Increase resulting from: State income taxes, net of federal income tax effect		6,058		4,354		2,534
Other		1,629		110		70
Provision for income taxes	$	99,399	$	86,431	$	59,778

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The components of the Company’s net deferred tax liability as of December 31, 2006 and 2005 were as follows:

	2006		2005
	(in thousands)
Deferred tax liabilities:
Differences between book and tax basis of property	$	500,386	$	330,465
Stored gas		4,558		6,343
Book over tax basis in partnerships		-		12,883
Cash flow hedges - FAS 133		24,906		-
Other		7,470		8,963
		537,320		358,654
Deferred tax assets:
Accrued compensation	$	6,795	$	2,753
Alternative minimum tax credit carryforward		3,026		3,026
Accrued pension costs		3,702		2,946
Book over tax basis in partnerships		1,247		-
Cash flow hedges - FAS 133		-		58,621
Asset retirement obligations - FAS 143		3,728		3,390
Net operating loss carryforward		125,438		63,369
Other		4,322		451
		148,258		134,556
Net deferred tax liability	$	389,062	$	224,098

The net deferred tax liability at December 31, 2006 consisted of a current deferred income tax liability of $19.2 million and long-term deferred income tax liabilities of $370.5 million including unamortized deferred investment tax credits of $0.6 million.  In 2006, the Company paid $6,000 in income taxes. There were no income tax payments in 2005 and 2004. The Company's net operating loss carryforward at December 31, 2006, was $328.6 million with expiration dates in 2020 through 2026. The Company also had an alternative minimum tax credit carryforward of $3.0 million and a statutory depletion carryforward of $7.6 million at December 31, 2006.

(4) PENSION PLAN AND OTHER POSTRETIREMENT BENEFITS

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 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.

On September 29, 2006, FAS 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans” was issued. FAS 158 requires, among other things, the recognition of the funded status of each defined pension benefit plan, retiree health care and other postretirement benefit plans and postemployment benefit plans on the balance sheet. Each overfunded plan is recognized as an asset and each underfunded plan is recognized as a liability. The initial impact of the standard due to unrecognized prior service costs or credits and net actuarial gains or losses as well as subsequent changes in the funded status is recognized as a component of accumulated comprehensive loss in stockholders’ equity. Additional minimum pension liabilities (AML) and related intangible assets are also derecognized upon adoption of the new standard. FAS 158 requires initial application for fiscal years ending after December 15, 2006 and wa s adopted by the Company as of December 31, 2006. The following table summarizes the effect of required changes as of December 31, 2006 prior to the adoption of FAS 158 as well as the impact of the initial adoption of FAS 158 as it relates to our pension plans.

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	December 31, 2006 Prior to AML and FAS 158 Adjustments	AML Adjustment	December 31, 2006 Prior to FAS 158	FAS 158 Adjustment	December 31, 2006 Post AML and FAS 158 Adjustment
			(in thousands)
Other assets	$    6,156	$   (3,436)	$    2,720	$   (2,720)	$           -
Deferred tax asset	2,946	(1,393)	1,553	3,785	5,338
Pension liability	(11,381)	7,201	(4,180)	(7,517)	(11,697)
Accumulated other comprehensive income, net of tax	5,017	(2,372)	2,645	6,452	9,097

The amounts in accumulated other comprehensive loss that are expected to be recognized as components of net periodic benefit cost (credit) during the next fiscal year are $0.5 million for prior service costs and a $0.4 million net loss.

In addition to the $7.5 million pension liability adjustment recognized at December 31, 2006 for the Company’s pension obligation, FAS 158 also required the Company to recognize an additional liability of $1.2 million related to its postretirement benefit obligation at December 31, 2006, resulting in a $0.8 million after-tax adjustment to other comprehensive income (loss). The amount in accumulated other comprehensive income (loss) that is expected to be recognized as a component of net transition obligation/(asset) and net loss/(gain)for 2007 is $0.1 million.

The following provides a reconciliation of the changes in the plans’ benefit obligations, fair value of assets, and funded status as of December 31, 2006 and 2005:

	Pension Benefits				Other Postretirement Benefits
	2006		2005		2006		2005
	(in thousands)
Change in benefit obligations:
Benefit obligation at January 1	$	71,854	$	63,800	$	4,022	$	4,504
Service cost		3,011		2,523		271		172
Interest cost		3,881		3,764		189		201
Participant contributions		-		-		116		116
Actuarial loss/(gain)		(2,588)		4,824		(578)		(693)
Benefits paid		(5,683)		(3,057)		(326)		(278)
Plan amendments		388		-		-		-
Benefit obligation at December 31	$	70,863	$	71,854	$	3,694	$	4,022

	Pension Benefits				Other Postretirement Benefits
	2006		2005		2006		2005
	(in thousands)
Change in plan assets:
Fair value of plan assets at January 1	$	55,932	$	54,165	$	1,379	$	1,114
Actual return on plan assets		5,504		3,020		94		(19)
Employer contributions		3,413		1,804		354		446
Participant contributions		-		- -		116		116
Benefit payments		(5,683)		(3,057)		(326)		(278)
Fair value of plan assets at December 31	$	59,166	$	55,932	$	1,617	$	1,379
Funded status:
Funded status at December 31	$	(11,697)	$	(15,922)	$	(2,078)	$	(2,643)
Unrecognized net actuarial loss		-		16,073		-		1,371
Unrecognized prior service cost		-		2,726		-		-
Unrecognized transition obligation		-		-		-		602
Net amount recognized	$	(11,697)	$	2,877	$	(2,078)	$	(670)

The Company uses a December 31 measurement date for all of its plans. As a result of the application of FAS 158, the Company recorded liabilities of $13.8 million on the balance sheet related to its pension and other postretirement benefit plans. This amount represents the difference between the fair value of the plans’ assets and projected benefit obligations for the pension liability, and the difference between the fair value of the plans’ assets and accumulated postretirement benefit obligations for the postretirement benefits liability. The Company also recorded an after-tax loss of $7.2 million to other comprehensive income (loss) to reflect unrecognized gains and losses resulting from changes in assumptions and prior service costs.

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The change in accumulated other comprehensive loss related to the pension plans was a loss of $6.5 million ($4.1 million after tax) for the year ended December 31, 2006 and a loss of $6.4 million ($4.0 million after tax) for the year ended December 31, 2005. The change in accumulated other comprehensive loss related to the other postretirement benefit plans was a loss of $1.2 million ($0.8 million after tax) for the year ended December 31, 2006. Included in accumulated other comprehensive loss at December 31, 2006 and 2005 was a $15.7 million loss ($9.9 million net of tax) and an $8.0 million loss ($5.1 million net of tax), respectively, related to the Company’s pension and other postretirement benefit plans.

The Company’s pension plans have an accumulated benefit obligation in excess of plan assets as of December 31, 2006 and 2005 as follows:

	2006	2005
	(in thousands)
Projected benefit obligation	$70,863	$71,854
Accumulated benefit obligation	63,347	63,834
Fair value of plan assets	59,166	55,932

Net periodic pension and other postretirement benefit costs include the following components for 2006, 2005 and 2004:

	Pension Benefits						Other Postretirement Benefits
	2006		2005		2004		2006		2005		2004
	(in thousands)
Service cost	$	3,011	$	2,523	$	2,404	$	271	$	172	$	174
Interest cost		3,881		3,764		3,692		189		201		252
Expected return on plan assets		(4,578)		(4,776)		(4,543)		(69)		(56)		(42)
Amortization of transition obligation		-		-		-		86		86		86
Recognized net actuarial loss		759		326		233		34		41		102
Amortization of prior service cost		436		440		444		-		-		-
	$	3,509	$	2,277	$	2,230	$	511	$	444	$	572

The weighted average assumptions used in the measurement of the Company’s benefit obligations at December 31, 2006 and 2005 are as follows:

	Pension Benefits		Other Postretirement Benefits
	2006	2005	2006	2005
Discount rate	6.00%	5.50%	6.00%	5.50%
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 2006, 2005 and 2004 are as follows:

		Pension Benefits			Other Postretirement Benefits
	2006	2005	2004	2006	2005	2004
Discount rate	5.50%	6.00%	6.25%	5.50%	6.00%	6.25%
Expected return on plan assets	8.25%	9.00%	9.00%	5.00%	5.00%	5.00%
Rate of compensation increase	4.00%	4.00%	4.00%	n/a	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 2006 and 2005:

	2006	2005
Health care cost trend assumed for next year	9%	10%
Rate to which the cost trend is assumed to decline	5%	5%
Year that the rate reaches the ultimate trend rate	2012	2011

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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	$   58	$   (50)
Effect on postretirement benefit obligation	$ 395	$ (345)

The Company’s pension plan weighted-average asset allocations at December 31, 2006 and 2005, by asset category, are as follows:

	2006	2005
Asset category:
Equity securities	59%	65%
Debt securities	37%	33%
Cash equivalents	4%	2%
Total	100%	100%

Assets of the postretirement benefit plans were invested 100% in debt securities for 2006 and 2005.

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, 2006, the defined benefit pension plan had a diversified asset allocation strategy of 55% to 75% and a target of 60% for equity securities and 35% to 45% and a target of 40% for 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 2006, the Company contributed $3.4 million to its pension plans and $0.4 million to its other postretirement benefit plans. The Company expects to contribute $3.7 million to its pension plans and $0.4 million to its other postretirement benefit plans in 2007.  

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

	Pension Benefits	Other Benefits
	(in thousands)
2007	$ 3,385	$   161
2008	$ 4,027	$   183
2009	$ 4,121	$   200
2010	$ 5,255	$   225
2011	$ 4,399	$   262
Years 2012-2016	$24,831	$1,751

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(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:

	2006		2005		2004
	(in thousands)
Sales	$	491,545	$	403,234	$	286,924
Production (lifting) costs		(68,479)		(50,949)		(35,501)
Depreciation, depletion and amortization		(143,101)		(88,902)		(66,924)
		279,965		263,383		184,499
Income tax expense		(105,227)		(96,651)		(67,031)
Results of operations	$	174,738	$	166,732	$	117,468

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 2006, 2005 and 2004:

	2006		2005		2004
	(in thousands)
Proved property acquisition costs	$	18,697	$	75	$	15,384
Unproved property acquisition costs		55,032		55,652		21,830
Exploration costs		231,771		44,416		24,526
Development costs		453,956		313,759		219,455
Capitalized costs incurred	$	759,456	$	413,902	$	281,195
Full cost pool amortization per Mcf equivalent	$	1.90	$	1.42	$	1.20

Capitalized interest is included as part of the cost of natural gas and oil properties. The Company capitalized $10.3 million, $5.0 million and $2.8 million during 2006, 2005 and 2004, respectively, based on the Company’s weighted average cost of borrowings used to finance the expenditures. The increases in capitalized interest since 2004 reflect an increase in the Company’s unevaluated costs primarily related to lease acquisition and drilling activities.

In addition to capitalized interest, the Company also capitalized internal costs of $44.1 million, $26.4 million and $14.3 million during 2006, 2005 and 2004, 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 increases in internal costs capitalized since 2004 have resulted from the addition of personnel and related costs in Southwestern’s exploration and development segment.

The table of capitalized costs incurred above does not include amounts for the acquisition of drilling rigs in 2006 and 2005, which were sold and then leased back in December 2006.

The following table shows the capitalized costs of gas and oil properties and the related accumulated depreciation, depletion and amortization at December 31, 2006 and 2005:

	2006		2005
	(in thousands)
Proved properties	$	2,484,600	$	1,775,312
Unproved properties		166,827		122,301
Total capitalized costs		2,651,427		1,897,613
Less: Accumulated depreciation, depletion and amortization		883,100		745,206
Net capitalized costs	$	1,768,327	$	1,152,407

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The table below sets forth the composition of net unevaluated costs excluded from amortization as of December 31, 2006.  Of the total, approximately $22.3 million represents costs of wells in progress at December 31, 2006 and approximately $77.2 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. Costs related to wells in progress will be included in the amortization computation in 2007. The timing and amount of the Fayetteville Shale play leasehold costs included in the amortization computation will depend on the success of drilling in pilot areas and the time frame for development of the play. The Company is, therefore, unable to estimate when these costs will be included in the amortization computation.

	2006		2005		2004		Prior		Total
	(in thousands)
Property acquisition costs	$	48,301	$	41,416	$	14,012	$	11,068	$	114,797
Exploration and development costs		32,572		4,683		150		-		37,405
Capitalized interest		3,971		5,338		2,369		2,947		14,625
	$	84,844	$	51,437	$	16,531	$	14,015	$	166,827

(6) NATURAL GAS AND OIL RESERVES (UNAUDITED)

The following table summarizes the changes in the Company’s proved natural gas and oil reserves for 2006, 2005 and 2004:

	2006		2005		2004
	Gas (MMcf)	Oil (MBbls)	Gas (MMcf)	Oil (MBbls)	Gas (MMcf)	Oil (MBbls)
Proved reserves, beginning of year	772,339	9,079	594,483	8,508	457,016	7,675
Revisions of previous estimates	(75,420)	(1,870)	(29,970)	(284)	(13,832)	199
Extensions, discoveries and other additions	352,734	1,645	264,683	1,669	196,398	1,274
Production	(68,133)	(698)	(56,758)	(705)	(50,425)	(618)
Acquisition of reserves in place	2,760	22	28	-	5,634	30
Disposition of reserves in place	(5,346)	(280)	(127)	(109)	(308)	(52)
Proved reserves, end of year	978,934	7,898	772,339	9,079	594,483	8,508
Proved developed reserves:
Beginning of year	551,456	8,309	491,697	7,767	369,867	6,719
End of year	623,870	6,994	551,456	8,309	491,697	7,767

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, 2006, 2005 and 2004:

	2006		2005		2004
	(in thousands)
Future cash inflows	$	5,662,436	$	6,699,456	$	3,857,623
Future production costs		(1,752,482)		(1,656,084)		(983,654)
Future development costs		(737,292)		(329,528)		(108,911)
Future income tax expense		(794,388)		(1,387,765)		(779,386)
Future net cash flows		2,378,274		3,326,079		1,985,672
10% annual discount for estimated timing of cash flows		(1,335,519)		(1,905,268)		(1,093,364)
Standardized measure of discounted future net cash flows	$	1,042,755	$	1,420,811	$	892,308

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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 $5.64 per Mcf for gas and $57.25 per barrel for oil in 2006, $10.08 per Mcf for gas and $61.04 per barrel for oil in 2005, and $6.18 per Mcf for gas and $43.45 per barrel for oil in 2004.  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 rat e to arrive at the standardized measure.

Following is an analysis of changes in the standardized measure during 2006, 2005 and 2004:

	2006		2005		2004
	(in thousands)
Standardized measure, beginning of year	$	1,420,811	$	892,308	$	716,352
Sales and transfers of gas and oil produced, net of production costs		(423,066)		(361,815)		(252,241)
Net changes in prices and production costs		(711,234)		582,247		28,009
Extensions, discoveries, and other additions, net of future production and development costs		381,924		546,523		367,892
Acquisition of reserves in place		5,106		58		20,771
Revisions of previous quantity estimates		(140,257)		(91,648)		(26,481)
Accretion of discount		198,641		121,837		99,432
Net change in income taxes		299,630		(239,539)		(48,091)
Changes in estimated future development costs		(69,450)		(248,322)		(70,005)
Previously estimated development costs incurred during the year		116,601		71,729		42,143
Changes in production rates (timing) and other		(35,951)		147,433		14,527
Standardized measure, end of year	$	1,042,755	$	1,420,811	$	892,308

(7) INVESTMENT IN UNCONSOLIDATED PARTNERSHIP

On May 2, 2006, the Company sold its 25% partnership interest in NOARK to Atlas Pipeline Partners, L.P. for $69.0 million and recognized a pre-tax gain of approximately $10.9 million ($6.7 million after tax) in the second quarter relating to the transaction.  The Company’s share of pre-tax income or loss from operations related to our investment in NOARK was income of $0.9 million in 2006 and $1.6 million in 2005, and a loss of $0.4 million in 2004. Income from operations and the gain on the sale in the second quarter of 2006 were recorded in other income in our statements of operations. The Company’s investment in NOARK totaled $17.1 million at December 31, 2005.

(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 and Cash Equivalents, and Customer Deposits: 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 Hedges: The fair value of all hedging financial instruments is the amount at which they could be settled, based on quoted market prices, best estimates obtained from counterparties and an option pricing model, when necessary, for price option contracts.

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The carrying amounts and estimated fair values of the Company’s financial instruments as of December 31, 2006 and 2005 were as follows:

	2006				2005
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(in thousands)
Cash and cash equivalents	$	42,927	$	42,927	$	223,705	$	223,705
Customer deposits	$	6,894	$	6,894	$	6,352	$	6,352
Total debt	$	137,800	$	141,704	$	100,000	$	105,370
Commodity hedges asset (liability)	$	58,102	$	58,102	$	(153,246)	$	(153,246)

Derivatives and Risk Management

The Company enters into various types of derivative instruments for a portion of its projected gas and oil sales to reduce its exposure to market price volatility for natural gas and oil.  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, 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 or as a component of other comprehensive income.

As of December 31, 2006, derivative instruments utilized by the Company included swaps, basis swaps and costless collars that have been classified as follows:

·

For fixed-price swaps, the Company receives a fixed price for the contract and pays a floating market price to the counterparty.

·

For floating-price swaps, the Company receives a floating market price from the counterparty and pays a fixed price.

·

Costless-collars contain a fixed floor price (put) and ceiling price (call). If the market price exceeds the call strike price or falls below the put strike price, the Company receives the fixed price and pays the market price. If the market price is between the call and the put strike price, no payments are due from either party.

·

Basis swaps are arrangements that guarantee a price differential for natural gas from a specified delivery point. For basis protection swaps, the Company receives a payment from the counterparty if the price differential is greater than the stated terms of the contract and pays the counterparty if the price differential is less than the stated terms of the contract.

·

Regulatory swaps are similar to that of floating price swaps but are used exclusively by the Natural Gas Distribution segment and are subject to accounting requirements set forth by the Arkansas Public Service Commission.

Substantially all of the Company’s gas and oil derivative instruments that are not basis related are settled based upon NYMEX prices. Substantially all of the Company’s derivative instruments that are basis related are settled based upon “Inside FERC” published prices for the particular locational basis that is traded.  The estimated fair value of these derivative instruments are based upon various market factors.

At December 31, 2006, the Company recorded hedging assets of $87.3 million, hedging liabilities of $20.7 million as well as a regulatory asset and corresponding current liability of $8.1 million related to its utility gas purchase hedges.  As of December 31, 2006, a net of tax gain to other comprehensive income (loss) of $41.4 million was recorded. 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, 2005, the Company recorded hedging assets of $19.5 million, hedging liabilities of $172.7 million, a regulatory asset and corresponding current liability of $1.2 million related to its utility gas purchase hedges, and a net of tax loss to other comprehensive income (loss) of $99.8 million. The change in accumulated other comprehensive loss related to derivatives was a gain of $224.2 million ($141.2 million after tax) for the y ear ended December 31, 2006, a loss of $128.6 million ($81.0 million after tax) for the year ended December 31, 2005 and a loss of $10.7 million ($6.8 million after tax) for the year ended December 31, 2004. Assuming the market prices of futures as of December 31, 2006 remain unchanged, we would expect to transfer a gain of approximately $30.6 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, 2006 are expected to mature by December 31, 2008.

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Gains or losses from derivative transactions are reflected as adjustments to oil and gas sales on the consolidated statements of operations. Realized gains from settled contracts included in oil and gas sales were $14.3 million in 2006, compared to realized losses of $85.8 million and $31.8 million in 2005 and 2004, respectively.

Cash Flow Hedges

For cash flow hedges, all derivative instruments are reported as either a hedging asset or hedging liability on the balance sheet and are measured at fair value. The reporting of gains and losses on derivative hedging instruments depends on whether the gains or losses are effective at offsetting changes in the cash flows of the hedged item. The effective portion of the gain or loss on the derivative hedging instrument is recorded in other comprehensive income (OCI) until recognized in earnings during the period that the hedged transaction takes place. The ineffective portion of the gains and losses from hedges is recognized in earnings immediately. The Company recorded a gain on the change in ineffectiveness of $20.2 million in 2006, compared to losses of $9.4 million and $1.5 million in 2005 and 2004, respectively.

For those contracts designated as cash flow hedges, the Company formally documents all relationships between the derivative instruments and the commodity being hedged, as well as its risk management objective and strategy for the particular derivative contracts as required by FAS 133.

Other Derivative Contracts

Although the Company’s basis swaps meet the objectives to manage our commodity price exposure, some of these trades do not qualify for hedge accounting under FAS 133. The basis swaps that do qualify for hedge accounting treatment are classified as “matched-basis” swaps. These matched basis swaps have been combined with other derivative trades (i.e., costless collars and swaps) to form a single hedge where both trades are accounted for as a unit. The basis swap trades that have not been designated as hedges are recorded on the balance sheet at their fair values under hedging assets and hedging liabilities. All realized and unrealized gains and losses related to these contracts are recognized immediately in the statement of operations as a component of gas sales. As of December 31, 2006 and 2005, the fair values of the basis swaps that do not meet the requirements of FAS 133 hedges were a $6.7 million liability and a $19.1 million asset, resp ectively.  The unrealized loss included in gas and oil sales for non-qualifying basis swaps was $25.8 million in 2006, compared to an unrealized gain of $19.1 million in 2005 and an unrealized loss of $1.2 million in 2004.

Hedge Position

At December 31, 2006, the Company had outstanding natural gas price swaps on total notional volumes of 32.5 Bcf in 2007 and 13.0 Bcf in 2008 for which the Company will receive fixed prices ranging from $6.20 to $12.06 per MMBtu. At December 31, 2006, the Company also had outstanding natural gas price swaps on total notional volumes of 0.2 Bcf in 2007 for which the Company will pay an average fixed price of $7.61 per Mcf.  At December 31, 2006, the Company had outstanding fixed price basis differential swaps on 62.0 Bcf of 2007 and 2008 gas production that did not qualify for hedge treatment.  

At December 31, 2006, the Company had collars in place on notional volumes of 34.0 Bcf in 2007, and 22.0 Bcf in 2008. The 34.0 Bcf in 2007 had an average floor and ceiling price of $6.93 and $12.34 per MMBtu, respectively. The 22.0 Bcf in 2008 had an average floor and ceiling price of $7.92 and $13.15 per MMBtu, respectively.  The Company’s price risk management activities increased revenues by $8.7 million in 2006, and reduced revenues by $77.2 million in 2005 and $35.6 million in 2004.

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.

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(9) STOCK BASED COMPENSATION

The Southwestern Energy Company 2004 Stock Incentive Plan (2004 Plan) was adopted in February 2004 and approved by stockholders in May 2004. The 2004 Plan 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) but did not affect prior awards under those plans which remained valid and some of which are still outstanding. The awards under the prior plans have been adjusted for the two-for-one stock splits in 2005 as permitted under such plans. The Company also has awards outstanding under 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 to employees, officers and directors that in the aggregate do not exceed 8,400,000 shares (as adjusted for the stock splits). The types of incentives that may be awarded are comprehensive and are intended to enable the Company’s 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.

As initially adopted, the 2000 Plan provided for the grant of options, stock appreciation rights, shares of phantom stock, and shares of restricted stock to employees, officers and directors that in the aggregate did not exceed 1,250,000 shares and an annual award to each non-employee director with respect to 8,000 shares of common stock. 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 1,200,000 shares to employees who are not officers or directors of the Company under provisions of Section 16 of the Securities Exchange Act of 1934, as amended.

The 1993 Plan, as amended, provided for the compensation of officers and key employees of the Company 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. As adopted, the 1993 Director Plan provided for annual stock option grants of 12,000 shares (with 12,000 limited SARs to each non-employee director up to an aggregate of 240,000 shares.

On January 1, 2006, the Company adopted FAS 123R, which requires companies to measure the cost of employee services received in exchange for an award of equity instruments based on the grant date fair value of the award. The Company has elected to use the modified prospective application method such that FAS 123R applies to new awards, the unvested portion of existing awards and to awards modified, repurchased or canceled after the effective date. The Company has equity incentive plans that provide for the issuance of stock options and restricted stock. 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. Generally, stock options granted to employees and directors vest ratably over three to four years from the grant date. The Company issues shares of restricted stock to employees and directors which generally vest over four years. The Company recognizes stock-based compensation expense on a straight-line basis over the requisite service period of the individual grants with the exception of awards granted to participants who have reached retirement age or will reach retirement age during the vesting period. In the fourth quarter of 2005, the Board of Directors prospectively revised the vesting for restricted stock and stock options granted to participants on or after December 8, 2005 under the 2004 Plan to immediately accelerate vesting upon death, disability or retirement (subject to a minimum of five years of service). This change did not affect awards issued prior to December 8, 2005.

Prior to January 1, 2006, the Company accounted for its long-term equity incentive plans under the intrinsic value method described in APB Opinion No. 25, “Accounting for Stock Issued to Employees” and related interpretations (APB 25). The Company, applying the intrinsic value method, did not record stock-based compensation cost for stock options because the exercise price of the stock options equaled the market price of the underlying stock at the date of grant.

Stock Options

For the year ended December 31, 2006, the Company recognized compensation costs of $3.6 million related to stock options subject to FAS 123R. Of this amount, $0.5 million was directly related to the acquisition, exploration and development activities for the Company’s gas and oil properties and was capitalized into the full cost pool. The remaining

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costs were recorded in general and administrative expenses. Under the provisions of FAS 123R, the Company recorded a deferred tax benefit of $1.1 million related to stock options for the year ended December 31, 2006. Unrecognized compensation costs of $6.4 million related to stock options not yet vested are expected to be recognized over future periods. That cost is expected to be recognized over a weighted-average period of 1.5 years.

The fair value of stock options is estimated on the date of the grant using a Black-Scholes valuation model that uses the weighted average assumptions noted in the following table.  Expected volatility is based on historical volatility of the Company’s common stock and other factors.  The Company uses historical data on exercise of stock options, post vesting forfeitures and other factors to estimate the expected term of the share-based payments granted. The risk free interest rate is based on the U.S. Treasury yield curve in effect at the time of grant.

Assumptions	2006	2005	2004
Risk-free interest rate	4.5%	4.4%	3.5%
Expected dividend yield	—	—	—
Expected volatility	42.7%	40.6%	44.3%
Expected term	5 years	4 years	5-6 years

The Company may utilize treasury shares, if available, or use authorized but unissued shares when a stock option is exercised or when restricted stock is granted.

Prior to the adoption of FAS 123R on January 1, 2006, the Company accounted for its stock-based compensation plans under the recognition and measurement principles of APB 25.  The following table illustrates the effect on net income and earnings per share for 2005 and 2004 as if the fair value based method under FAS 123R had been applied to all outstanding vested and unvested awards for those periods.

	For the years ended December 31,
	2005		2004
	(in thousands, except share/per share amounts)
Net income, as reported	$	147,760	$	103,576
Add back: Stock option based compensation expense included in reported net income, net of related tax effects		1,203		1,251
Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effects		(2,995)		(2,433)
Pro forma net income	$	145,968	$	102,394
Earnings per share:
Basic-as reported (1)	$	0.98	$	0.72
Basic-pro forma (1)		0.97		0.72
Diluted-as reported (1)		0.95		0.70
Diluted-pro forma (1)		0.93		0.69

⁽¹⁾

2004 restated to reflect two-for-one stock splits effected in June and November 2005.

The following tables summarize stock option activity for the years 2006, 2005 and 2004 and provide information for options outstanding at December 31, 2006:

	2006			2005			2004 (1)
	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	7,126,465	$	4.34	8,884,512	$	3.18	10,107,640	$	2.72
Granted	221,330		40.67	223,780		35.44	500,040		11.99
Exercised	(1,549,679)		2.50	(1,981,827)		2.66	(1,718,504)		3.02
Canceled	(5,876)		24.41	-		-	(4,664)		3.14
Options outstanding at December 31	5,792,240	$	6.19	7,126,465	$	4.34	8,884,512	$	3.18

⁽¹⁾

2004 restated to reflect two-for-one stock splits effected in June and November 2005.

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	Options Outstanding						Options Exercisable
Range of Exercise Prices	Options Outstanding  at Year End		Weighted Average Exercise  Price	Weighted Average Remaining Contractual Life  (Years)		Aggregate Intrinsic Value  (in thousands)	Options Exercisable  at Year End		Weighted Average Exercise  Price		Aggregate Intrinsic Value  (in thousands)
$1.50  -  $1.86	2,075,891	$	1.73	3.6			2,075,891	$	1.73
$1.87  -  $2.85	674,828		2.52	4.1			674,828		2.52
$2.86  -  $5.00	1,332,160		2.95	4.6			1,332,160		2.95
$5.01  -  $12.00	854,874		5.53	7.0			800,206		5.46
$12.01 - $41.00	854,487		25.65	5.7			339,517		17.45
	5,792,240	$	6.19	4.7	$	167,139	5,222,602	$	3.74	$	163,523

There were 221,330, 223,780 and 500,040 stock options granted during 2006, 2005 and 2004, respectively.  The total intrinsic value of options exercised during 2006, 2005 and 2004 was $49.0 million, $39.3 million and $9.0 million, respectively.

Associated with the exercise of stock options, the Company received a tax benefit of $14.6 million, $12.0 million and $2.7 million in 2006, 2005 and 2004, respectively. The tax benefit is recorded as an increase in additional paid-in capital.  

Restricted Stock

For years ended December 31, 2006 and 2005, the Company recognized compensation costs of $3.3 million and $2.6 million, respectively, related to restricted stock grants. Of these amounts, $1.2 million in 2006 and $0.8 million in 2005 were directly related to the acquisition, exploration and development activities for the Company’s gas and oil properties and were capitalized into the full cost pool. The remaining costs were recorded in general and administrative expenses. Under the provisions of FAS 123R, the Company recorded a deferred tax liability of $1.6 million related to restricted stock for the year ended December 31, 2006.

The Company granted 192,065 shares of restricted stock in 2006, 132,065 shares of restricted stock in 2005 and 59,690 shares of restricted stock, on a pre-split basis, in 2004. The fair values of the grants were $7.6 million for 2006, $4.3 million for 2005 and $2.8 million for 2004. Of the 4,948,942 shares granted to date under the Company’s long-term equity incentive plans, 1,787,100 shares vest over a three-year period, 2,991,642 shares vest over a four-year period and the remaining shares vest over a five-year period.  As of December 31, 2006, 4,146,513 shares have vested to employees.  In 2006, 24,073 shares of restricted stock were canceled and 46,132 shares were canceled in 2005. In 2004, 3,210 shares of restricted stock, on a pre-split basis, were canceled.

The following tables summarize restricted stock activity for the years 2006, 2005 and 2004 and provide information for restricted stock outstanding at December 31, 2006:

	2006			2005			2004 (1)
	Number of Shares	Weighted Average Grant Date Fair Value		Number of Shares	Weighted Average Grant Date Fair Value		Number of Shares	Weighted Average Grant Date Fair Value
Unvested shares at January 1	707,142	$	11.14	1,281,031	$	4.49	1,686,459	$	2.48
Granted	192,065		39.81	132,065		32.39	238,760		11.86
Vested	(396,402)		7.51	(659,822)		2.89	(631,348)		1.92
Canceled	(24,073)		18.08	(46,132)		5.48	(12,840)		3.50
Unvested shares at December 31	478,732	$	25.30	707,142	$	11.14	1,281,031	$	4.49

⁽¹⁾

2004 restated to reflect two-for-one stock splits effected in June and November 2005.

As of December 31, 2006, there was $11.7 million of total unrecognized compensation cost related to unvested shares. That cost is expected to be recognized over a weighted-average period of 1.4 years. The total fair value of shares vested during 2006 was $2,974,000.

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(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 $10.00, 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 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 $0.0025 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

Operating Commitments

The Company’s E&P and Midstream Services segments have commitments to third parties for demand transportation charges. At December 31, 2006, future payments under non-cancelable demand charges for the Company’s E&P and Midstream Services segments are approximately $11,794,000 in 2007, $15,929,000 in 2008, $6,991,000 in 2009, $5,495,000 in 2010 and $4,167,000 in 2011.

Additionally, the Company’s gas distribution 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, 2006, future payments under these non-cancelable demand contracts are $9,869,000 in 2007, $9,245,000 in 2008, $9,631,000 in 2009, $10,018,000 in 2010, $10,405,000 in 2011 and $31,681,000 thereafter.

On December 15, 2006, the Company entered into a precedent agreement pursuant to which it will contract for firm gas transportation services on two newly-proposed pipeline laterals and related facilities of Texas Gas Transmission, LLC (Texas Gas), a subsidiary of Boardwalk Pipeline Partners, LP. The Company will be a “Foundation Shipper” for the project and will use the proposed laterals and related facilities primarily to deliver gas volumes produced from the Company’s operations in its Fayetteville Shale play in central Arkansas. Depending on regulatory approvals, the expected in-service date for both laterals is January 1, 2009. The first lateral line (Fayetteville Lateral) will originate in Conway County, Arkansas, and connect to Texas Gas’ mainline system in Coahoma County, Mississippi. The Fayetteville Lateral will be a minimum of 36” in diameter and would have an estimated ultimate capacity of up to 1.1 Bcf per day. The sec ond lateral (Greenville Lateral) will originate at the Texas Gas mainline system near Greenville, Mississippi, and extend eastward to interconnect with various interstate pipelines. The firm transportation agreements to be entered into by the Company pursuant to the precedent agreement will have an initial term of ten years and, over time, will enable the Company to transport up to 500,000 MMBtu per day on the Fayetteville Lateral and up to 400,000 MMBtu per day on the Greenville Lateral. The Company will also have the option to acquire up to 300,000 MMBtu per day of additional capacity on the Fayetteville Lateral and up to 240,000 MMBtu per day of additional capacity on the Greenville Lateral. Upon execution and delivery of the firm transportation agreements contemplated by the precedent agreement, the Company’s Midstream Services segment would have additional demand charges of $503.5 million that would be payable over the ten-year term of the agreements.

On December 29, 2006, Southwestern entered into a sale/leaseback transaction pursuant to which the Company sold 13 operating drilling rigs, two rigs yet to be delivered and related equipment and then leased such drilling rigs and equipment from the buyer for an initial term of eight years from January 1, 2007 for rental payments of approximately $19,584,000 annually. Subject to certain conditions, the Company has options to purchase the rigs and related equipment

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from the lessors at the end of the 84^th month of the lease term at an agreed upon price or at the end of the lease term for its then fair market value. Additionally, the Company has the option to renew the lease for a negotiated renewal term at a periodic rental equal to the fair market rental value of the rigs as determined at the time of renewal.

The Company leases compressors related to its Midstream Services and E&P operations under non-cancelable operating leases expiring through 2014. At December 31, 2006, future minimum payments under these non-cancelable leases accounted for as operating leases are approximately $18,046,000 in 2007, $19,646,000 in 2008, $17,713,000 in 2009, $15,492,000 in 2010, $12,618,000 in 2011 and $7,002,000 thereafter. The Company also leases certain office space and equipment under non-cancelable operating leases expiring through 2013. At December 31, 2006, future minimum payments under these non-cancelable leases accounted for as operating leases are approximately $4,905,000 in 2007, $4,545,000 in 2008, $4,043,000 in 2009, $2,690,000 in 2010, $2,544,000 in 2011 and $2,748,000 thereafter.

Environmental Risk

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.

Litigation

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.

A lawsuit was filed against the Company in 2001 alleging a breach of an agreement to indemnify the other party against settlement payments related to the Company’s Boure' prospect in Louisiana. The allegations were contested and, in 2002, the Company was granted a motion for summary judgment by the trial court. The case was appealed to the First Court of Appeals in Houston, Texas, which subsequently transferred the appeal to the Thirteenth Court of Appeals in Corpus Christi. The appeal was briefed and argued during 2003. On April 14, 2005, the Thirteenth Court of Appeals reversed the orders of the trial court and rendered judgment denying the Company’s motion for summary judgment and granting the motion for summary judgment of the other party.  The Company’s motion for rehearing with the Thirteenth Court of Appeals was denied on May 19, 2005. In August of 2005, the Company filed a petition for review with the Texas Supreme Court. In Oc tober of 2005, the Texas Supreme Court invited additional briefing by the parties. In March of 2006, the Texas Supreme Court requested that both parties submit full briefing on the merits of the case. After receiving full briefing from both sides, the Company’s petition for review with the Texas Supreme Court was denied on December 1, 2006, and the case has been remanded to the trial court for further disposition.  Should the other party prevail in the case, the Company could be required to pay approximately $2.1 million, plus pre-judgment interest and attorney's fees.  Based on an assessment of this litigation by the Company and its legal counsel, the Company accrued a loss in the fourth quarter of 2006.

(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.  The Midstream Services segment generates revenue through the marketing of both Company and third-party produced gas volumes and through gathering fees associated with the transportation of natural gas to market. Gathering revenues have been insignificant to-date but are expected to increase in the future depending upon the level of production from our Fayetteville Shale properties.  Revenues for the Natural Gas Distribution segment arise from the transportation and sale of natural gas at retail.

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 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, the Company’s former investment in the Ozark Gas Transmission system and corporate items.

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	Exploration And Production		Midstream Services		Natural Gas Distribution		Other			Total
	(in thousands)
2006
Revenues from external customers	$	452,887	$	138,251	$	171,974	$	-		$	763,112
Intersegment revenues		38,658		336,956		233		448			376,295
Operating income		237,307		4,111		4,474		380			246,272
Interest and other income (loss)(1)		6,271		(581)		(415)		11,804			17,079
Depreciation, depletion and amortization expense		143,101		1,772		6,325		92			151,290
Interest expense(1)		508		-		171		-			679
Provision for income taxes(1)		91,276		554		1,698		5,871			99,399
Assets		1,965,247		112,027		206,919		94,876	(2)		2,379,069
Capital investments(3)		861,041		48,660		11,232		21,474			942,407
2005
Revenues from external customers	$	365,384	$	132,690	$	177,810	$	445		$	676,329
Intersegment revenues		37,850		327,200		672		448			366,170
Operating income		234,759		5,684		4,911		566			245,920
Interest and other income (loss)(1)		3,401		-		(269)		1,652			4,784
Depreciation, depletion and amortization expense		88,902		303		6,907		99			96,211
Interest expense(1)		8,416		1,054		4,429		1,141			15,040
Provision for income taxes(1)		83,921		1,668		11		831			86,431
Assets		1,315,616		53,894		212,113		286,901	(2)		1,868,524
Capital investments(3)		451,289		15,840		10,908		5,014			483,051
2004
Revenues from external customers	$	253,920	$	65,128	$	152,288	$	5,801		$	477,137
Intersegment revenues		33,004		249,849		161		448			283,462
Operating income		164,585		3,151		8,516		6,035			182,287
Depreciation, depletion and amortization expense		66,924		67		6,592		91			73,674
Interest expense(1)		11,537		-		4,461		994			16,992
Provision for income taxes(1)		55,197		1,151		1,471		1,959			59,778
Assets		890,486		29,243		184,213		42,202	(2)		1,146,144
Capital investments(3)		281,988		-		7,298		5,704			294,990

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

⁽²⁾ Other assets include the Company’s investment in cash equivalents for 2006 and 2005, the Company’s equity investment in the operations of NOARK (see Note 7) for 2005 and 2004, corporate assets not allocated to segments and assets for non-reportable segments.

⁽³⁾ Capital investments for 2006, 2005 and 2004 included $88.9 million, $28.1 million and $3.9 million, respectively, related to the change in accrued expenditures between years.

Included in intersegment revenues of the Midstream Services segment are $284.9 million, $290.9 million and $235.7 million for 2006, 2005 and 2004, respectively, for marketing of the Company’s E&P sales.  Intersegment sales by the E&P segment and Midstream Services segment to the Natural Gas Distribution segment are priced in accordance with terms of existing contracts and current market conditions. Parent company assets include furniture and fixtures and prepaid debt 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.

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(13) QUARTERLY RESULTS (UNAUDITED)

The following is a summary of the quarterly results of operations for the years ended December 31, 2006 and 2005:

	Mar 31		June 30		Sept 30		Dec 31
	(in thousands, except per share amounts) 2006
Operating revenues	$	226,702	$	153,999	$	168,394	$	214,017
Operating income		89,804		48,294		53,118		55,056
Net income		58,395		37,004		33,477		33,760
Basic earnings per share		0.35		0.22		0.20		0.20
Diluted earnings per share		0.34		0.22		0.20		0.20
	2005
Operating revenues	$	161,053	$	132,463	$	162,127	$	220,686
Operating income		56,226		47,181		67,201		75,312
Net income		32,621		26,814		39,469		48,856
Basic earnings per share		0.23		0.19		0.27		0.29
Diluted earnings per share		0.22		0.18		0.26		0.29

(14) NEW ACCOUNTING STANDARDS

During the fourth quarter of fiscal 2006, the Company adopted Statement on Financial Accounting Standards No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans” (FAS 158).  FAS 158 requires the recognition of the funded status of each defined pension benefit plan, retiree health care and other postretirement benefit plans and postemployment benefit plans on the balance sheet. Each over-funded plan is recognized as an asset and each under-funded plan is recognized as a liability. The initial impact of the adoption of the standard as well as subsequent changes in the funded status is recognized as a component of accumulated comprehensive loss in the statement of stockholders equity. Additional minimum pension liabilities and related intangible assets are also derecognized upon adoption of the new standard. FAS 158 requires initial application for fiscal years ending after December 15, 2006.  See Note 4 of our financial statements for a description of the impact of this standard on our financial statements.

In June 2006, the FASB issued FASB Interpretation (FIN) No. 48, Accounting for Uncertainty in Income Taxes—an interpretation of FASB Statement No. 109. FIN 48 provides guidance for recognizing and measuring uncertain tax positions, as defined in SFAS 109, Accounting for Income Taxes. FIN 48 prescribes a threshold condition that a tax position must meet for any of the benefit of the uncertain tax position to be recognized in the financial statements. Guidance is also provided regarding de-recognition, classification and disclosure of these uncertain tax positions. FIN 48 is effective for fiscal years beginning after December 15, 2006. The Company is in the process of evaluating the impact of the adoption of this interpretation on its results of operations and financial condition.

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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, accumulate and communicate information to our management, including our Chief Executive Officer and Chief Financial Officer, to allow timely decisions regarding required disclosures and submission 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, 2006.  There were no changes in our internal control over financial reporting during the three months ended December 31, 2006 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 59 of this Form 10-K.

ITEM 9B. OTHER INFORMATION

There was no information required to be disclosed in a current report on Form 8-K during the fourth quarter of the fiscal year ended December 31, 2006 that was not reported on such form.

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PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

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 Stockholders to be held on or about May 10, 2007, or the 2007 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 and our audit committee financial expert. We refer you to the sections “Proposal No. 1: Election of Directors” and “Share Ownership of Management, Directors and Nominees” in the 2007 Proxy Statement for information concerning our directors. We refer you to the section “Corporate Governance – Committees of the Board of Directors” for discussion of our audit committee and 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 secti on “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 stockholder who requests it.   Requests for copies should be addressed to the Secretary at 2350 N. Sam Houston Parkway East, Suite 125, Houston TX, 77032.

ITEM 11. EXECUTIVE COMPENSATION

The 2007 Proxy Statement is hereby incorporated by reference for the purpose of providing information about executive compensation, compensation committee interlocks and insider participation as well as the Compensation Committee Report. We refer you to the sections “Compensation Discussion & Analysis,” “Executive Compensation,” “Outside Director Compensation,” “Compensation Committee Interlocks and Insider Participation” and “Compensation Committee Report” in the 2007 Proxy Statement.

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

The 2007 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 2007 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 and directors.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

The 2007 Proxy Statement is hereby incorporated by reference for the purpose of providing information about certain relationships, related transactions and board independence. Refer to the sections “Transactions with Related Persons,” “Share Ownership of Management, Directors and Nominees,” and “Compensation Discussion and Analysis” for information about transactions with our executive officers, directors or management and to “Corporate Governance – Director Independence” and “ – Committees of the Board of Directors” for information about director independence.

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

The 2007 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” in the 2007 Proxy Statement and to Exhibit A thereto for information concerning fees paid to our principal accountant and the audit committee’s pre-approval policies and procedures and other required information.

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PART IV

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES

(a)

(1)

The consolidated financial statements of Southwestern Energy Company and its subsidiaries and the report of independent registered public accounting firm 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.

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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: February 28, 2007	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 February 28, 2007.

/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/ 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

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 EXHIBIT INDEX

Exhibit Number	Description
3.1	Certificate of Incorporation of Southwestern Energy Company. (Incorporated by reference to Exhibit 3.1 to the Registrant's Current Report on Form 8-K/A filed August 3, 2006)
3.2	Bylaws of Southwestern Energy Company. (Incorporated by reference to Exhibit 3.2 to the Registrant's Current Report on Form 8-K/A filed August 3, 2006)
4.1	Form of Common Stock Certificate. (Incorporated by reference to Exhibit 4.4 to the Registrant's Current Report on Form 8-K/A filed August 3, 2006)
4.2	Indenture, dated as of December 1, 1995 between Southwestern Energy Company and The First National Bank of Chicago (now J.P. Morgan Chase Bank). (Incorporated by reference to Exhibit 4 to Amendment No. 1 to the Registrant's Registration Statement on Form S-3 (File No. 33-63895) filed on November 17, 1995)
4.3	First Supplemental Indenture between Southwestern Energy Company and J.P. Morgan Trust Company, N.A. as successor to the First National Bank of Chicago dated June 30, 2006. (Incorporated by reference to Exhibit 4.2 to the Registrant's Current Report on Form 8-K/A filed August 3, 2006)
4.4	Indenture dated June 1, 1998 by and among NOARK Pipeline Finance, L.L.C. and The Bank of New York. (Incorporated by reference to Exhibit 4.1 to the Registrant's Current Report on Form 8-K filed May 4, 2006)
4.5	First Supplemental Indenture dated May 2, 2006 by and among Southwestern Energy Company, NOARK Pipeline Finance, L.L.C., and UMB Bank, N.A. as successor to the Bank of New York (Incorporated by reference to Exhibit 4.2 to the Registrant's Current Report on Form 8-K filed May 4, 2006)
4.6	Second Supplemental Indenture between Southwestern Energy Company and UMB Bank, N.A. as successor to the Bank of New York dated June 30, 2006. (Incorporated by reference to Exhibit 4.3 to the Registrant's Current Report on Form 8-K/A filed August 3, 2006)
4.7	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)
4.8	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)
4.9	Amendment No. 2 to the Amended and Restated Rights Agreement between Southwestern Energy Company and Computershare Trust Company, N.A. as successor to the First National Bank of Chicago dated June 30, 2006. (Incorporated by reference to Exhibit 4.5 to the Registrant's Current Report on Form 8-K/A filed August 3, 2006)
4.10	Guaranty dated June 1, 1998 by Southwestern Energy Company in favor of The Bank of New York, as trustee (the “Trustee”), under the Indenture dated as of June 1, 1998 between NOARK Pipeline Finance L.L.C. and the Trustee. (Incorporated by reference to Exhibit 4.6 to the Registrant’s Annual Report filed on Form 10-K (Commission file No. 1-08246) for the year ended December 31, 2005)
4.11*	Second Amended and Restated Credit Agreement dated February 9, 2007 among Southwestern Energy Company, JPMorgan Chase Bank, NA, SunTrust Bank, The Royal Bank of Scotland PLC, Royal Bank of Canada, Bank of America, N.A., and the other lenders named therein, JPMorgan Chase Bank, NA, as administrative agent, SunTrust Bank as syndication agent.
4.12	Policy on Confidential Voting of Southwestern Energy Company. (Incorporated by reference to the Appendix of the Registrant's Definitive Proxy Statement (Commission File No. 1-08246) for the 2006 Annual Meeting of Stockholders)

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10.1	Form of Second Amended and Restated Indemnity Agreement between Southwestern Energy Company and each Executive Officer and Director of the Registrant. (Incorporated by reference to Exhibit 10.1 to the Registrant's Current Report on Form 8-K/A filed August 3, 2006)
10.2	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)
10.3	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)
10.4	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)
10.5	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)
10.6	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)
10.7	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)
10.8	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)
10.9	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 Stockholders)
10.10	Southwestern Energy Company 2002 Employee Stock Incentive Plan, effective October 23, 2002.  (Incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K (filed December 13, 2005)
10.11	Southwestern Energy Company 2002 Performance Unit Plan, as amended, effective December 8, 2005. (Incorporated by reference to Exhibit 10.1 to Registrant’s Current Report on Form 8-K filed on December 13, 2005)
10.12	Southwestern Energy Company 2004 Stock Incentive Plan. (Incorporated by reference to Appendix A to the Registrant’s Proxy Statement dated March 29, 2004)
10.13	Form of Incentive Stock Option Agreement for awards prior to December 8, 2005. (Incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed on December 20, 2004)
10.14	Form of Restricted Stock Agreement for awards prior to December 8, 2005. (Incorporated by reference to Exhibit 10.3 to the Registrant’s Current Report on Form 8-K filed on December 20, 2004)
10.15	Form of Non-Qualified Stock Option Agreement for non-employee directors for awards prior to December 8, 2005. (Incorporated by reference to Exhibit 10.2 to the Registrant’s Current Report on Form 8-K filed on December 20, 2004)
10.16	Form of Incentive Stock Option for awards granted on or after December 8, 2005 (Incorporated by reference to Exhibit 10.4 to the Registrant’s Current Report on Form 8-K filed on December 13, 2005)
10.17	Form of Restricted Stock Agreement for awards granted on or after December 8, 2005 (Incorporated by reference to Exhibit 10.4 to the Registrant’s Current Report on Form 8-K filed on December 13, 2005)

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10.18	Form of Non-Qualified Stock Option Agreement for awards granted on or after December 8, 2005 (Incorporated by reference to Exhibit 10.4 to the Registrant’s Current Report on Form 8-K filed on December 13, 2005)
10.19	Description of Compensation Payable to Non-Management Directors.  (Incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed on May 31, 2006)
10.20	Form of Restricted Stock Agreement for Special Incentives.  (Incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed on December 14, 2006)
10.21	Project Services Agreement by and between SEECO, Inc., a wholly-owned subsidiary of Southwestern Energy Company, and Schlumberger Technology Corporation dated August 17, 2006. (Incorporated by reference to Exhibit 10.1 to the Registrant’s Quarterly Report on Form 10-Q filed on October 23, 2006)
10.22*	Master Lease Agreement by and between Southwestern Energy Company and SunTrust Leasing Corporation dated December 29, 2006.
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

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EX-4

Execution Version

       SECOND AMENDED AND RESTATED CREDIT AGREEMENT


DATED AS OF FEBRUARY 9, 2007


AMONG


SOUTHWESTERN ENERGY COMPANY,


THE LENDERS,


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

SUNTRUST BANK,
AS SYNDICATION AGENT,

AND

ROYAL BANK OF CANADA,

BANK OF AMERICA, N.A.

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

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SECOND AMENDED AND RESTATED CREDIT AGREEMENT

This Second Amended and Restated Credit Agreement, dated as of February 9, 2007 is among Southwestern Energy Company, a Delaware Corporation (together with its successors and assigns, the “Borrower”), the Lenders, JPMorgan Chase Bank, N.A., a national banking association, as Administrative Agent, SunTrust Bank, as Syndication Agent, and Royal Bank of Canada, Bank of America, N.A. 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

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(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.

 “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” is defined in the preamble at the top of page one.

“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 Houston, Texas and New York City, 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 Houston, Texas and New York City, 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.

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2

“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 t han $500,000,000, (iv) any repurchase agreement entered into with any Lender (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 (other than for collection in the ordinary course of business), 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,

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3

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 (i) comfort letter, (ii) take or pay contract, (iii) application for a letter of credit or (iv) obligation 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 London interbank offered 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’

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4

Association London interbank offered 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 Amended and Restated Credit Agreement dated as of January 4, 2005, as amended by the First Amendment and Consent dated as of June 29, 2006, among the Borrower, various lenders and JPMorgan, as administrative agent.

 “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.

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“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 on Property now or hereafter owned or acquired by such Person, limited, however to the lesser of (x) the amount of its liability or (y) the book value of the property, (iv) obligations, whether or not assumed, payable out of the proceeds or production from Property now or hereafter owned or acquired by such Person, (v) obligations which are evidenced by notes, banker’s acceptances, or other similar instruments, (vi) 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, (vii) Capitalized Le ase Obligations, (viii) 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, (ix) net liabilities under interest rate swap, exchange or cap agreements, obligations or other liabilities with respect to accounts or notes, (x) Synthetic Lease Obligations, (xi) 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 but excluding operating leases, and (xii) Contingent Obligations; provided that, notwithstanding any of the foregoing, trade payables of gas marketing Subsidiaries and 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 future 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, 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 and any non-cash charge on pension obligations resulting from the requirements of SFAS 158, 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 me thod 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

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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 not 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.

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“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.

“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.

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“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 or leased 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

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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.

 “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.

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“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 and any non-cash charge on pension obligations recorded in stockholders’ equity resulting from the requirements of SFAS 158.

“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 Second 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.

“Synthetic Lease Obligation” means the monetary obligations of a Person under (a) a so-called synthetic or tax retention lease, or (b) an agreement for the use or possession of property creating obligations that do not appear on the balance sheet of such Person but which are depreciated for tax purposes by such Person.

“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 February 9, 2012 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.

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“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 requested by the Borrower in an aggregate amount not at any time exceeding $100,000,000 (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 requested by the Borrower in an aggregate amount not at any time exceeding $40,000,000 (and each Lender severally agrees to participate in each such Swing Line Loan as more fully set forth in Section 2.21.3); 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 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

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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 New York City 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;

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(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 (but no more often than twice in any one calendar year), 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 $250,000,000 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 incr ease in the Aggregate Commitment pursuant to this Section 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 Lende r or an increasing Lender to temporarily hold risk participations in the

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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 automatically and immediately reduced to zero and the Borrower shall forthwith deposit in the LC Collateral Account referenced in Section 2.20.11 hereof, with the Administrative Agent, for the benefit of the Lenders, an amount in cash equal to the LC Obligations.

2.8

Prepayments.  (i)   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 multiple 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

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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 remainder of the applicable In terest 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 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.

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2.13

Noteless Agreement; Evidence of Indebtedness.  1.  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 Administrative Agent and t he 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

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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 days 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

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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 date, 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 (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, (b) the amount of the LC Obligations shall not exceed $100,000,000 and (c) 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 thereof for additiona l 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

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promptly notify each Lender, of the contents thereof and of the amount of each Lender’s participation 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, transfer, cancellation 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 being understood tha t, 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

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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 a mounts 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 documents 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, caused b y (d) 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, (e) 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 (f) 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

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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 liability 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 ea ch 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 (g) the failure of any other Lender to fulfill or comply with its obligations to the Issuer hereunder (bu t nothing herein contained shall affect any right the Borrower may have against any defaulting Lender) or (h) 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 2., (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 Agree ment.

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

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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 and 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 interes t 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 give 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 $40,000,000 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

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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 New York City 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 thereafter 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, happ ening or event whatsoever.  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 Effecti ve Rate for each day during the period commencing on the date of demand and ending on the date such amount is received.

1)

YIELD PROTECTION; TAXES

3.1

Yield Protection.  (ii)  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,

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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 application 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

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Interest Period commencing at least three Business Days after the giving of such notice and (y) shall notify the Borrower 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 quasi-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 required 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.  3.  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

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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 applicable 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 Administrative Agent (x) renewal s 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 payments without any de duction or withholding of United States federal income tax.

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(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 assist 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 with all costs and expenses related ther eto (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. &nb sp;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.

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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, 2005 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.

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(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 (a) 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 (b) the Indenture dated June 1, 1998 between NOARK Pipeline Finance L.L.C. and the Bank of New York, as trustee, and in each case, 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.

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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, 2005 and the September 30, 2006 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

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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 agreement 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 $50,000,000.

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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

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.

5.17

Negative Pledge.  Except as set forth in Schedule 5.17, 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.

5.18

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.

5.19

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

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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 certificate of the Borrower’s chief financial offic er 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 and results of operations of the Borrower a nd 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):

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(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

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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 inquiry sha ll 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 or any i tem 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

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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 acco rdance 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 have a Material Advers e 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.

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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 authorized, executed and delivered by suc h 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 assets as of the beginning of such f iscal year.

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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 o r 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,

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(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 5.17,

(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,

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(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; 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:

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(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 (calculated as of the last day of each 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) $900,000,000 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), 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 or Reimbursement Obligation when due or non-payment of any 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

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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 Indebtedness 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 $50,000,000.

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) take 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 $25,000,000, which is not stayed on appeal or otherwise being appropriately contested in good faith.

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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 (j) 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 Obligat ions (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 Collateral 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.

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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 specifically set forth.  All reme dies 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

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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.  THIS AGREEMENT AND THE OTHER LOAN DOCUMENTS REPRESENT THE FINAL AGREEMENT AMONG THE PARTIES HERETO AND THERETO AND MAY NOT BE CONTRADICTED BY EVIDENCE OF PRIOR, CONTEMPORANEOUS OR SUBSEQUENT ORAL AGREEMENTS OF THE PARTIES.  THERE ARE NO UNWRITTEN ORAL AGREEMENTS BETWEEN THE PARTIES.

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.  4.  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 either Arranger or the Administrative Agent) paid or incurred by the Administrative Agent or JPMorgan Securities, Inc. in connection with the preparation,

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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 reasonable 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 in demnification.  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 transactions contemplated and the relationship established by the Loan Documents, or any act, omission or event occurring in

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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 remedy 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 with only those duti es 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

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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 genuineness 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 Document 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

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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 disbursements of any kind and nature wha tsoever 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 releva nt 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

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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.

10.12

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 satisfactory 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 Administrative Agent has resigned or been

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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 ef fectiveness of the resignation or removal of the Administrative Agent, the resigning or removed Administrative Agent 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.

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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, such 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 unl ess 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

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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 Article 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 be 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

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for all purposes be a Lender party to this Agreement 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 assignment.

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, requ est 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.

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55

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 LAWS OF THE STATE OF TEXAS, BUT GIVING EFFECT TO FEDERAL LAWS APPLICABLE TO NATIONAL BANKS.  CHAPTER 346 OF THE TEXAS FINANCE CODE (WHICH REGULATES CERTAIN REVOLVING CREDIT LOAN ACCOUNTS AND REVOLVING TRI-PARTY ACCOUNTS) SHALL NOT APPLY TO THIS AGREEMENT OR ANY NOTE.

15.2

CONSENT TO JURISDICTION.  THE BORROWER HEREBY IRREVOCABLY SUBMITS TO THE NON-EXCLUSIVE JURISDICTION OF THE COURTS OF THE STATE OF TEXAS OR OF THE UNITED STATES OF AMERICA FOR THE SOUTHERN DISTRICT OF TEXAS 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 ADMINISTRATIVE 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 HOUSTON, TEXAS.

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,

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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 shall be ap plied 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.  To the extent that Chapter 303 of the Texas Finance Code is relevant for the purpose of determining the Maximum Rate applicable to a Lender, such Lender elects to determine the applicable rate ceiling under such Chapter by the weekly ceiling from time to time in effect.  Chapter 346 of the Texas Finance Code does not apply to the Borrower’s obligations hereunder.

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 and the commitments of the Lenders under the Existing Agreement shall be superseded by the Commitments of the Lenders hereunder and terminated; 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 mad e upon the effectiveness of this Agreement), a portion of such Existing Loans equal to such 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

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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 th e Lenders may also ask to see the Borrower’s legal organizational documents or other identifying documents.

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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:   /s/ GREG D. KERLEY                                          

Executive Vice President and Chief Financial Officer


2350 N. Sam Houston Parkway East
Suite 125
Houston, Texas 77032
Attention:

Greg Kerley
Fax: 281-618-4820

Signature page for  the Southwestern

Energy Company Credit Agreement

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JPMORGAN CHASE BANK, N.A., as

Administrative Agent, as Swing Line Lender, as

Issuer and as a Lender


By:   /s/ ROBERT W. TRABAND                           

Title:   Executive Director                                  


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:  713-216-1081

Signature page for  the Southwestern

Energy Company Credit Agreement

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SUNTRUST BANK, as Syndication Agent and as a Lender

By:   /s/ ILLEGIBLE SIGNATURE                                   

Title:   Vice President                                                 

Signature page for  the Southwestern

Energy Company Credit Agreement

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ROYAL BANK OF CANADA, as Co-

Documentation Agent and as a Lender

By:   /s/ ILLEGIBLE SIGNATURE                               

Title:   Authorized Signatory                                   

Signature page for  the Southwestern

Energy Company Credit Agreement

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BANK OF AMERICA, N.A., as Co-Documentation

Agent and as a Lender

By:   /s/ ILLEGIBLE SIGNATURE                             

Title:   Managing Director                                     

Signature page for  the Southwestern

Energy Company Credit Agreement

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THE ROYAL BANK OF SCOTLAND plc, as Co-

Documentation Agent and as a Lender

By:   /s/ DAVID SLYE                                                    

Title:   Vice President                                               

Signature page for  the Southwestern

Energy Company Credit Agreement

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THE BANK OF TOKYO – MITSUBISHI UFJ,

LTD. – HOUSTON AGENCY, as Managing Agent

and as a Lender

By:   /s/ K. GLASSCOCK                                              

Title:   VP and Manager                                           

Signature page for  the Southwestern

Energy Company Credit Agreement

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BMO CAPITAL MARKETS FINANCING, INC.,

as Managing Agent and as a Lender

By:   /s/ ILLEGIBLE SIGNATURE                           

Title:   Vice President                                              

Signature page for  the Southwestern

Energy Company Credit Agreement

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WELLS FARGO BANK, N.A., as Managing Agent

and as a Lender

By:   /s/ ANDREW J. WATSON                                 

Title:   Vice President                                            

Signature page for  the Southwestern

Energy Company Credit Agreement

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U.S. BANK NATIONAL ASSOCIATION, as Co-

Agent and as a Lender

By:   /s/ KATHRYN GAITER                                    

Title:   Vice President                                          

Signature page for  the Southwestern

Energy Company Credit Agreement

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KEYBANK NATIONAL ASSOCIATION, as Co-

Agent and as a Lender

By:   /s/ THOMAS RAJAN                                          

Title:   Senior Vice President                                  

Signature page for  the Southwestern

Energy Company Credit Agreement

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COMERICA BANK

By:   /s/ JOSH STRONG                                                

Title:   Corporate Banking Officer                            

Signature page for  the Southwestern

Energy Company Credit Agreement

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MIZUHO CORPORATE BANK, LTD.

By:   /s/ LEON MO                                                        

Title:   Senior Vice President                                    

Signature page for  the Southwestern

Energy Company Credit Agreement

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COMPASS BANK

By:  /s/ ILLEGIBLE SIGNATURE                               

Title:   Senior Vice President                                  

Signature page for  the Southwestern

Energy Company Credit Agreement

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ARVEST BANK

By:   /s/ ILLEGIBLE SIGNATURE                                

Title:   Senior Vice President                                

Signature page for  the Southwestern

Energy Company Credit Agreement

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CAPITAL ONE, N.A.

By:   /s/ PAUL D. HEIN                                                  

Title:   Vice President                                               

Signature page for  the Southwestern

Energy Company Credit Agreement

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BANK OF ARKANSAS

By:   /s/ ILLEGIBLE SIGNATURE                                  

Title:   President and CEO                                       

Signature page for  the Southwestern

Energy Company Credit Agreement

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SCHEDULE 1A
COMMITMENTS

Lender	Amount of Commitment
JPMorgan Chase Bank, N.A.	$75,000,000
SunTrust Bank	$75,000,000
Royal Bank of Canada	$70,000,000
Bank of America, N.A.	$70,000,000
The Royal Bank of Scotland plc	$70,000,000
Mizuho Corporate Bank, Ltd.	$65,000,000
BMO Capital Markets Financing, Inc.	$65,000,000
The Bank of Tokyo – Mitsubishi UFJ, Ltd. – Houston Agency	$45,000,000
Wells Fargo Bank, N.A.	$45,000,000
U.S. Bank National Association	$30,000,000
KeyBank National Association	$30,000,000
Comerica Bank	$25,000,000
Compass Bank	$25,000,000
Arvest Bank	$25,000,000
Capital One, N.A.	$25,000,000
Bank of Arkansas	$10,000,000
Aggregate Commitment	$750,000,000

1

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SCHEDULE 1B

PRICING SCHEDULE
(Applicable Margins and Rate in basis points)

Applicable Margin	Level I Status	Level II Status	Level III Status	Level IV Status	Level V Status	Level VI Status
Eurodollar Rate / Letter of Credit Fee	0.375%	0.500%	0.625%	0.875%	1.125%	1.375%
ABR	0.000%	0.000%	0.000%	0.000%	0.000%	0.000%

Applicable Fee Rate	Level I Status	Level II Status	Level III Status	Level IV Status	Level V Status	Level VI Status
Commitment Fee	0.100%	0.125%	0.150%	0.175%	0.200%	0.250%

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 corporate family rating issued by Moody’s Investors Service, Inc. and then in effect with respect to the Borrower.

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“S&P Rating” means, at any time, the corporate 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 S&P Issuer Rating.

“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.

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SCHEDULE 5.4
SUBSIDIARIES

Arkansas Western Gas Company

Southwestern Energy Production Company

SEECO, Inc.

A.W. Realty Company

Southwestern Midstream Services Company

Diamond “M” Production Company

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

Southwestern Energy Services Company, an Arkansas corporation, is 100% owned by Southwestern Midstream Services Company

DeSoto Gathering Company, L.L.C., an Arkansas limited liability company, is a subsidiary of Southwestern Midstream Services Company

Arkansas Gas Gathering Company, an Arkansas corporation, is 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, and DeSoto Drilling, Inc., an Arkansas corporation, are both 100% owned by Southwestern Energy Production Company.

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SCHEDULE 5.12
LITIGATION

None.

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SCHEDULE 5.17
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.

Indenture dated June 1, 1998 between NOARK Pipeline Finance L.L.C. and The Bank of New York, as Trustee, as supplemented by the First Supplemental Indenture dated May 2, 2006 by and between Southwestern Energy Company and UMB Bank, N.A. (as successor to The Bank of New York), as Trustee and the Second Supplemental Indenture dated as of June 30, 2006 by and between Southwestern Energy Company and UMB Bank, N.A. (as successor to The Bank of New York), as Trustee.

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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.

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EXHIBIT A
FORM OF BORROWING NOTICE

Reference is made to the Second Amended and Restated Credit Agreement dated as of February 9, 2007 (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: _______________________________________

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EXHIBIT B
FORM OF OPINION

February 9, 2007

The Administrative Agent and the Lenders who are parties to the
Second Amended and Restated 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 a Second Amended and Restated Credit Agreement dated as of February 9, 2007 (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 $1,000,000,000 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

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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, 2005 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,

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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 of 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 Second Amended and Restated Credit Agreement dated as of February 9, 2007 among the Borrower, the Lenders party thereto and JPMorgan Chase Bank, N.A., as Administrative Agent.

6.

Assigned Interest:

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Facility Assigned	Aggregate Amount of Commitment/Loans for all Lenders*	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

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[NAME OF RELEVANT PARTY]

By: ________________________________________

Title: ___________________________________

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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 Affi liates 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 n ot be “plan assets” under ERISA, (v) agrees to indemnify and hold the Assignor harmless against all 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 Agreemen t, duly completed and executed by the Assignee and (b) agrees that (i) it will, independently and without reliance on the Administrative 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

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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 Texas.

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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 ________________)

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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 JP Morgan Chase Bank, N.A.,

as Administrative Agent (the "Administrative Agent")

under the Credit Agreement

Described Below.

Re:                    Second Amended and Restated Credit Agreement, dated as of February 9, 2007 (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__________________________________

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_________________________________________                  __________________________________________

(Please Print)

Signature

(Deliver Completed Form to Credit Support Staff For Immediate Processing)

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EXHIBIT E

NOTE

[Date]

Southwestern Energy Company, a Delaware 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 Second Amended and Restated Credit Agreement dated as of February 9, 2007 (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 princ ipal of indebtedness evidenced by this Note, and, if the principal amount has been paid in full, any remaining excess shall forthwith be paid to the Borrower.

[This Note replaces and supersedes any Note issued under the Existing Agreement to the Lender or in which the Lender has been assigned an interest.]

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This Note shall be construed in accordance with the laws of the State of Texas, but giving effect to Federal laws applicable to national banks.

SOUTHWESTERN ENERGY COMPANY

By: ________________________________________

Print Name:__________________________________

Title: _______________________________________

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SCHEDULE OF LOANS AND PAYMENTS OF PRINCIPAL
TO
NOTE
OF SOUTHWESTERN ENERGY COMPANY

DATED __________, 20__

Date Principal
Amount of
Loan Maturity
of Interest
Period Principal
Amount Paid Unpaid Balance

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EXHIBIT F

FORM OF SUBSIDIARY GUARANTY

THIS SECOND AMENDED AND RESTATED SUBSIDIARY GUARANTY (this “Guaranty”) is made as of February 9, 2007 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 4, 2005 (the “Existing Subsidiary Guaranty”) to guarantee the obligations of the Company under an Amended and Restated Credit Agreement dated as of January 4, 2005 among the Company, various financial institutions and JPMorgan Chase Bank, N.A., 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.

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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 “Guarantee d Obligations”).  Upon failure by the Company to pay

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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)

 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.

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3099077v.3

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 Guar antor’s “Maximum Liability”). This Section 9(a) with respect to the Maximum Liability of the Subsidiary Guarantors is intended 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

4

3099077v.3

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 contr ibution 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 Subsidiary 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 Guarantor 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;

5

3099077v.3

(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 refu sal), 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 TEXAS.  EACH SUBSIDIARY

6

3099077v.3

GUARANTOR HEREBY SUBMITS TO THE NONEXCLUSIVE JURISDICTION OF THE UNITED STATES DISTRICT COURT FOR THE SOUTHERN DISTRICT OF TEXAS AND OF ANY TEXAS STATE COURT SITTING IN HOUSTON, TEXAS 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 TH IS 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 autho rity in accordance with applicable law, and (iii) furnish to the Agent or such Lender certified copies of official receipts evidencing payment of such withholding taxes within 30 days after such payment is made.

7

3099077v.3

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:   /s/ RICHARD F. LANE                                         

Richard F. Lane,

President, Exploration and Production

SEECO, INC.

By:   /s/ RICHARD F. LANE                                       

Richard F. Lane,

President, Exploration and Production

SOUTHWESTERN ENERGY SERVICES COMPANY

By:   /s/ TIMOTHY J. O'DONNELL                            

Timothy J. O’Donnell

Vice President, Treasurer and Assistant Secretary

8

3099077v.3

Additional Signature page for the Subsidiary Guaranty dated as of February 9, 2007 (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:

9

3099077v.3

SCHEDULE I

TO GUARANTY

ADDRESSES

SOUTHWESTERN ENERGY SERVICES COMPANY

SOUTHWESTERN ENERGY PRODUCTION COMPANY

2350 N. Sam Houston Parkway East

Suite 125

Houston, Texas 77032

SEECO, INC.

1083 Sain Street

P.O. Box 13408

Fayetteville, AR 72703-1004

10

3099077v.3

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 Second Amended and Restated Credit Agreement dated as of February 9, 2007 (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:

1

3099077v.3

Schedule I

Financial Statements
(to be attached)

1

3099077v.3

Schedule II

Compliance Calculations
(to be attached)

1

3099077v.3

Schedule III

Defaults/Remedial Action
(to be attached)

1

3099077v.3

Schedule IV

Qualifications to Representations and Warranties

1

3099077v.3

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 Second Amended and Restated Credit Agreement dated as of February 9, 2007 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: ________________________________________

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3099077v.3

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 Second Amended and Restated Credit Agreement dated as of February 9, 2007 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: _______________________________________

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3099077v.3

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 Second Amended and Restated Credit Agreement dated as of February 9, 2007 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:

3

3099077v.3

Legal name: _______________________________

Address:  

_______________________________

_______________________________

_______________________________

Attention:    _______________________________

Telephone:  (___) __________________________

Facsimile:   (___) __________________________

(B)

Payment Instructions:

Account No.:  ____________________________

At:

____________________________

____________________________

____________________________

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:______________________

4

3099077v.3

Accepted and consented to as of

______________, 20___

JPMORGAN CHASE BANK, N.A.,

  as Administrative Agent

By: _____________________________

Name: ___________________________

Title: ____________________________

5

3099077v.3

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

 Issuance

19

2.20.2

 Participations

19

2.20.3

 Issuance or Modification of Letters of Credit

19

2.20.4

 Letter of Credit Fees

20

2.20.5

 Reimbursement by Borrower

20

2.20.6

 Reimbursement by Lenders

21

3099077v.3 -i-

TABLE OF CONTENTS

(continued)

Page

2.20.7

 Obligations Absolute

21

2.20.8

 Actions of Issuer

22

2.20.9

 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

3099077v.3 -ii-

TABLE OF CONTENTS

(continued)

Page

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

Regulatory Approval

33

5.17

Negative Pledge

33

5.18

Investment Company Act

33

5.19

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

3099077v.3 -iii-

TABLE OF CONTENTS

(continued)

Page

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

3099077v.3 -iv-

TABLE OF CONTENTS

(continued)

Page

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

3099077v.3 -v-

TABLE OF CONTENTS

(continued)

Page

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

SCHEDULES
Schedule 1A

Commitments
Schedule 1B

Pricing Schedule

Schedule 5.4

Subsidiaries
Schedule 5.12

Litigation
Schedule 5.17

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

Footnotes

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.

3099077v.3 -vi-

EX-10

EXECUTION COPY

MASTER LEASE AGREEMENT

dated as of December 29, 2006

between

SUNTRUST LEASING CORPORATION

as Lessor

and

SOUTHWESTERN ENERGY COMPANY

as Lessee

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TABLE OF CONTENTS

Page

1.

LEASE OF EQUIPMENT

1

1.1

Each Schedule is a Lease

1

1.2

Closing Conditions

2

2.

TERM AND RENT

2

3.

REPRESENTATIONS, WARRANTIES AND COVENANTS OF LESSEE

3

3.1

Representations, Warranties and Covenants

3

4.

DISCLAIMER OF WARRANTIES; NO AGENCY

5

4.1

Disclaimer

5

4.2

Lessor is Not Supplier

6

5.

EXCLUSION OF CONSEQUENTIAL DAMAGES

6

5.1

NO CONSEQUENTIAL DAMAGES

6

6.

RISK OF LOSS

6

6.1

Risk of Loss

6

6.2

Total Loss

6

6.3

Stipulated Loss Value, Etc

7

6.4

Application of Proceeds

7

7.

INSURANCE

8

7.1

Required Coverages and Amounts

8

7.2

Additional Requirements

8

8.

INSTALLATION; MAINTENANCE; ADDITIONS

9

8.1

Maintenance and Repairs

9

8.2

Related Real Property Requirements

9

8.3

Additions

9

8.4

Location Reporting

10

9.

TAXES, FEES AND ASSESSMENTS

10

10.

RETURN OF EQUIPMENT

10

11.

AFFIRMATIVE AND NEGATIVE COVENANTS

11

12.

LESSEE’S IDENTITY, ADDRESS AND LOCATION

12

13.

NO ASSIGNMENT OR OTHER SUBLEASING BY LESSEE

12

14.

QUIET ENJOYMENT

13

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TABLE OF CONTENTS
(continued)

Page

15.

EVENTS OF DEFAULT

13

16.

REMEDIES

14

16.1

Remedies

14

16.2

Cumulative Remedies

15

16.3

No Waiver

15

17.

SECURITY; FILINGS

15

17.1

Granting Clause

16

17.2

Precautionary Provisions

16

17.3

Filings

16

18.

LESSOR’S FEES AND EXPENSES; INDEMNITY

16

18.1

Indemnity

16

18.2

Express Exculpation

17

18.3

Indemnity is Essential to Lessor, Etc

17

19.

INCOME TAX INDEMNITY

18

20.

WAIVERS

19

21.

PERFORMANCE BY LESSOR; FURTHER ASSURANCES

19

22.

NOTICES

19

23.

ABSOLUTE AND UNCONDITIONAL

20

24.

GOVERNING LAW

20

25.

WAIVER OF JURY TRIAL

20

26.

FORUM SELECTION AND CONSENT TO JURISDICTION

20

27.

ASSIGNMENT BY LESSOR

21

28.

MISCELLANEOUS

21

RIDER NO. 1 ENVIRONMENTAL RIDER

23

RIDER NO. 2 RETURN RIDER

24

RIDER NO. 3 REMOVAL RIDER

25

EXHIBIT 1 FORM OF SCHEDULE

26

EXHIBIT 2 FORM OF ACCEPTANCE CERTIFICATE

27

EXHIBIT 3 FORM OF ACKNOWLEDGMENT AND AGREEMENT

28

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MASTER LEASE AGREEMENT

THIS MASTER LEASE AGREEMENT is dated as of December 29, 2006 (including any and all riders, exhibits and supplements, this “Master Lease”) between SOUTHWESTERN ENERGY COMPANY, a Delaware corporation (together with its successors and assigns, “Lessee”), and SUNTRUST LEASING CORPORATION (“STLC”), a Virginia corporation (STLC, or such other party entering into any Schedule (as defined below) incorporating the terms hereof, and named as “Lessor” therein, together with their respective successors and assigns, a “Lessor”).

RECITALS

Whereas Lessee desires to lease certain drilling rigs, related property and other items of equipment, and intends to have each Lessor, (a) purchase such items of equipment, either from Lessee or directly from a supplier of such equipment and (b) lease the equipment to Lessee pursuant to Schedules entered into from time to time by the Lessor named therein incorporating this Master Lease.   

Whereas, each Lessor is willing to enter into a Lease or Leases (as defined below) on the terms and conditions set forth herein, and in the related Schedule, and Lessee is willing to enter into the Leases on such terms and conditions.

Now, Therefore, for such good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the parties hereto agree as follows:

1.

Lease of Equipment.  

1.1

Each Schedule is a Lease.  Subject to the terms of each schedule, substantially in the form of Exhibit 1 attached hereto, executed by Lessee and a Lessor (together with all exhibits, riders and attachments thereto, each, a “Schedule”), and incorporating the terms of this Master Lease by reference therein (collectively, a “Lease”), each Lessor hereby leases to Lessee and Lessee hereby leases from such Lessor that certain drilling rig and those spare parts identified in the related Schedule (together with all accessories, attachments, parts, repairs, additions, upgrades and accessions thereto and all replacements and substitutions therefor, the “Equipment”).  The term “Lessor”, in each place used herein or in any other related document, instrument or agreement with respect to the Lease created by any Schedule, shall mean the party entering into and named in the Schedule as “Lessor” (i.e., either STLC or its designee), or any successors and assigns of such Lessor.  Lessee acknowledges and agrees that, unless a Schedule expressly provides to the contrary, each Lease is a “Finance Lease” as defined by the Uniform Commercial Code (the “UCC”).

1.2

Closing Conditions.  Each Lessor's agreement to purchase and lease any Equipment under a Lease is conditioned upon such Lessor's determination that all of the following have been satisfied with respect to such Lease prior to the proposed effective date thereof:  

(a)

Such Lessor’s having received the following, in form and substance reasonably satisfactory to such Lessor: (i) evidence as to due compliance with the insurance provisions of Sections 7.1 and 7.2 of this Master Lease; (ii) if requested with sufficient notice, lien searches in the jurisdictions of Lessee’s and DeSoto Drilling, Inc. (“DDI”) respective organization, and wherever else such Lessor deems appropriate; (iii) UCC financing statements and all other filings required by such Lessor; (iv) a certificate of an appropriate officer of each of Lessee and DDI, certifying: (A) resolutions duly authorizing the transactions contemplated in the applicable Lease Documents (as defined in Section 3.2(b)) and any Relevant Third Party Document (as defined below), (B) the incumbency and signature of the officers of Lessee and DDI, authorized to execute such documents; and (C) if requested by su ch Lessor, the accuracy and completeness of the attached copies of Lessee’s organizational documents; (v) if requested by such Lessor, an opinion of counsel for Lessee as to certain of the matters set forth in Section 3.1(a) through (e) of this Master Lease under Texas law, Delaware corporate law, and certain federal law, as more particularly referenced therein; (vi) the only manually executed original of each of the related

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Schedule, and Acceptance Certificate (as defined in Section 3.1(g)), and counterpart originals of all other related Lease Documents and Relevant Third Party Documents; (vii) all purchase documents pertaining to the related Equipment (collectively, the "Supply Contract") and, if such Lessor is purchasing the Equipment from Lessee, bills of sale, assignments of warranties, lien releases, and such other documents, instruments and agreements reasonably requested by such Lessor in connection with such purchase (the vendor and any other seller of the Equipment, a “Supplier”); (viii) if requested by such Lessor, good standing certificates from the jurisdictions of Lessee’s and DDI’s respective organization and the state in which the Equipment is located, and evidence of Lessee’s and DDI’s organizational numbers; and (ix) such other documents, agreements, instruments, certificates, opinions, and assurances, as such Lessor reasonably may require.  For the purposes hereof: (a) “Relevant Third Party” shall mean (i) any Permitted Operator (as defined in Section 13), or (ii) DDI (itself, as well as being successor by merger to PV Exploration Company); and (b) “Relevant Third Party Document” shall mean any of the following to which a Relevant Third Party is a party, (i) any bills of sale or other purchase documents relating to the Equipment, (ii) any Use Agreement, and/or (iii) the Acknowledgment and Agreement (as defined in Section 13) and any and all other documents, instruments, filings, assurances or deductibles entered into or provided to a Lessor in connection with a Lease.

(b)

All representations and warranties provided by Lessee and/or Permitted Operator in favor of a Lessor herein, in any Lease, or in any related Lease Documents or Relevant Third Party Documents, to which Lessee is a party, shall be true and correct on the effective date of the related Acceptance Certificate (and Lessee's execution and delivery of the Acceptance Certificate, shall constitute its acknowledgment of the same).  

(c)

There shall be no Event of Default under such Lease. The related Equipment shall have been delivered to and accepted by Lessee, as evidenced by an Acceptance Certificate, and shall be in the condition and repair required hereby and thereby; and on the effective date of such Acceptance Certificate, the Lessor under such Lease shall have received good title to the related Equipment described therein, free and clear of any Liens, except for any Permitted Liens.  For the purposes hereof, “Permitted Lien” means (i) Liens for taxes, assessments or other governmental charges that are either not delinquent or being contested in good faith by appropriate proceedings so long as such proceedings do not involve any material danger of the sale, forfeiture or loss of the Equipment or any material part thereof, or a Lessor’s rights, title or interests with respect thereto, (ii) suppliers’, m echanics’, materialmen’s, workers’, repairmen’s, landlords’, operators’, drillers’, carriers’, employees’ or other like Liens arising after the Acceptance Date in the ordinary course of Lessee’s business and for amounts the payment of which is either not yet delinquent or is being contested in good faith by appropriate proceedings, so long as such proceedings do not involve any material danger of the sale, forfeiture or loss of the Equipment or any material part thereof, or Lessor’s rights, title or interests with respect thereto, (iii) salvage or similar rights of insurers under insurance policies maintained pursuant to Section 7.1 hereof, (iv) Liens arising out of any judgment against Lessee which has been fully bonded, (v) the rights of a Permitted Operator under a Use Agreement, (vi) Lessor Liens, and (vii) the respective rights of Lessor and Lessee under such Lease.

2.

Term and Rent.  Equipment described in a Schedule shall be leased for a term (the “Term”) that shall commence on the date stated in such Schedule and continue for the period stated therein, including any extension or renewal periods as provided in the End of Term Option Rider executed by Lessee and the Lessor thereunder in connection with such Schedule, except as sooner terminated by Lessee’s exercise of its rights under the Early Purchase Rider executed by Lessee and such Lessor, or otherwise terminated or cancelled, in each case, in accordance with any other provision hereof, or of such Lease or any of the other related Lease Documents.  Lessee shall pay the Lessor the rental payments in the aggregate amounts specified in each Schedule to which it is a party, without notice or prior demand, and all other amounts payable pursuant to the related Lease (collectively,  7;Rent”).  If any Rent shall be unpaid five (5) days after the due date thereof, Lessee shall pay on demand a late charge equal to 5% of any such unpaid Rent but in no event to exceed the maximum lawful charges.  EACH LEASE IS NONCANCELABLE BY LESSEE FOR ITS ENTIRE TERM, and Lessee has no right of termination or purchase of any Equipment except as specifically granted to Lessee in a Schedule (including any rider thereto).  Upon the expiration of the Term respecting the Equipment, and until the return to the applicable

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Lessor of all such Equipment in accordance with the terms of the Lease applicable thereto, or until any purchase option with respect thereto is exercised in accordance with the terms of the Lease applicable thereto, at the option of the Lessor thereunder, in its sole discretion, such Lease shall remain effective and shall become a month-to-month lease between the parties with respect to such Equipment on the same terms and conditions of such Lease and the monthly Rent in effect immediately prior to such expiration shall be the monthly Rent payable during such month-to-month term under the applicable Schedule.

3.

Representations and Warranties of Lessee.  

3.1

Representations and Warranties.  Lessee represents and warrants to each Lessor on the date hereof and the date of the Schedule to which such Lessor is a party that:  

(a)

Lessee is a corporation, duly organized and validly existing in good standing under the laws of the jurisdiction of its organization (as specified in the first sentence of this Master Lease), duly qualified to do business in each jurisdiction (i) where any Equipment subject to such Schedule is, or is to be, located or (ii) in which the failure to be so qualified, singly or in the aggregate, could reasonably be expected to have a Material Adverse Effect (as defined under Section 3.1(d)) and has full power and authority to hold property under lease and to enter into and perform its obligations hereunder and under that Lease.  

(b)

 Lessee is fully authorized to execute and deliver this Master Lease and each Schedule, and each of the documents, instruments and agreements entered into pursuant to or contemplated by this Master Lease, or in connection with such Schedule, including the Acceptance Certificate, Acknowledgment and Agreement, any RE Waivers, bills of sale, certificates, filings and other related assurances and deliverables (collectively with the Schedule, and solely as they relate to such Schedule, the “Lease Documents”) to which Lessee is a party delivered by it, under an appropriate resolution or resolutions of its governing body and by any other appropriate official approval.   

(c)

This Master Lease and such Lease and each related Lease Document and any Relevant Third Party Document have been duly executed and delivered by Lessee and any Relevant Third Party, to the extent each is a party thereto, and this Master Lease, such Lease and each related Lease Document and any Relevant Third Party Document constitute, legal, valid and binding obligations of Lessee and any Relevant Third Party, enforceable against Lessee and any Relevant Third Party in accordance with their respective terms, except as enforceability may be limited by bankruptcy, insolvency or similar laws affecting creditors’ rights generally (although none of such laws is or shall be applicable to Lessee or any Relevant Third Party on the date hereof, or on the date of any Schedule, whether prior to, upon, or by reason of such party’s entering into and/or becoming bound to pay and perform its obligations under, this Master Lease, any such Schedule, or other related Lease Document or Relevant Third Party Document), and by general principles of equity.  

(d)

The execution, delivery and performance by Lessee of this Master Lease and such Lease, and all related Lease Documents to which it is a party, do not violate any law or governmental rule, regulation, or order applicable to Lessee or any provision of Lessee’s organizational documents, do not and will not contravene any provision of, or constitute a default under, any indenture, mortgage, contract, or other instrument to which it is bound which could reasonably be expected to have a Material Adverse Effect and do not and will not result in the creation of any lien, charge, security interest, encumbrance or other charge or claim (any of the same, a “Lien”) on all or any part of the Equipment leased thereby other than as retained by, created and/or granted in favor of such Lessor under a Lease.  As used herein, “Material Adverse Effect” shall mean (i) a mat erially adverse effect on the business, condition (financial or otherwise), operations, performance or properties of Lessee and its subsidiaries, taken as a whole, (ii) a material impairment of Lessee’s ability to perform its financial obligations under such Lease or any related Lease Document or (iii) any material impairment of the validity or enforceability of this Master Lease, such Lease or any related Lease Document or the rights and remedies available to such Lessor thereunder.

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(e)

There is no action, suit, proceeding, claim, inquiry or investigation, at law or in equity, before or by any court, regulatory agency, public board or body pending or, to the best of Lessee’s knowledge, threatened against Lessee, challenging Lessee’s authority to enter into this Master Lease, or such Lease or any related Lease Document or any other action wherein an unfavorable ruling or finding could reasonably be expected to have, a Material Adverse Effect.  

(f)

No consent or authorization of, filing with, or any other act by or in respect of any person (for the purposes hereof, “person” shall mean any individual or business entity, as the context may require) is required in connection with the execution, delivery, performance or validity of this Master Lease, the Lease or any Lease Document to which Lessee is a party other than leases, titles, concessions, bonds, deposits, permits, licenses, easements and/or rights-of-way, approvals or consents, in respect of or by any local, state, federal or other governmental authority or agency, that have already been obtained or, as appropriate, shall have been obtained on or before the effective date of the related Lease.  

(g)

As of the date of each Schedule, Lessee has accepted the related Equipment pursuant to a certificate of acceptance delivered to such Lessor and substantially similar in form and substance to Exhibit 2 (an “Acceptance Certificate”) and, on each occasion, and without regard as to how situated on or attached to any real property, such Equipment is personal property and is removable from and is not essential to the premises at which it is located.  

(h)

The consolidated financial statements of Lessee for the fiscal year ended December 31, 2005 contained in its annual report on Form 10-K, and the consolidated financial statements of Lessee for the fiscal quarters ended March 31, 2006, June 30, 2006, and September 30, 2006, contained in Lessee's quarterly reports on Forms 10-Q for such quarterly periods, present fairly in all material respects the financial position and the results of operations and cash flows of the Company and its consolidated subsidiaries, at the indicated dates and for the indicated periods.  Such consolidated financial statements have been prepared in accordance with U.S. generally accepted principles of accounting, consistently applied throughout the periods involved, except as disclosed therein.  

(i)

Lessee’s residence for federal income tax purposes, Lessee’s “location” for purposes of Article 9 of the applicable UCC and its organizational identification number are as set forth below its signature hereto.  

(j)

Lessee’s correct legal name is as set forth on the execution page hereof.  

(k)

Any Lease or any other Lease Documents deemed to create a security interest and/or other Lien creates a valid first priority Lien on the related Equipment subject to no other Lien (other than any Permitted Lien), and upon the filing by such Lessor of financing statements pursuant to Section 17 hereof, such Lessor will have a valid and perfected security interest in the Equipment and any other Lien retained, created or granted with respect thereto, subject to no other Lien other than Permitted Liens.  

(l)

Effective as of the payment of the purchase price therefor on the Acceptance Date, such Lessor shall have good and marketable title to the Equipment leased under such Lease, free and clear of all Liens, except for any Permitted Liens, whether purchased from Lessee or any third party supplier.  

(m)

Lessee is in compliance with all Applicable Requirements.  For the purposes hereof, “Applicable Requirements” shall mean, to the extent applicable, any and all of the following: (i) all maintenance and operating manuals or service agreements, whenever furnished or entered into, including any subsequent amendments or replacements thereof, issued by the manufacturer or service provider, to the extent disseminated to all customers, (ii) the requirements, terms and conditions of all applicable insurance policies, (iii) the Supply Contract or the original purchase agreement with the manufacturer, so as to preserve all of Lessee’s and such Lessor’s rights thereunder, including all rights to any warranties, indemnities or other rights or remedies, (iv) all Applicable Laws, and (v) all prudent

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industry standards and practices (including any of the same as determined by the American Petroleum Institute (API)), in existence from time to time for the purposes for which it was designed, but in any event, to no lesser standard than that employed by Lessee for comparable equipment owned or leased by it.  For the purposes hereof, “Applicable Laws”, shall mean all applicable legal requirements, including without limitation the applicable statutes, treaties, conventions, judgments, decrees, injunctions, writs and orders of any court, governmental agency or authority and rules, regulations, orders, directives, licenses and permits of any governmental body, instrumentality, agency or authority as amended and revised, and any judicial or administrative interpretation, of any of the same, relating to such Lease or any related Lease Document or Relevant Third Party Document, Lessee, any Permitted Operator, o r any party using, operating, possessing or having any right, title or interest in, or with respect to any of the Equipment  leased under such Lease, or any real property on which any of the Equipment is then located, including, without limitation, any Environmental Law (as defined in the Environmental Rider attached hereto as Rider No. 1, the terms of which are hereby incorporated herein; the “Environmental Rider”), or any other similar municipal, state or federal law or regulation.

(n)

Lessee has paid or withheld or caused to be paid or withheld, all federal, state and local taxes required to be paid or withheld by it, and Lessee has filed all federal, state and local tax returns which are required to be filed by Lessee, if in each such case, failing to do so has resulted or could result in a Material Adverse Effect.  

(o)

No factual information furnished by Lessee in connection with the entering into of this Master Lease or any Lease, relating to the transactions contemplated herein or therein, contains any material misstatement of fact or omitted to state a material fact necessary to make the statements contained therein not misleading.  

(p)

Lessee is not engaged principally, nor does it engage as one of its important activities, in the business of extending credit for the purpose of purchasing or carrying “margin stock” (as provided in F.R.S. Board Regulation T, U or X or any regulations substituted therefor, as from time to time in effect), and none of the proceeds of any Lease will be used in any manner to enable or assist any person in, directly or indirectly, purchasing or carrying “margin stock.”  

4.

Disclaimer of Warranties; No Agency.  

4.1

Disclaimer.  Lessee acknowledges that no Lessor is the manufacturer of the Equipment, the manufacturer’s agent or a dealer therein; the Equipment is of a size, design, capacity, description and manufacture selected by Lessee; Lessee is satisfied that all licenses and rights necessary to install, use and operate the Equipment have been obtained and that the Equipment is suitable and fit for its purposes; and THE EQUIPMENT IS LEASED HEREUNDER “AS IS, WHERE IS” AND WITH ALL FAULTS, AND NO LESSOR HAS MADE, NOR DOES ANY LESSOR MAKE, AND EACH LESSOR SPECIFICALLY DISCLAIMS, ANY WARRANTY OR REPRESENTATION WHATSOEVER, EITHER EXPRESS OR IMPLIED AND ALL OTHER WARRANTIES OTHERWISE ARISING BY OPERATION OF LAW, AS TO THE FITNESS, CONDITION, MERCHANTABILITY, DESIGN, OPERABILITY, OPERATION OR PERFORMANCE OF THE EQUIPMENT, ITS FITNESS FOR ANY PARTICULAR PURPOSE, THE QUALITY OR CAPACITY OF THE MATERIALS IN THE EQUIPMENT OR WORKMANSHIP IN THE EQUIPMENT, THE CONFORMITY OF THE EQUIPMENT TO ANY OF THE APPLICABLE REQUIREMENTS, SUCH LESSOR’S TITLE TO THE EQUIPMENT AND RIGHTS TO USE AND OPERATE THE EQUIPMENT NOR ANY OTHER REPRESENTATION OR WARRANTY WHATSOEVER; no Lessor shall be liable to Lessee, and Lessee hereby releases and discharges each Lessor, for any loss, damage, or expense of any kind or nature caused, directly or indirectly, by the Equipment or the use or maintenance thereof or the failure or operation thereof, or the repair, service or adjustment thereof, or by any delay or failure to provide any such maintenance, repairs, service or adjustment, or by any interruption of service or loss of use thereof or for any loss of business howsoever caused.  No defect or unfitness of the Equipment shall relieve Lessee of the obligation to pay any Rent or perform any other obligation under any Lease.  No Lessor shall have any obligation under a Lease in respect of the Equipment lea sed thereunder or any obligation to ship, deliver, assemble, install, erect, test, adjust or service such Equipment.  Each Lessor agrees that until an Event of Default (as defined in

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Section 15) or an event which with lapse of time or notice, or both, might become an Event of Default hereunder (a “Default”) has occurred, such Lessor will permit Lessee, as Lessee’s sole and exclusive remedy hereunder, to enforce in Lessee’s own name and at Lessee’s sole expense any Supplier’s or manufacturer’s warranty or agreement in respect of such Equipment to the extent that such warranty or agreement is assignable.

4.2

Lessor is Not Supplier.  Lessee acknowledges and agrees that none of the manufacturer, the Supplier or any salesman, representative or other agent of the manufacturer or the Supplier is an agent of any Lessor.  No salesman, representative or agent of the manufacturer or the Supplier is authorized to waive or alter any term or condition of any Lease, and no representation as to the Equipment or any other matter by the manufacturer or the Supplier shall in any way affect Lessee’s duty to pay Rent and perform its other obligations as set forth in a Lease.

5.

Exclusion of Consequential Damages.  

5.1

NO CONSEQUENTIAL DAMAGES.  NOTWITHSTANDING ANYTHING TO THE CONTRARY CONTAINED IN ANY LEASE, NO LESSOR SHALL, UNDER ANY CIRCUMSTANCES, BE LIABLE TO LESSEE OR ANY THIRD PARTY, FOR CONSEQUENTIAL, INCIDENTAL, SPECIAL OR EXEMPLARY OR PUNITIVE DAMAGES ARISING OUT OF OR RELATED TO THE EQUIPMENT OR ANY TRANSACTION CONTEMPLATED UNDER ANY LEASE, WHETHER IN AN ACTION BASED ON CONTRACT, TORT (INCLUDING NEGLIGENCE OR STRICT LIABILITY) PATENT INFRINGEMENT, BREACH OF WARRANTY, MISREPRESENTATION OR THE NEGLIGENT ACTS OR OMISSIONS OF LESSEE OR ANY OTHER LEGAL THEORY, INCLUDING, BUT NOT LIMITED TO, LOSS OF ANTICIPATED PROFITS OR BENEFITS OF USE OR LOSS OF BUSINESS, BUSINESS INTERRUPTION, LOSS OF REVENUES, OR PRODUCT, LOSS BY REASON OF SHUTDOWN, NON-OPERATION, OR INCREASED EXPENSE OF MAINTENANCE OR OPERATION, INCREASED EXPENSES OF BORROWING, FINANCING, LOSS OF PRODUCTIVITY OR LOSS OF SHOP SPACE, EVEN IF SUCH LESSOR IS APPRISED OF THE LIKELIHOOD OF SUCH DAMAGES OCCURRING.  Without limiting the foregoing, no Lessor will be responsible to Lessee or any other person with respect to, and Lessee agrees to bear sole responsibility for, any risk or other matter that is the subject of any Lessor’s disclaimer; and each Lessor's agreement to enter into this Master Lease and any Lease or Schedule is in reliance upon the freedom from and complete negation of liability or responsibility for the matters so waived or disclaimed herein or covered by the indemnity in this Lease.  

6.

Risk of Loss.  

6.1

Risk of Loss.  At all times until all of the Equipment is returned to and accepted by the applicable Lessor in accordance with the related Lease, Lessee shall bear the risk of loss, theft, confiscation, taking, unavailability, damage or partial destruction of any or all of the Equipment and shall not be released from its obligations under any Lease or any related Lease Document in any such event. Lessee shall provide prompt written notice to such Lessor of any Total Loss or any material damage to any Equipment (including any Component Part or Spare Part (as hereinafter defined)) leased under such Lease.  Any such notice must be provided together with any damage reports provided to any governmental authority, the insurer or Supplier, and any documents pertaining to the repair of such damage, including copies of work orders, and all invoices for related charges. Without limiting any other provision hereof, Lessee shall repair all damage to any Equipment (including any Component Part or Spare Part (as hereinafter defined)) from any and all causes, other than a Total Loss, so as to cause it to be in the condition and repair required by the related Lease.  

6.2

Total Loss.  

(a)

The parties hereby agree as follows:

(i) For the purposes of this Section 6, as incorporated into each Lease,

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(A) a “Drilling Rig” shall mean that certain drilling rig identified in the related Schedule, comprised of the Component Parts and other related property described in such Schedule as being a part of or used in connection with such drilling rig,

(B) a “Spare Part,” shall mean each item of Equipment identified as a “spare part” on the related Schedule and other related property described in such Schedule as being a part of or used in connection with such spare part,

(C) a “Component Part” shall mean each of the components of the Drilling Rig specified in the related Schedule as being a part of such Drilling Rig, and other related property described in such Schedule as being a part of or used in connection with such Component Part, and

(D) each of the above defined terms shall also be deemed to include all accessories, attachments, parts, repairs, additions, upgrades and accessions to the property described in the definition and all replacements and substitutions therefor.

(ii) For the purposes hereof, (A) the occurrence of a Total Loss, at any time, of or relating to less than all of the Component Parts of the Drilling Rig leased under any Lease having an aggregate Stipulated Loss Value, determined as of the preceding rent payment date, not exceeding fifteen percent (15.00%) of the Stipulated Loss Value, as of such date, of all of the Component Parts comprising such Drilling Rig shall constitute a Total Loss of only such Component Parts, shall be deemed a Total Loss solely of each such Component Part suffering a Total Loss, and in such event Lessee shall replace such Component Parts in accordance with Section 6.4; and (B) the occurrence a Total Loss, at any time, with respect to Component Parts having an aggregate Stipulated Loss Value, determined as of the preceding rent payment date, equal to or exceeding fifteen percent (15.00%) of the Stipulated Loss Value, as of such dat e, of all of the Component Parts comprising such Drilling Rig shall constitute a Total Loss of such Drilling Rig, and in such event, Lessee shall pay the amounts and otherwise comply with Section 6.3.  

(iii) Notwithstanding the provisions of subparagraph (ii) above, or any shorter grace periods provided for in the definition of “Total Loss” in Section 6.2(b), Lessee may avoid having the occurrence described in subparagraph (ii) being deemed a Total Loss with respect to the related Drilling Rig by replacing the Component Parts having suffered an immediate Total Loss, or a Potential Loss (as defined below) within sixty (60) days of the occurrence of such immediate Total Loss, or Potential Loss, as the case may be, or if earlier, at the expiration or earlier termination or cancellation of the related Lease.  Any such replacement must be made in accordance with the provisions of Section 6.4 (except that the 60 day period set forth therein will run from the date of the Potential Loss, if applicable), and Lessee’s right to make such replacement shall be further conditioned upon the aggregate Stipulated Loss Value of all such Component Parts having suffered such Total Loss or Potential Loss, as the case may be, determined as of the preceding rent payment date, being less than twenty five percent (25.00%) of the Stipulated Loss Value, as of such date, of all of the Component Parts comprising such Drilling Rig.  For the purposes hereof, a “Potential Loss” shall mean an event or occurrence described in the definition of Total Loss that, with the passage of time without cure could be deemed a Total Loss. Upon the occurrence of a Total Loss of any Spare Part, Lessee shall replace such Spare Part in accordance with Section 6.4.

(b)

A “Total Loss” shall be deemed to have occurred with respect to a Drilling Rig, any Spare Part or any Component Part, as the case may be, upon: (i) any damage thereto that results in an insurance settlement with respect to such Drilling Rig, Spare Part or Component Part, as the case may be, on the basis of a total loss or constructive total loss thereof, (ii) (A) the loss, disappearance, or theft thereof that continues to exist for a period of 45 days, or if earlier, at the expiration or earlier termination or cancellation of such Lease, (B) the destruction of such Drilling Rig, Spare Part or Component Part, as the case may be, or (C) damage to such Drilling Rig, Spare Part or Component Part, as the case may be, that is either (1) uneconomical to repair or (2) renders it unfit for normal use, and it remains unfit for normal use for a period of 90 days, or if earlier, at the expirat ion or earlier termination or cancellation of

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such Lease, (iii) the return of such Drilling Rig, Spare Part or Component Part, as the case may be, to the manufacturer (other than for any scheduled or ordinary maintenance with respect thereto), (iv) the condemnation, confiscation, requisition, seizure, forfeiture or other taking of title to or, if not a taking of title, any other non-permanent taking, including a taking of use thereof, that continues to exist for a period of 90 days, or if earlier, at the expiration or earlier termination or cancellation of such Lease, or the imposition of any Lien thereon (other than Permitted Liens) by any governmental authority, (v) as a result of any rule, regulation, order or other action by any governmental authority, the use of any such Drilling Rig, Spare Part or Component Part, as the case may be, shall have been prohibited, or it shall have been declared unfit for use, for a period of six (6) consecutive months, un less Lessee, prior to the expiration of the six-month period, shall have undertaken and, in the reasonable opinion of the Lessor of such Drilling Rig, Spare Part or Component Part, as the case may be, shall be diligently carrying forward all steps which are necessary or desirable to permit the normal use thereof by Lessee or, in any event, if use shall have been prohibited, or such property shall have been declared unfit for use, for a period of twelve (12) consecutive months (unless waived by the Lessor thereof, in its sole and absolute discretion) or such prohibition shall exist on the expiration or earlier cancellation or termination of the related Lease or (vi) at the election of the Lessor of such Drilling Rig, Spare Part or Component Part, as the case may be, any RE Interest Holder (as defined in Section 8.2) shall deny Lessee or Lessor the right to de-install and/or remove any such Drilling Rig, Spare Part or Component Part, or shall assert or have any Lien, claim or other right against or with respec t thereto, and (A) an Event of Default shall have occurred and then exist or (B) such denial, Lien, claim or right has not been effectively, unconditionally and irrevocably waived by such RE Interest Holder on the earlier of the tenth (10th) business day after such event has occurred, or the expiration, or earlier cancellation or termination of the Term of the related Lease.   

6.3

Stipulated Loss Value, Etc.  On the next rent payment date under any Lease following a Total Loss of a Drilling Rig leased thereunder (a “Loss Payment Date”), Lessee shall pay to the Lessor thereof (i) any rental payment due on that date pursuant to such Lease, plus (ii) the Stipulated Loss Value of the Drilling Rig with respect to which the Total Loss has occurred (“Lost Drilling Rig”), plus (iii) any other Rent due under such Lease and the related Lease Documents to which Lessee is a party with respect to any such Lost Drilling Rig.  Upon making such payment, (i) Lessee’s obligation to pay future Rent shall terminate solely with respect to any Lost Drilling Rig so paid for, but Lessee shall remain liable for, and pay as and when due, all other Rent due and payable to such Lessor pursuant to such Lease, and (ii) the Les sor under such Lease shall convey to Lessee all of such Lessor’s right, title and interest in any such Lost Drilling Rig on an AS IS, WHERE IS BASIS (as defined in Section 8.1), but subject to any rights or interests of any other party, including without limitation, any RE Interest Holder, any governmental authority and/or the requirements of any third party insurance carrier in order to settle an insurance claim.  As used herein or in any other Lease Document with respect to any Lease, “Stipulated Loss Value” shall mean the product of the Original Equipment Cost of any Lost Drilling Rig leased thereunder, multiplied by the percentage factor applicable to the Loss Payment Date, as set forth on the schedule of Stipulated Loss Values attached to the related Schedule.  After the final rent payment date of the original term or any renewal term of a Lease, the Stipulated Loss Value shall be determined as of the last rent payment date during the applicable term of such Lease, and the applicable percentage factor shall be the last percentage factor set forth on the schedule of Stipulated Loss Values attached to the related Schedule.  No Lessor shall be under any duty to Lessee to pursue any claim against any person in connection with a Total Loss or other loss or damage.  

6.4

Spare Parts and Component Parts.  The parties agree that upon a Total Loss with respect to any Component Part leased under a Lease (but not the Drilling Rig on which it was installed), or any Spare Parts leased under a Lease,

(a) if such Component Part or Spare Part constitutes a “Removed Part” for the purposes of the Removal Rider, Lessee shall comply with all of the provisions of the Removal Rider with respect to such Removed Part; or

(b)  if such Component Part or Spare Part does not constitute a Removed Part, no later than the Last Replacement Date, Lessee shall replace such Component Part or Spare Part, as the case may be, with a new or reconditioned replacement component part or spare part, which such replacement

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component part or spare part shall be free and clear of all Liens (other than Permitted Liens) and which shall have a fair market value, utility and remaining use life at least equal to the replaced Component Part or Spare Part, as the case may be (assuming such replaced Component Part or Spare Part, as the case may be, was in the condition required by the related Lease).  For the purposes hereof, the “Last Replacement Date” shall mean, with respect to any Component Part or Spare Part required to be replaced pursuant to this Section 6.4(b), that certain date that is the earlier of (i) 60 days after the Total Loss is deemed to have occurred with respect to such Component Part or Spare Part, as the case may be, or (ii) the date on which such Component Part or Spare Part is required to be returned to the Lessor pursuant to the applicable provisions of the related Lease.  Any such replacement of the Comp onent Part shall be done in accordance with all Applicable Requirements, and, after giving effect thereto, each of the related Drilling Rig and replacement Component Part shall comply with all Applicable Requirements and the other provisions of the related Lease and other Lease Documents.  Any such replacement spare part shall be in compliance with all Applicable Requirements, and the other provisions of the related Lease and other Lease Documents. Lessee shall be deemed to have conveyed or caused to be conveyed to such Lessor good and marketable title to each replacement component part or spare part, as the case may be, and each shall be subject to the provisions of the related Lease, and thereafter, such replacement component part shall be a “Component Part” or “Spare Part,” as the case may be, for all purposes of the related Lease.  Lessee agrees to execute and/or deliver any bills of sale, amendments to the related Schedule, filings or other assurances reasonab ly requested by such Lessor in connection with such replacement, and shall be responsible for and pay, and reimburse Lessor for, any taxes or costs relating to any such removal, and any temporary or permanent replacement of parts or components pursuant hereto.

6.5

Application of Proceeds.  If a Lessor receives a payment under an insurance policy required under a Lease in connection with any Total Loss or other loss of or damage to any of the Equipment leased under a Lease, and such payment is both unconditional and indefeasible, then provided Lessee shall have complied with the applicable provisions of this Section, such Lessor shall either (i) if received pursuant to a Total Loss of any Drilling Rig, Spare Part or Component Part, remit such proceeds to Lessee up to an amount equal to the amount paid by Lessee to such Lessor as the Stipulated Loss Value, or credit such proceeds against any amounts owed by Lessee pursuant to Section 6.3, or (ii) if received with respect to repairs made pursuant to Section 6.1 or replacements of Component Parts or Spare Parts pursuant to Section 6.4 (and solely with respect to any replacements of a Removed Part, the Removal Rider), remit such proceeds to Lessee up to an amount equal to the amount of the costs of such repair or replacement, as the case may be, actually incurred by Lessee, as established to such Lessor’s satisfaction.  Any excess insurance proceeds shall be returned to Lessee, so long as no Event of Default and no Default has occurred and is continuing under the affected Lease.  In the event that during the Term of any Lease the use of any Drilling Rig, Spare Part or Component Part leased thereunder is requisitioned or taken by any governmental authority under the power of eminent domain or otherwise for a period which does not constitute a Total Loss, Lessee’s obligation to pay all installments of Rent with respect to such Drilling Rig, Spare Part or Component Part shall continue for the duration of such requisitioning or taking.  Lessee shall be entitled to receive and retain for its own account all sums payable for any such period by such governmental authority as compensation for requisition or taking of possession.  Any amount referred to herein which is payable to Lessee shall not be paid to Lessee, or if it has previously been paid directly to Lessee, shall not be retained by Lessee, if at the time of such payment an Event of Default or a Default under the affected Lease shall have occurred and is continuing, but shall be paid to and held by the Lessor under such Lease as security for the obligations of Lessee under such Lease, and at such time as there shall not be continuing any such Default or Event of Default, such amount shall be paid to Lessee.

7.

Insurance.  

7.1

Required Coverages and Amounts.  Lessee shall procure and maintain, at its sole cost and expense during the Term of each Lease, insurance policies containing the following coverages: (a) All Risk Property Insurance covering loss of or damage to the Equipment leased thereunder, including debris removal; (b) Sue and Labor Expense; (c) Bringing Under Control Expense; (d) Pollution Liability Insurance covering personal injury and bodily injury, including death, and loss of (including loss of use

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subject to the policy terms, conditions and exclusions) or damage to (including cleanup of) property of any kind or description arising out of seepage, pollution or contamination; and (e) General Liability Insurance (including products and completed operations and contractual liability) covering personal injury and bodily injury, including death, and loss of (including loss of use subject to the policy terms, conditions and exclusions) or damage to property of any kind or description caused by an occurrence.  The amount of any coverage obtained and maintained pursuant to clause (a) of the preceding sentence with respect to any Equipment leased under a Lease shall be a stated value policy in a minimum amount that is no less than the Stipulated Loss Value of such Equipment, determined as of the Rent payment date next preceding the date of determination.  The amount of any coverage obtained and maintained pursuant to ea ch of clauses (b) through (e) of the preceding sentence in connection with any Lease shall be no less than $10,000,000, per occurrence.

7.2

Additional Requirements.  Prior to acceptance of the Equipment by Lessee, Lessee shall furnish to the Lessor thereof certificates, policies or endorsements satisfactory to such Lessor evidencing the insurance coverages required under Section 7.1.  Subsequent to acceptance of the Equipment, Lessee shall, before the expiration date of the current policies and endorsements, provide the Lessor thereof with renewal certificates, policies or endorsements complying with the requirements of Section 7.1.  All insurance policies required in Section 7.1 with respect to such Lease shall (i) with respect to all risk property insurance on the related Equipment, name the Lessor thereof as an Additional Insured and a sole Loss Payee; (ii) with respect to all other coverages required under Section 7.1, name such Lessor as an Additional Insured as its interest may appear; (iii) be in a form and amount rea sonably satisfactory to such Lessor (but in no event less than the minimum policy amounts specified Section 7.1), and written by insurers of recognized reputation and responsibility satisfactory to such Lessor (at a minimum; such insurer shall carry a current Financial Strength Rating by A.M. Best Company of at least “A”), (iv) include a severability of interest clause providing that such policy shall operate in the same manner as if there were a separate policy covering each insured, (v) waive any rights of subrogation against such Lessor, (vi) provide that with respect to the interests of such Lessor in such policies, the insurance shall not be invalidated by any action or inaction of Lessee or any other person operating or in possession of any of the Equipment leased under such Lease regardless of any breach or violation of any warranties, declarations or conditions contained in such policies by or binding upon Lessee or any other person operating or in possession of any of such Equipment, (vii) be primary and without any right of contribution with respect to any insurance maintained by the Lessor under such Lease, (viii) provide that the insurer will give such Lessor at least thirty (30) days prior written notice of any cancellation of such insurance (ten days for non-payment of premium).  The insurance policies required under Section 7.1 shall provide that all insurance proceeds payable thereunder shall be payable in U.S. Dollars.  The policies required under Section 7.1 shall not, without Lessor’s consent, contain self insured retentions, deductibles or co-insurance requirements, except, so long as no Event of Default then exists, (A) the policy described in Section 7.1(a) may be subject to deductibles and/or self-insurance retentions in an amount not to exceed $1,000,000, per occurrence, and (B) the policies described in Sections 7.1 (b) through (e) shall be subject to deductibles and/or self-insurance retentions in an amount not to exceed $1,000,000, per occurrence.  T o the extent any self insured retention or co-insurance requirement with respect to a Lease is expressly permitted pursuant hereto, Lessee shall be solely responsible for the satisfaction and payment of any self insured retention, deductible or co-insurance obligation contained in the insurance policies required in Section 7.1.  Failure of any Lessor to enforce Lessee’s obligations under this Section 7.2 to provide proof of the required insurances, or to otherwise confirm that the required insurances are in place and maintained, shall not constitute a waiver of any of Lessee’s obligations under Sections 7.1 or 7.2.

8.

Installation; Maintenance; Additions.  

8.1

  Maintenance and Repairs.  Lessee shall, at its sole expense, install, maintain, preserve, protect and keep the Equipment in good repair, condition and working order and in compliance with all Applicable Requirements, except for any unintentional non-compliance with any Applicable Requirements, where failure to do so could reasonably be expected to have a Material Adverse Effect or, the effect of which could reasonably be expected to result in a Material Risk.  For the purposes hereof, a “Material Risk” means (i) any impairment of any of Lessor’s rights, title or interests in, any Lien (other than a Permitted Liens) against, or the  diminution of the then fair market value or anticipated residual

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value or useful life of any of the Equipment (ordinary wear and tear from proper use alone excepted, and assuming that the Equipment is in the condition required by the Lease), or (ii) any (A) material civil liability of any Lessor or any other Indemnified Party, (B) civil liability of any Lessor or any other Indemnified Party for which a Lessor or an Indemnified Party is not indemnified (after giving effect to any exclusions in the applicable indemnity) or the indemnification with respect thereto is limited or prohibited by Applicable Law, or (C) criminal liability of any Lessor or any other Indemnified Party.  Lessee shall make necessary and proper repairs and furnish any and all parts, mechanisms and devices required to keep the Equipment in the condition required by the first sentence of this Section 8.1, at the sole cost and expense of Lessee, including any ordinary or capital or extraordinary repairs and replacement s of any parts of the Equipment which become worn out, lost, destroyed, damaged beyond repair or otherwise unfit for use, by new or reconditioned replacement parts which are free and clear of all Liens (other than Permitted Liens) and have a value, utility and remaining useful life at least equal to the parts replaced (assuming that they were in the condition required by the Lease).  Good title to any and all such replacement parts shall be deemed conveyed to the Lessor under such Lease and constitute a part of the Equipment and leased by such Lessor to Lessee under the related Lease, and replaced parts shall be deemed conveyed to Lessee, AS IS, WHERE IS, without recourse to or warranty from any Lessor, express or implied, other than as to the absence of Lessor’s Liens (“AS IS, WHERE IS BASIS”) in each case, without further action. For the purposes hereof, the term “Lessor’s Liens” shall mean the Liens arising by, through or under such Lessor (including but not limited to (i) claims against such Lessor not related to the transactions contemplated by the related Lease, (ii) Liens directly resulting from Lessor ’s breach of any of its agreements expressly set forth in a Lease, which are not indemnified against by Lessee or any Relevant Third Party pursuant to a Lease or any related Lease Document, and (iii) taxes imposed against a Lessor, except for those taxes the liability for which has been expressly excluded in Sections 9 and 19 of this Master Lease. Lessee shall ensure that Equipment and/or component performance monitoring and recording devices shall be continuously maintained and fully operational. Lessee shall keep performance, utilization, inspection, maintenance and repair data, records and reports in proper order and in sufficient detail to establish an historical record relating to the use, operation, maintenance, damage, repair and rebuilds to the Equipment.  The provisions of this Section 8.1 are supplemented, and as and to the extent inconsistent with, modified by, the Removal Rider attached to this Master Lease as Rider No. 3, and incorporated herein as a part of this Master Lease (“Removal Rider”).

8.2

Related Real Property Requirements.  Lessee, at its sole expense, shall enter into and maintain in force, for the entire Term with respect to the subject Equipment, any installation or maintenance contracts required by the manufacturer, Supplier or any insurer of the Equipment, and shall provide to the Lessor of such Equipment a copy of such contract and all supplements thereto.  Lessee, at its sole expense shall secure all leases, titles, concessions, bonds, deposits, permits, licenses, easements and rights-of-way necessary from time to time for the transportation, installation, operation, maintenance, repair and future removal of each item of such Equipment, or in conformity with (1) any  Applicable Requirement, the breach of which could reasonably be expected to result in any Material Adverse Event or Material Risk , or (2) the right or purported right of any person, whether by contract, deed, lease, license, or other instrument, agreement or document, or arising under any Applicable Law, the breach of which could reasonably be expected to result in any Material Adverse Event or Material Risk.  Without limiting the foregoing, a Lessor may require that Lessee obtain an RE Waiver from any and all RE Interest Holders having an interest in the real property at which any Equipment leased by such Lessor is then located or to be relocated from time to time, provided, however, no such RE Waiver shall be required unless: (a) a Default or an Event of Default shall have occurred and is continuing with respect to the related Lease, (b) any RE Interest Holder has asserted, or attempted to establish, record, perfect, take possession or control of, or exercise any rights or remedy against, any such Equipment, or (c) such RE Interest Holder is an Affiliate of Lessee. For the purposes hereof, (i) an “RE Interest Holder ” shall mean any party owning, controlling, or holding any Lien or other right, title or interest in the real property at which any Equipment is, then located (and thereby susceptible to any such Lien, right, title or interest), whether a governmental authority, person or entity, (ii) an “RE Waiver” shall mean a waiver, disclaimer and recognition agreement, duly executed by such RE Interest Holder, in form and having terms and conditions acceptable to the Lessor of such Equipment, pursuant to which such RE Interest Holder effectively agrees that, among other things, (A) such Lessor may have access to, and the right to remove and/or store the related Equipment at such location, without regard as to (1) how and whether such item

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is attached to the related real property, and (2) the purported or actual rights, title or interests of any RE Interest Holder, to, in or with respect to the real property and (B) it effectively releases, waives and disclaims any Lien, or other right, title or interest in, against or with respect to such Equipment, or any rights, property or proceeds relating thereto and/or other collateral securing Lessee’s obligations under the related Lease, and (iii) an “Affiliate” of Lessee or Lessor, as used herein, shall mean a person, firm or entity controlling, controlled by or under common control with such party.

8.3

Additions.  Lessee shall not attach or install anything in or on any Equipment that could impair the originally intended function or use of such Equipment unless the Lessor thereof has provided its prior written consent (such consent not to be unreasonably withheld, delayed or conditioned).  Except as expressly permitted hereunder or under any related Lease, Lessee shall not attach or incorporate the Equipment to or in any other property in such a manner that the Equipment may be deemed to have become an accession to or a part of such other property. Lessee shall make all additions and modifications as and when required by all applicable requirements (“Required Additions”) and may make all other additions and modifications it so elects as and to the extent such other additions and modifications do not impair the fair market value or anticipated residual vale, or origin ally intended function or utility, of the Equipment to which it is to be attached, are readily removable without harm to such Equipment, and are in all respects consistent with the applicable Lease (“Other Additions”).  All Required Additions and Other Additions while attached, shall become part of the Equipment subject to all terms and conditions of the related Lease and subject to the interest of the Lessor thereunder.  Any Required Additions and Other Additions shall be made only in compliance with this Master Lease, the related Lease Documents and Applicable Law.  Without the prior written consent of the Lessor thereof, Lessee shall not attach or install any Equipment to or in any other personal property so as to constitute an “accession” under applicable commercial law.  The Equipment is, and shall at all times be and remain, personal property notwithstanding that the Equipment or any part thereof may now be, or hereafter become, in any manner affixe d or attached to, or imbedded in, or permanently resting upon, real property or any building thereon.  

8.4

Location Reporting.  Lessee agrees that, with respect to each Lease, Lessee will deliver to the Lessor thereunder a report in form and substance reasonably acceptable to such Lessor, and signed by Lessee’s authorized signatory, detailing the locations at which the Equipment leased under such Lease was located since the Acceptance Date of such Equipment, or after the first such report, since the date of the previous such report.  Each such report will be delivered to such Lessor (i) on May 1, 2007 and each consecutive anniversary of such date, or (if after the occurrence and during the existence of a Default, or Event of Default or if in connection with such Lessor’s compliance with any Applicable Requirement or such Lessor’s filing or reporting any tax or other assessment) within five (5) business days after Lessor’s request therefor, and (ii) on the date on wh ich the related Equipment is to be returned in accordance with the related Lease.

9.

Taxes, Fees and Assessments.  Lessee agrees to (i) pay when due or reimburse such Lessor, and on a net after tax basis, indemnify and defend such Lessor against,  all fees, assessments and sales, use, property, excise and other taxes and governmental charges, including, without limitation, interest and penalties now and hereafter imposed by any federal, foreign, state or local governmental body or agency upon any Equipment leased by such Lessor, or the use thereof; (ii) if required by law, file and pay (and copy Lessor on such filings and payments) in a timely manner any tax returns and informational statements required by any federal, state and/or local governmental agency with respect to taxes payable under this Section 9; and (iii) provide evidence of payment of the related taxes and charges to the applicable Lessor.  Lessee agrees to provide all necessary and timely informatio n  requested by a Lessor in connection with its filing or reporting with any governmental authority with respect to taxes payable under this Section 9; provided, that at least 15 days prior to any assessment date with respect to such taxes the Lessee will provide the Lessor with the location of the Equipment and otherwise shall provide Lessor with the location of the Equipment from time to time as Lessor shall request.  

Notwithstanding anything to the contrary in this Section 9, the foregoing indemnity shall not apply to (i) any withholding taxes imposed on gross income by the United States of America which are imposed on a Person considered to be a non-U.S. Person for purposes of such tax, (ii) any taxes or other impositions

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based on any Lessor’s net income, branch profits (imposed by the United States of America), capital,  net worth, capital stock, or taxes that are, or are in the nature of, business or franchise taxes (including for this purpose the Texas franchise tax), or (iii) any tax for which Lessee is obligated to indemnify Lessor pursuant to Section 19 of this Lease (such taxes and impositions described in clauses (i), (ii) and (iii) being collectively referred to herein as “Excluded Taxes”).  

If any Lessor receives any refund, credit, or deduction from any taxing authority to which such Lessor would not be entitled but for payments by Lessee under this Section, such Lessor shall repay to Lessee the amount of such refund, credit, or deduction.

All of Lessor’s rights and privileges and indemnities contained in this Section shall survive the expiration or other termination of any Lease.

10.

Return of Equipment.  Lessee hereby agrees as follows with respect to its obligation to return to each Lessor the Equipment leased under each Lease to which such Lessor is a party, as and when required pursuant to such Lease and any related Lease Documents:

(a)

At the expiration or earlier termination of any Term, unless Lessee purchases the related Equipment or renews the Lease in accordance with the terms of such Lease, Lessee shall, at Lessee’s risk and expense, perform any testing and repairs required to place the units of Equipment in the same condition and appearance as when received by Lessee (reasonable wear and tear under proper use and maintenance excepted) and in the condition required by the first sentence of Section 8.1 and Return Rider No. 2.  If required by the Lessor under such Lease, the units of Equipment shall be deinstalled, disassembled and crated by an authorized manufacturer’s representative or such other service person as is reasonably satisfactory to such Lessor.  Lessee shall remove installed markings that are not necessary for the operation, maintenance or repair of the Equipment.  Upon such Lessor 6;s demand, Lessee shall remove all Other Additions, including all parts, supplies, upgrades, accessories and equipment furnished, attached or installed in, on or to any Equipment, and shall repair all damage to the Equipment caused by such removal so as to restore such Equipment to the condition which existed prior to installation of such Other Additions and as required by this Master Lease.  All Equipment shall be cleaned and in such condition as to be immediately installed into use by a third-party end user in a similar environment for which the Equipment was originally intended to be used without the need for repairs or refurbishment.  All waste material and fluid must be removed from the Equipment and disposed of in accordance with then current waste disposal laws, and all other Applicable Laws.  Lessee shall return the units of Equipment to a location within the United States as the Lessor thereof shall direct, but in no event to any location more than 1,000 miles from Houston, Texas. &n bsp;Lessee shall obtain and pay for a policy of transit insurance for the redelivery period in an amount equal to the replacement value of the Equipment.  The transit insurance shall name the Lessor of such Equipment as insurance committee to decide a loss payee.  Lessee shall pay for all costs to comply with this subsection (a).

(b)

Until Lessee has fully complied with the requirements of subsection (a) above, Lessee’s Rent payment obligations with respect to the subject Equipment and all other obligations under the related Lease with respect thereto shall continue from month to month notwithstanding any expiration or termination of the related Term, and the Lessor thereof may terminate Lessee’s right to use the Equipment upon 30 days notice, to Lessee.

(c)

Lessee shall provide to the Lessor thereof a detailed inventory of all components of the Equipment including model and serial numbers.  Lessee shall also provide an up-to-date copy of all other documentation pertaining to the Equipment.  All service manuals, blue prints, process flow diagrams, operating manuals, inventory and maintenance records shall be given to such Lessor at least 90 days and not more than 120 days prior to expiration or termination of the related Term.

(d)

Lessee shall make the Equipment available for on-site operational inspections by potential purchasers at their own risk and expense at least 120 days prior to and continuing up to the expiration or termination of the related Term.  The Lessor of such Equipment shall provide Lessee with reasonable notice prior to any inspection, but no less than three (3) business days notice, except that no

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such prior notice shall be required if an Event of Default under the related Lease is then existing.  Lessee shall provide personnel, power and other requirements necessary to demonstrate electrical, hydraulic and mechanical systems for the Equipment.

(e)

Lessee shall perform and comply with any supplemental maintenance requirements set forth in the Return Rider (attached hereto as Rider No. 2, and incorporated by reference as a part hereof; the “Return Rider”).  If any provision of the Return Rider is inconsistent with any of the provisions hereof, the specific provisions of the  Return Rider, to the extent so inconsistent, shall supersede the inconsistent provisions hereof. Lessee’s obligation to return, and a Lessor’s right to recover all of the items of Equipment as and when, and in accordance with each Lease and the related Lease Documents to which Lessee is a party, are of the essence of this Master Lease and each Lease.

11.

Affirmative and Negative Covenants.  Lessee covenants and agrees as follows:  

(a)

Lessee shall comply with, and cause the Equipment to comply with, all Applicable Requirements, including without limitation, all governmental laws, regulations, requirements, rules to the extent related to any Lease, to any of the Equipment and the installation and operation thereof, the real property at which any of the Equipment shall there be located, including but not limited to the EPAct 2005, the Energy Policy and Conservation Act as amended from time to time, which singly or in the aggregate could reasonably be expected to have a Material Adverse Effect or result in a Material Risk.  

(b)

Lessee shall, upon the request of the Lessor thereof, mark and identify the Equipment with all information and in such manner as such Lessor may reasonably request from time to time and replace promptly any such markings or identification which are removed, defaced or destroyed.  

(c)

Lessee shall at all reasonable times and intervals during business hours grant the Lessor of such Equipment and any of its representatives (including outside auditors) free access to, or otherwise ensure such Lessor free access to, (i) ingress and egress with respect to the related real property, (ii) enter upon the premises wherein the Equipment shall be located or used and permit such Lessor to inspect the Equipment, and all performance, utilization, inspection, maintenance and repair reports and to make copies and take extracts from such records and reports and (iii) examine and audit its books and records (including computer records) relating to the Equipment and any Lease to which such Lessor is a party.  

(d)

Lessee shall not create, incur, assume or suffer to exist any Lien affecting or with respect to any of the Equipment (other than Permitted Liens).  

(e)

Lessee shall not make any changes or alterations in or to the Equipment except as necessary for compliance with, or expressly, permitted by, Section 8 hereof.  

(f)

Lessee or its Permitted Operator shall possess and control each of the items of Equipment and shall not change the location of the Equipment or any part thereof from the address or location shown on the related Schedule without complying with Section 8 hereof.  

(g)

The Equipment will remain personal property and will at all times be used for commercial or business purposes.

(h)

Lessee shall deliver to the Lessor of such Equipment each of the following with respect to such Lessor’s Lease and the Equipment leased thereunder: (i) promptly, but in no event later than 10 days after a responsible officer of Lessee learns (or in the exercise of reasonable diligence should have learned) of any Lien (other than Permitted Liens) that has attached to any Equipment, notice of the full particulars of such Lien (to the extent known to Lessee), (ii) as soon as practicable but in no event later than 90 days after the closing of each fiscal year of Lessee, its complete financial statements, prepared in accordance with generally accepted accounting principles applied consistently with past

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periods and certified by nationally recognized and reputable independent certified public accountants, and upon request of such Lessor, as soon as practicable but in no event later than 60 days after close of each of Lessee’s fiscal quarter, copies of its quarterly financial report prepared in accordance with generally accepted accounting principles applied consistently with past periods and certified by Lessee’s chief financial officer, provided, however, Lessee shall be deemed to have complied with the foregoing requirements if it files Forms 10-K and 10-Q with the Securities and Exchange Commission (“SEC”) that are publicly available within the time frames set forth above, (iii) promptly, but in no event later than 15 days after the occurrence thereof, notice of any loss or damage to any Equipment (where the estimated repairs costs would exceed 10% of the Original Equipment Cost) or any accid ent involving the Equipment causing personal injury or material property damage, and (iv) promptly but in no event later than three (3) business days after a responsible officer of Lessee learns (or in the exercise of reasonable diligence should have learned) of the occurrence  thereof, notice of any Default or Event of Default and a statement of Lessee setting forth reasonably detailed information regarding such Default or Event of Default and the actions that Lessee has taken or proposes to take with respect thereto.

(i)

Lessee shall maintain its corporate existence, except that Lessee may merge or consolidate with or sell all of its assets to any other solvent corporation, if (i) the surviving, continuing or resulting corporation (if not Lessee) shall (x) expressly assume by a written instrument reasonably satisfactory to Lessor (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 Rent and the due performance and observance of all covenants, conditions and agreements on the part of Lessee under this Master Lease, each Lease and all of the other Lease Documents to which Lessee is a party, (y) deliver to Lessor an opinion of counsel, in form and substance reasonably satisfactory to Lessor, to the effect that such written instrument has been duly authorized, 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 Lessor 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 Event of Default would exist; provided, however, that Lessee may sell, lease or otherwise dispose of any of its assets to any person, for a consideration which represents the fair value thereof at the time of such sale, lease or other disposition, if (x) immediately after such sale, lease or other disposition, no Default or Event of Default would exist; and (y) in any one fiscal year, the fair value of the assets sold, leased or otherwise disposed of does not exceed fifteen percent (15%) of Lessee’s consolidated assets as at the beginning of such fiscal year. Notwithstanding the proviso in the preceding sentence, Lessee shall not assign, sell, transfer, encumber or in any way dispose of all or any part of its rights or obligations under this Master Lease or any Lease or any of the Equipment, except as permitted by Section 13 hereof.

(j)

Lessee shall take, and cause any Relevant Third Party to take all actions, including if necessary by entering into or obtaining, as the case may be, any and all pertinent leases, titles, concessions, bonds, deposits, permits, licenses or easements and/or rights-of-way, approvals or consents, in respect of or by any local, state, federal or other governmental authority or agency, or any other  person or entity, if then required with respect to (i) the leasing, subleasing, or other disposition of any Equipment, or (ii) the use, transportation, installation, operation, maintenance, repair, access to and future removal or recovery and disposition of each item of property constituting the Equipment, in each case wherever such Equipment shall be located from time to time.  

12.

Lessee’s Identity, Address and Location.  Except pursuant to a transaction permitted by Section 11(i), Lessee shall not change its name, address, organizational identification number, if any, or location for purposes of Section 9-307 of the applicable UCC from that set forth below its signature hereto, unless it shall have given Lessor or its assigns no less than 30 days’ prior written notice.

13.

No Assignment or Other Subleasing by Lessee.  Unless Lessee is itself operating the Equipment pursuant to and in accordance with a Lease, Lessee shall enter into to a use agreement (the

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“Use Agreement”) with a Permitted Operator.  For the purposes hereof, a “Permitted Operator” shall be, at the time of determination, (a) a domestic, solvent business organization, that is an Affiliate of Lessee, (b) having all necessary licenses, permits and other approvals and authorizations required to comply with all Applicable Law, and the applicable provisions of the related Lease (including this Master Lease as incorporated therein), and (c) provided that the applicable Lessor executes and delivers the same, a party to a valid, binding and enforceable Acknowledgment and Agreement (as defined below).  Lessee agrees that, with respect to each Use Agreement, (a) such Use Agreement shall (i) not a grant any property interest, including any leasehold or security interest under applicable commercial law, including the UCC, (ii) be expressly subject and subordinate to the related Leas e and the rights of the Lessor thereunder, and under the other related Lease Documents (including as to the Equipment subject to such Use Agreement), (iii) not permit any further disposition by the Permitted Operator, (iv) not be inconsistent with the provisions of the related Lease or cause Lessee to breach any of its representations, warranties or agreements under the related Lease, and (v) otherwise conform to any Acknowledgment and Agreement entered into by Lessee, Permitted Operator and such Lessor concurrently therewith; and (b) Lessee shall enter into, and cause Permitted Operator to enter into, concurrently therewith, an Acknowledgment and Agreement, with and in favor of Lessor, having substantially the same form and substance as Exhibit 3 attached hereto (each, an “Acknowledgment and Agreement”).  Lessor agrees that it will enter into any Acknowledgment and Agreement entered into by Lessee and any Permitted Operator conforming to the requirements of this Section 13.  Any o bligations under this Master Lease or any Lease may be delegated to a Permitted Operator with respect to the related Equipment, but no such delegation by Lessee will reduce any of the obligations of Lessee or the rights of Lessor under and with respect to the related Lease and Lease Documents, and all of the obligations of Lessee hereunder and thereunder shall be and remain primary and shall continue in full force and effect as the obligations of a principal and not of a guarantor or surety.   EXCEPT AS PERMITTED BY THIS SECTION, LESSEE SHALL NOT ASSIGN, SELL, TRANSFER, ENCUMBER OR IN ANY WAY DISPOSE OF ALL OR ANY PART OF ITS RIGHTS OR OBLIGATIONS UNDER THIS MASTER LEASE OR ANY LEASE OR ANY OF THE EQUIPMENT WITHOUT THE PRIOR WRITTEN CONSENT OF THE LESSOR THEREOF, AND LESSEE SHALL NOT ENTER INTO ANY SUBLEASE OF ALL OR ANY PART OF THE EQUIPMENT WITHOUT THE PRIOR WRITTEN CONSENT OF THE LESSOR THEREOF.  

14.

Quiet Enjoyment.  So long as no Event of Default shall have occurred, Lessee shall lawfully and quietly hold, occupy and enjoy the Equipment (subject to the provisions of this Master Lease) during the term of each Lease without interference by the Lessor party thereto or by any person or persons claiming under such Lessor.

15.

Events of Default.  Each of the following events or occurrences shall constitute an “Event of Default” under a Lease (but solely as it relates to such Lease), and under this Master Lease, but only as and to the extent incorporated into the Schedule relating to such Lease:  

(a)

Lessee fails to pay to such Lessor any installment of Rent or other payment required under such Lease or any related Lease Document when due and payable, by acceleration or otherwise, and such failure continues for a period of 10 calendar days;

(b)

any representation or warranty of Lessee made in such Lease or any related Lease Document or any other certificate or instrument delivered by Lessee in connection with this Master Lease shall be materially incorrect or misleading when made;

(c)

Lessee fails to perform any of its obligations under Section 6, 7, 11(d), 11(h)(iv) or 11(i), 12 or 13;

(d)

Lessee fails to perform or observe any other covenant, condition or agreement to be performed or observed by it under such Lease or under any related Lease Document, and such failure or breach shall continue unremedied for a period of 30 days after Lessee has received notice by Lessor thereof;  

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(e)

The occurrence of an event of default under any other Lease between Lessee and such Lessor;  

(f)

Lessee or any Permitted Operator shall be or become insolvent, or admit in writing its inability to pay its debts as they mature, or make an assignment for the benefit of creditors; or Lessee or any Permitted Operator shall apply for or consent to the appointment of any receiver, trustee or similar officer for it or for all or any substantial part of its property; or such receiver, trustee or similar officer shall be appointed without the application or consent of Lessee or any Permitted Operator, and the same remains in effect for 60 consecutive days; or Lessee or any Permitted Operator shall institute (by petition, application, answer, consent or otherwise) any bankruptcy, insolvency, reorganization, arrangement, readjustment of debt, dissolution, liquidation or similar proceeding relating to it under the laws of any jurisdiction; or any such proceeding shall be instituted (by petition, application or othe rwise) against Lessee or any Permitted Operator; and the same remains in effect for 60 consecutive days;

(g)

any Permitted Operator shall fail to perform when due or within any applicable period of grace, and taking into account any waiver or forbearance by the applicable Lessor, any of such Permitted Operator’s obligations under the applicable Use Agreement, or the applicable Acknowledgment and Agreement, or any Permitted Operator shall repudiate any of such obligations;

(h)

the occurrence of an event of default (however defined, and taking into account any waiver, forbearance, or similar limitations or modifications of such last effective agreement or agreements) under any instrument, agreement or other document evidencing or relating to, and the acceleration of, any indebtedness or other monetary obligation of Lessee, either (i) having a principal amount, in the aggregate, in excess of $50,000,000, or (ii) connected with that certain Amended and Restated Credit Agreement dated January 4, 2005, among the Lessee, the lender parties identified therein, JP Morgan 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, as the same may be amended from time to time, or any financing facility extended to Lessee in replacement thereof (the “Facil ity”); provided, however, in the event of a termination of the Facility, unless and until it is replaced with a facility that is substantially similar to, or more favorable than, the Facility (taking into account, among other things, the covenants and events of default provided therein), any event that would have constituted a “default” or “event of default” under the last effective agreement or agreements, collectively constituting the Facility (and taking into account any waivers, forbearances or similar limitations or modifications of such last effective agreement or agreements that have the effect of amending such agreement or agreements), shall constitute an Event of Default for the purposes of this clause (h);

(i)

the occurrence of any event that, when taken together with all other events that have occurred, could reasonably be expected to result in liability of Lessee under Title IV of the Employee Retirement Income Security Act of 1974, as amended (and including any related regulation then in effect) that would have a Material Adverse Effect;

(j)

any Lease Document or any Lien granted thereunder shall (except in accordance with its terms), in whole or in part, terminate, cease to be effective or cease to be the legally valid, binding and enforceable obligation of Lessee;

(k)

Lessee or any Permitted Operator shall contest in writing the effectiveness, validity, binding nature or enforceability of any Lease or any other Lease Document or any applicable Use Agreement or applicable Acknowledgment and Agreement; and/or

(l)

any Lien securing (or required to secure) any of Lessee’s obligations shall, in whole or in part, cease to be a first priority perfected Lien.

The occurrence of an Event of Default under any Lease or group of Leases held by a single Lessor shall not prevent Lessee from exercising any right, power or privilege under any Lease or Leases (including this Master Lease as incorporated into the Schedule or Schedules relating thereto) held

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by any other Lessor or any other related Lease Document (including but not limited to any Early Purchase Option).

16.

Remedies.  

16.1

Remedies.  Following the occurrence of any Event of Default and while the same shall be continuing, any Lessor may, with or without cancelling any or all Leases held by such Lessor, in its sole discretion, do any one or more of the following:

(a)

upon written notice to Lessee, cancel any or all Leases held by such Lessor;

(b)

declare immediately due and payable all sums due and to become due under any or all Leases held by such Lessor for the full Term respecting the Equipment subject to such Leases (including any renewal or purchase options which Lessee has contracted to pay);

(c)

with or without terminating any or all Leases held by such Lessor, demand and recover all Liquidated Damages (as defined in subsection (h) below) and all other payments then due hereunder, whereupon Lessee shall promptly pay the same;

(d)

with or without notice to Lessee, (i) repossess the Equipment leased by such Lessor wherever found, with or without legal process, and for this purpose such Lessor and/or its agents may peaceably enter upon any premises of or under the control or jurisdiction of Lessee or any agent of such Lessee, without liability for suit, action or other proceeding by Lessee (any damages occasioned by such repossession being hereby expressly waived by Lessee to the extent permitted by Applicable Law) and remove the Equipment therefrom, and (ii) without limiting the foregoing, terminate or cancel the related Use Agreement, without regard as to the existence of any event of default thereunder and recover, or cause Lessee and/or Permitted Operator to relinquish possession and return any and all items of Equipment leased under the related Lease, pursuant to this Section 16, and/or exercise any and all other reme dies under or with respect to the Acknowledgment and Agreement;

(e)

require Lessee to return the Equipment leased by such Lessor in accordance with Section 10(a) and the Return Rider;

(f)

re-lease, sell or otherwise dispose of any or all of the Equipment leased by such Lessor, whether or not in such Lessor’s possession, at a public or private sale on such terms and notice as such Lessor shall deem reasonable (such sale may, at such Lessor’s sole option, be conducted at Lessee’s premises); or

(g)

exercise any other right or remedy which may be available to it under the applicable UCC or any other applicable law.

(h)

As used herein, “Liquidated Damages” shall mean the liquidated damages (all of which, Lessee hereby acknowledges, are damages to be paid in lieu of future monthly rent (the “Basic Rent”) and are reasonable in light of the anticipated harm arising by reason of an Event of Default, and are not a penalty) described in the first sentence of parts (i) or (ii) of this subsection (h), depending upon the recovery and disposition of the Equipment leased under the applicable Lease.

(i)

 If an Event of Default occurs with respect to any Lease, if Lessor recovers the Equipment and disposes of it by a lease or elects not to dispose of the Equipment after recovery upon demand, Lessee shall pay to such Lessor an amount equal to the sum of (A) any accrued and unpaid Rent as of the date such Lessor recovers possession of the Equipment, plus (B) the present value as of such date of the total Basic Rent for the then remaining term of such Lease, minus (C) either, as applicable, (1) the present value, as of the commencement date of any substantially similar re-lease of the Equipment, of the re-lease rent payable for that period, commencing on such date, which is comparable to the then remaining term of such Lease or (2) the present value, as of that certain date

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which may be determined by taking into account Lessor's having a reasonable opportunity to remarket the Equipment, of the “market rent” for such Equipment (as computed pursuant to UCC-2A) in the continental United States on that date, computed for that period, commencing on such date, which is comparable to the then remaining term of such Lease. Any amounts discounted to present value, shall be discounted at the rate of four and one-half percent (4.5%) per annum, compounded annually.

(ii)

If Lessee fails to return the Equipment in the manner and condition required by this Lease, or such Lessor  recovers and sells the Equipment, upon demand, Lessee shall pay to such Lessor  an amount calculated as the Stipulated Loss Value of the Equipment (determined as of the next rent payment date after the date of the occurrence of the subject Event of Default), together with all other Rent due with respect to the related Lease as of such determination date, and all enforcement costs, less a credit for any disposition proceeds, if applicable pursuant to the application provisions in the next sentence.  If such Lessor demands the liquidated damages under this part (ii), and recovers and sells the Equipment, any proceeds received in good and indefeasible funds shall be applied by such Lessor, with respect to the related Lease: first, to pay all enforcement costs, to the extent not previously p aid; second, to pay to such Lessor an amount equal to any accrued and unpaid Rent then due and payable, together with the liquidated damage amounts specified in this part (ii), to the extent not previously paid; third, to pay to such Lessor any interest accruing on the amounts covered by the preceding clauses, at a per annum rate that is equal to the lesser of (i) 18% and (ii) the highest rate permitted by Applicable Law (the “Default Rate”), from and after the date the same becomes due, through the date of payment; and fourth, (A) if the Lessor under such Lease is also the Lessor under any other Leases (whether by retaining the same, or as assignee), to satisfy any remaining obligations under any or all such other Leases, or (B) if such Lessor is not the Lessor under any other Lease, or if Lessee’s obligations to such Lessor under such other Leases have been fully and indefeasibly satisfied, to reimburse Lessee for such amounts to the extent paid by Lessee as liquidated damages pursuan t to this part (ii).

16.2

Cumulative Remedies.  The foregoing remedies are cumulative, and any or all thereof may be exercised instead of or in addition to each other or any other remedies at law or in equity.  Lessee waives notice of sale or other disposition (and the time and place thereof), and the manner and place of advertising.  Lessee shall pay each Lessor’s actual attorney’s fees incurred in connection with the enforcement, assertion, defense or preservation of Lessor’s rights and remedies under this Master Lease or a Lease or if prohibited by law, such lesser amount as may be permitted.

16.3

No Waiver.  No waiver of any Default or any Event of Default shall be effective unless in writing and executed by Lessor.  Waiver of any Default or any Event of Default shall not be deemed a waiver of any other or subsequent Default or Event of Default.

16.4

Effect of Cancellation.  A cancellation of a Lease shall occur only upon written notice by the Lessor thereunder and only as to such Lease as such Lessor specifically elects to cancel and all other Leases not included in any such notice of cancellation shall continue in full force and effect.

17.

Security; Filings.   

17.1

Granting Clause.  In order to secure the prompt payment of the Rent and all of the other amounts from time to time outstanding with respect hereto and to each Lease, and the performance and observance by Lessee of all of the provisions thereof and of all of the other related Lease Documents, Lessee hereby collaterally assigns, grants, and conveys to the Lessor under each such Lease to which it is then a party (whether originally named therein and retained, or by assignment), a security interest in and lien on all of Lessee’s right, title and interest in and to all of the following (whether now existing or hereafter created, and including any other collateral described on any rider hereto; the “Collateral”): (i) (if contrary to the parties’ intentions a court determines that such Lease is not a true “lease” under the UCC) the Equipment described in such Lease or otherwise covered thereby (including all inventory, fixtures or other property comprising the Equipment), together with all related software (embedded therein or otherwise) and general intangibles, all additions, attachments, accessories and accessions thereto whether or not furnished by the Supplier; (ii) any subleases, chattel paper, accounts, security deposits,

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and general intangibles relating thereto, and any and all substitutions, replacements or exchanges for any such Equipment or other collateral, in each such case in which Lessee shall from time to time acquire an interest; and (iii) any and all related insurance and/or other proceeds of the Equipment and other collateral in and against which a security interest is granted hereunder.  The collateral assignment, security interest and lien granted herein shall survive the termination, cancellation or expiration of each Lease held by such Lessor until such time as Lessee’s obligations thereunder (other than inchoate indemnity obligations) are fully and indefeasibly discharged.

17.2

Precautionary Provisions.  If contrary to the parties’ intentions a court determines that any Lease is not a true “lease”, the parties agree that in such event Lessee agrees that: (i) with respect to the related Equipment, in addition to all of the other rights and remedies available to the Lessor under or with respect to the related Lease, upon the occurrence of an Event of Default during the continuation thereof, such Lessor shall have all of the rights and remedies of a first priority secured party under the UCC; and (ii) any obligation to pay Rent or any other payment, to the extent constituting the payment of interest, shall be at an interest rate that is equal to the lesser of the maximum lawful rate permitted by applicable law or the effective interest rate used by Lessor in calculating such amounts.

17.3

Filings.  Each Lessor is authorized to file one or more UCC financing statements, precautionary or otherwise, as appropriate, disclosing such Lessor’s interest in the Equipment, a Lease and the sums due under a Lease, without the signature of Lessee or signed by such Lessor as attorney-in-fact for Lessee.  Lessee hereby appoints such Lessor (and any of such Lessor’s officers, employees, or agents designated by such Lessor) as Lessee’s attorney, coupled with an interest, to do all things necessary to carry out this paragraph.  Lessee hereby waives any right that Lessee may have to file with the applicable filing officer, and agrees that it shall not file or authorize the filing of, any financing statement, amendment, termination or other record pertaining to the Equipment leased by such Lessor and/or such Lessor’s interest therein, except as authorized by such Lessor i n writing.  Lessee shall pay all costs of filing any financing, continuation or termination statements with respect to a Lease and the Equipment leased thereunder, including, without limitation, any intangibles tax and/or documentary stamp taxes relating thereto.  Lessee shall do whatever may be necessary to have a statement of the interest of a Lessor in the Equipment noted on any certificate of title relating to the Equipment and shall deliver said certificate to such Lessor.

18.

Lessor’s Fees and Expenses; Indemnity.  

18.1

Indemnity.  Lessee shall reimburse each Lessor for all charges, out-of-pocket costs and expenses and attorneys’ fees and expenses, reasonably incurred by such Lessor, on a net after-tax basis, in connection with (a) defending or protecting its interests in the Equipment, (b) the execution, delivery, administration, amendment or enforcement of this Master Lease or any Lease to which such Lessor is a party or the collection of any installment of Rent under such Lease, and (c) any lawsuit or other legal proceeding to which this Master Lease or any Lease to which such Lessor is a party or any Equipment leased under such Lease is related, including, without limitation, actions in tort.  Lessee shall indemnify, defend and hold each Lessor, its permitted successors and assigns, and their respective officers, directors, employees, Affiliates and agents (individually and collective , the “Indemnified Parties”) harmless from and against all claims, actions, losses, liabilities (including negligence, tort and strict liability), damages, penalties, judgments, suits and all legal proceedings and any and all costs and expenses and disbursement of whatsoever kind and nature, imposed on, incurred by or asserted against such Indemnified Party (a “Claim”) in connection therewith (including reasonable attorneys’ fees and expenses) that in any way relate to or arise out of any of this Master Lease, any Lease to which such Lessor is a party, or any related Lease Document, the transactions contemplated thereby or the Equipment leased thereby, including, without limitation, (i) the selection, manufacture, purchase, financing, acceptance or rejection of such Equipment, (ii) the ownership of such Equipment, (iii) the delivery, nondelivery, installation, lease, possession, maintenance, use, condition, repair, return, operation or disposition of such Equipment; and without limiting the foregoing, any event or circumstance relating to the real property or personal property to which, or on which, any item of such Equipment may become located and/or attached from time to time, (iv) the condition of such Equipment sold or otherwise disposed of after possession by Lessee, (v) any patent, copyright or trademark infringement, (vi) any act

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or omission on the part of Lessee, any Permitted Operator or any of its officers, employees, agents, contractors, lessees, licensees or invitees, (vii) any misrepresentation or inaccuracy in any representation or warranty of Lessee or any Relevant Third Party, or any breach of Lessee or Permitted Operator of any of its covenants or obligations under such Lease, any related Lease Document or the Relevant Third Party Document, (viii) any Environmental Claim or Environmental Loss, as such terms are defined in the separate Environmental Rider (Rider No. 1), attached to, and a part of this Master Lease, (ix) any personal injury, wrongful death or property damage arising under any statutory or common law or tort law theory, including, without limitation, damages assessed for the maintenance of a private or public nuisance or for the conducting of an abnormally dangerous activity on or near such Equipment, (x) any injury to, or destruction of, such Equipment, including, without limitation, costs to investigate and assess such injury or damage, (xi) any administrative process or proceeding or judicial or other similar proceeding (including, without limitation, any alternative dispute resolution process and any bankruptcy proceeding) in any way connected with any matter addressed in any Lease to which such Lessor is a party; or (xii) any latent or other defects in such Equipment whether or not discoverable by such Lessor.  Notwithstanding the foregoing, Lessee shall not be required to indemnify an Indemnified Party under this Section 18.1 for (i) any Claim to the extent caused directly by the gross negligence or willful misconduct of such Indemnified Party (except as imputed by law),  (ii) any Claim in respect of the Equipment arising from acts or events which occur after (A) the Equipment has been redelivered to such Lessor in accordance with the applicable Lease, and (B) any and all other obligati ons of any kind whatsoever of Lessee (other than unaccrued and inchoate indemnity and reimbursement obligations) under this Master Lease and the applicable Lease that have been indefeasibly paid or performed, as the case may be, (iii) any Claim that is an ordinary and usual operating or overhead expense of such Lessor with respect to this Master Lease or the applicable Lease, or (iv) any Claim arising from Excluded Taxes. If any Claim is made against Lessee or an Indemnified Party, the party receiving notice of such Claim shall promptly notify the other, but the failure of the party receiving notice to so notify the other shall not relieve Lessee of any obligation hereunder.  All the rights, privileges and indemnities contained in this Section shall survive the expiration or earlier cancellation or termination of any Lease.

18.2

Express Exculpation.  Notwithstanding anything in this Master Lease or in any rider or Schedule related hereto to the contrary, Lessee and each Lessor acknowledge and intend that all limitations of liability and exculpation from consequential, indirect, special, incidental or punitive damages expressed in this Master Lease shall apply even in the event of the negligence, fault or strict liability of such Lessor, AND SHALL INCLUDE LIABILITY FOR ANY LOSS CAUSED BY THE SOLE  NEGLIGENCE OF SUCH LESSOR.

18.3

Indemnity is Essential to Lessor, Etc.  Notwithstanding anything in this Master Lease or in any rider or Schedule related hereto to the contrary, Lessee and each Lessor acknowledge and intend that it is a material term of this Master Lease, and that such Lessor was induced to agree to the amount of the Rent and the duties and obligations of such Lessor under this Master Lease or the rider or Schedule related hereto that could give rise to any liability whatsoever, based in material part upon the agreement by Lessee to indemnify such Lessor in accordance with the terms of Section 18.1, including but not limited to any exculpations from consequential or incidental damages, all releases, waivers, overall limitation on liability, and hold harmless and indemnity provisions.  Accordingly, Lessee acknowledges that with respect to Lessee's obligation set forth above in Section 18.1 to indemnify, defe nd and hold harmless the Indemnified Parties from the matters set forth hereinabove, Lessee has had the benefit and advise of legal counsel or has specifically waived the right to obtain such advice, has calculated the potential costs of assuming the risks of doing so when agreeing to the Rent, and has agreed to assume such obligation to indemnify the Indemnified Parties with the full awareness and understanding of the Texas anti-indemnification statutes (Tex. Civ. Prac. & Rem. Code §§ 130.001-005 pertaining to design and construction contracts; and Tex. Civ. Prac. & Rem. Code §§ 127.001-007 pertaining contracts for a well for oil, gas, or water or to a mine for a mineral) or any successor statutes or laws (the “Anti-Indemnity Acts”), and, to the extent permitted by Applicable Law, Lessee hereby covenants and warrants to each Lessor that it will not raise or assert the Anti-Indemnity Acts or any similar statute or policy as an affirmative defense.  Suc h obligation of Lessee to indemnify the Indemnified Parties as set forth in Section 18.1 shall not be limited by the limits of any insurance obtained by Lessee pursuant to Section 7, and shall be limited by a limitation on amount or type of damages, compensation or

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benefits payable by or for Lessee or any contractor or subcontractor of Lessee under workers' or workmen's compensation acts, disability benefit acts or other employee benefit acts.

19.

Income Tax Indemnity.  With respect to each Lease, Lessee hereby represents, warrants and agrees as follows:

(a)

Lessee represents and warrants that:  (i) it is reasonable to estimate that the useful life of the Equipment leased thereunder exceeds the Term (including any interim and fixed rental renewal periods) of such Lease by the greater of one (1) year or twenty (20) percent of such estimated useful life, and that said Equipment will have a value at the end of the Term of such Lease, including any fixed rate renewal period, of at least twenty (20) percent of the Original Equipment Cost of such Equipment, without including in such value any increase or decrease for inflation or deflation during the original Term (all as evidenced by the certificate of a qualified party to be provided at Lessee’s expense to the Lessor under such Lease prior to the commencement of the lease term); and (ii) the Equipment is, and will be used by Lessee so as to remain, property eligible for the MACRS Deductions (as defined bel ow).  Lessee and each Lessor shall consistently report each lease transaction as a lease for federal income tax purposes.

(b)

If (i) any Lessor in computing its taxable income or liability for tax, shall lose, or shall not have, or shall lose the right to claim, or there shall be disallowed or recaptured for Federal and/or state income tax purposes, in whole or in part, the benefit of MACRS Deductions; or (ii) any Lessor shall become liable for additional tax as a result of Lessee having made a substitution for or replacement of any item of the Equipment under a Lease, or having added an attachment or made an alteration to the Equipment under a Lease, including without limitation, any such attachment or alteration which would increase the productivity or capability of such Equipment so as to violate the provisions of Rev. Proc. 2001 28, 2001 1 C.B. 1156 (as it may hereafter be modified or superseded) or as a result of Lessee’s making any payments other than or at times different from those contemplated by the relevant Lease; o r (iii) the statutory full-year marginal Federal tax rate (including any surcharge) for corporations is more than thirty five (35) percent; or (iv) as the result of the treatment of any item of income or deduction attributable to a Lease as being from sources without the United States, the foreign tax credit which the Lessor thereunder may claim against its Federal income tax liability for any year is less than the credit which such Lessor could have claimed if all such items of income and deduction had been treated as from sources within the United States; hereinafter referred to as a “Loss”; then Lessee shall pay such Lessor the Tax Indemnification Payment under such Lease as additional rent and such Lessor shall revise the Schedule(s) of Stipulated Loss Values to reflect the Loss for the relevant Equipment.  As used herein, “MACRS Deductions” shall mean the deductions under Section 167 of the Internal Revenue Code of 1986, as now or hereafter amended (the “Co de”), determined in accordance with the modified Accelerated Cost Recovery System with respect to the Original Equipment Cost of any item of the Equipment under a Lease using the accelerated method set forth in Section 168(b)(1) of the Code as in effect on the date of such Lease for “7 year property” within the meaning of Section 168(e) of the Code; “Lessor” shall be deemed to include the consolidated Federal taxpayer group of which such Lessor is a member; and “Tax Indemnification Payment” shall mean such amount as, after consideration of (i) all taxes required to be paid by such Lessor in respect of the receipt thereof under the laws of any governmental or taxing authority in the United States, and (ii) the amount of any interest or penalty payable by such Lessor in connection with the Loss for the relevant Equipment, shall be required to cause such Lessor’s after-tax net return (the “Net Return”) to be equal to, but no greater than, the Net Return computed consistently with current tax laws (and with the assumption that such Lessor is taxed at the highest marginal Federal and state tax rates) as of the date of such Lease that would have been available to such Lessor had the Loss not occurred.

(c)

Each Lessor shall be responsible for, and no Lessor shall be entitled to a Tax Indemnification Payment by Lessee on account of, any Loss arising as a direct result of the occurrence of any one or more of the following:  (i) the failure of such Lessor to timely and properly claim MACRS Deductions in the tax return of such Lessor other than as a result of changes in the Code or applicable regulations unless in the opinion of such Lessor’s tax counsel there is no reasonable basis for such claim; or (ii) the failure of such Lessor to have sufficient taxable income before application of the MACRS

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Deductions to offset the full amount of such MACRS Deductions other than as a result of changes in the Code or applicable regulations; or (iii) any event which by the terms of a Lease requires payment by Lessee of the Stipulated Loss Value if such payment is thereafter actually made to such Lessor, to the extent that such payment reimburses such Lessor for amounts otherwise payable by Lessee pursuant thereto; or (iv) a disqualifying disposition due to a voluntary sale of any item of the Equipment under a Lease by the Lessor thereunder prior to a Default.  If any Lessor receives any refund, credit, or deduction from any taxing authority to which such Lessor would not be entitled but for payments by Lessee under this Section, such Lessor shall repay to Lessee the amount of such refund, credit, or deduction.

(d)

Each Lessor promptly shall notify Lessee in writing of any Loss relating to the Equipment under a Lease, detailing the events or circumstances giving rise to the Loss, and Lessee shall pay to such Lessor the Tax Indemnification Payment within thirty (30) days of such notice.  For these purposes, a Loss shall occur upon the earliest of:  (i) the happening of any event (such as disposition or change in use of any item of the Equipment under a Lease) which will cause such Loss, (ii) the payment by such Lessor to the Internal Revenue Service or state taxing authority of the tax increase (including an increase in estimated taxes) resulting from such Loss; (iii) the date on which the Loss relating to the Equipment under a Lease is realized by the Lessor thereunder; or (iv) the adjustment of the tax return of such Lessor to reflect such Loss.

(e)

The obligations of Lessee under this Section 19, which accrue during the term of a Lease, shall survive the expiration, cancellation or termination of each Lease.

20.

Waivers.  To the extent permitted by applicable law, Lessee hereby waives any and all rights and remedies conferred upon a Lessee by Sections 2A-508 through 2A-522 of the UCC, including, without limitation, Lessee’s rights to (a) cancel any Lease; (b) repudiate any Lease; (c) reject any Equipment; (d) revoke acceptance of any Equipment; (e) recover damages from a Lessor for any breaches of warranty or for any other reason; (f) a security interest in the Equipment in Lessee’s possession or control for any reason; (g) deduct from Rent owed all or any part of any claimed damages resulting from a Lessor’s default, if any, under any Lease; (h) accept partial delivery of the Equipment; (i) ”cover” by making any purchase or lease of or contract to purchase or lease Equipment in substitution for those due from a Lesso r; (j) recover any special, incidental or consequential damages for any reason whatsoever; and (k) specific performance, replevin, detinue, sequestration, claim and delivery or the like for any Equipment identified in any Lease.  

21.

Performance by Lessor; Further Assurances.  If Lessee fails to perform or comply with any provisions contained herein or in a Lease, the Lessor thereunder may perform or comply with such provisions, and the amount of any payments and expenses of such Lessor reasonably incurred in connection with such performance or compliance (including reasonable attorneys’ fees and expenses), together with interest thereon at the Default Rate, shall be deemed additional Rent payable by Lessee upon demand.  Lessee shall cooperate with each Lessor for the purpose of protecting the interests of such Lessor in the Equipment, a Lease and the sums due under a Lease.  Lessee hereby appoints such Lessor (and any of such Lessor’s officers, employees, or agents designated by such Lessor) as Lessee’s attorney-in-fact, coupled with an interest, to do all things necessary to carry out this Sec tion.  Lessee shall execute and deliver to such Lessor upon request such other instruments and assurances as such Lessor deems necessary or advisable for the implementation, effectuation, confirmation or perfection of a Lease and any rights of such Lessor thereunder.

22.

Notices.  All notices, certificates, requests, demands and other communications provided for under a Lease shall be in writing and shall be (a) personally delivered or (b) sent by overnight courier of national reputation, and shall be deemed to have been given on (i) the date received if personally delivered and (ii) the next business day if sent by overnight courier.  All communications shall be addressed to the party to whom notice is being given at its address set forth below its signature hereto, or such other address as such party may designate in writing to the other party.  If notice to Lessee of any intended disposition of the Equipment or any other intended action is required by law in a particular instance, such notice shall be deemed commercially reasonable if given (in the manner specified in this Section) at least 10 calendar days prior to the date of intended disposition or other action.

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23.

Absolute and Unconditional.  Lessee hereby agrees that the obligations of each Lessor and Lessee hereunder shall be separate and independent covenants and agreements, and that Lessee’s obligation to pay all Rent and any other amounts owing under a Lease shall be absolute and unconditional, even if the Equipment is damaged or destroyed, if it is defective or if Lessee no longer can use it.  Lessee is not entitled to reduce, or set-off against, Rent or other amounts due to a Lessor or to anyone to whom a Lessor assigns this Master Lease or any Lease whether Lessee’s claim arises out of this Master Lease, any Lease, any statement by a Lessor, any Lessor’s liability or any manufacturer’s liability, strict liability, negligence or otherwise.

24.

Governing Law.  THIS MASTER LEASE AND EACH LEASE SHALL EACH BE DEEMED TO BE A CONTRACT MADE UNDER AND GOVERNED BY THE INTERNAL LAWS OF THE STATE OF NEW YORK (EXCLUDING THE LAWS APPLICABLE TO CONFLICTS OR CHOICE OF LAW OTHER THAN SECTIONS 5-1401 AND 5-1402 OF THE GENERAL OBLIGATIONS LAW OF THE STATE OF NEW YORK), INCLUDING ALL MATTERS OF CONSTRUCTION, VALIDITY AND PERFORMANCE.

25.

Waiver of Jury Trial.  EACH LESSOR AND LESSEE HEREBY WAIVE THEIR RESPECTIVE RIGHTS TO A JURY TRIAL OF ANY CLAIM OR CAUSE OF ACTION BASED UPON OR ARISING OUT OF, DIRECTLY OR INDIRECTLY, THIS MASTER LEASE OR ANY LEASE, ANY DEALINGS BETWEEN SUCH LESSOR AND LESSEE RELATING TO THE SUBJECT MATTER OF THE TRANSACTIONS CONTEMPLATED BY THIS MASTER LEASE OR ANY LEASE, AND/OR THE RELATIONSHIP THAT IS BEING ESTABLISHED BETWEEN SUCH LESSOR AND LESSEE.  LESSEE ACKNOWLEDGES AND AGREES THAT THIS PROVISION IS A MATERIAL INDUCEMENT FOR SUCH LESSOR’S ENTERING INTO THIS MASTER LEASE AND EACH LEASE.  THE SCOPE OF THIS WAIVER IS INTENDED TO BE ALL ENCOMPASSING OF ANY AND ALL DISPUTES THAT MAY BE FILED IN ANY COURT (INCLUDING, WITHOUT LIMITATION, CONTRACT CLAIMS, TORT CLAIMS, BREACH OF DUTY CLAIMS AND ALL OTHER COMMON LAW AND STATUTORY CLAIMS).  THIS WAIVER IS IRREVOCABLE, MEANING THAT IT MAY N OT BE MODIFIED EITHER ORALLY OR IN WRITING, AND THIS WAIVER SHALL APPLY TO ANY SUBSEQUENT AMENDMENTS, RENEWALS, SUPPLEMENTS OR MODIFICATIONS TO THIS MASTER LEASE, ANY LEASE OR ANY OTHER LEASE DOCUMENT RELATING TO THE TRANSACTIONS CONTEMPLATED BY THIS MASTER LEASE OR A LEASE.  IN THE EVENT OF LITIGATION, THIS MASTER LEASE MAY BE FILED AS A WRITTEN CONSENT TO A TRIAL BY THE COURT.

26.

Forum Selection and Consent to Jurisdiction.  LESSEE AND EACH LESSOR HEREBY IRREVOCABLY SUBMIT TO THE NON-EXCLUSIVE JURISDICTION OF THE UNITED STATES DISTRICT COURT FOR THE SOUTHERN DISTRICT OF NEW YORK AND ANY COURT IN THE STATE OF NEW YORK LOCATED IN THE CITY AND COUNTY OF NEW YORK, AND ANY APPELLATE COURT FROM ANY THEREOF, IN ANY ACTION, SUIT OR PROCEEDING BROUGHT AGAINST IT AND TO OR IN CONNECTION WITH THIS MASTER LEASE OR ANY LEASE OR THE TRANSACTIONS CONTEMPLATED THEREUNDER OR FOR RECOGNITION OR ENFORCEMENT OF ANY JUDGMENT; PROVIDED, HOWEVER, THAT ANY SUIT SEEKING ENFORCEMENT AGAINST THE EQUIPMENT MAY BE BROUGHT, AT A LESSOR’S OPTION, IN THE COURTS OF ANY JURISDICTION WHERE SUCH EQUIPMENT MAY BE FOUND.  LESSEE HEREBY EXPRESSLY AND IRREVOCABLY SUBMITS TO THE JURISDICTION OF SUCH COURTS FOR THE PURPOSE OF ANY SUCH LITIGATION AS SET FORTH ABOVE AND IRREVOCABLY AGREES TO BE BOUN D BY ANY JUDGMENT RENDERED THEREBY IN CONNECTION WITH SUCH LITIGATION.  LESSEE HEREBY EXPRESSLY AND IRREVOCABLY WAIVES, TO THE FULLEST EXTENT PERMITTED BY LAW, ANY OBJECTION WHICH IT MAY HAVE OR HEREAFTER MAY HAVE TO THE LAYING OF VENUE OF ANY SUCH LITIGATION BROUGHT IN ANY SUCH COURT REFERRED TO ABOVE AND ANY CLAIM THAT ANY SUCH LITIGATION HAS BEEN BROUGHT IN AN INCONVENIENT FORUM.  

27.

Assignment by Lessor.  A Lessor may, without the consent of or notice to Lessee, assign or transfer a Lease, and any related Lease Documents and/or such Lessor’s interest in the Equipment to any financial institution or other equipment financing provider (x) having capital surplus or a minimum net worth of Seventy-five Million Dollars ($75,000,000), or an Affiliate of any such person that

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guarantees such assignee’s obligations under the assigned Lease; and (y) not engaged directly, nor having an Affiliate that is engaged directly, in a business that competes with Lessee in the exploration and production of hydrocarbons, drilling for hydrocarbons, or the gathering or marketing of hydrocarbons; any other assignment or transfer shall require Lessee’s consent, not to be unreasonably withheld, provided, however, that no such assignment or transfer shall, in any case, materially change Lessee’s duties or obligations under this Master Lease or any Lease, nor materially increase the burdens or risks imposed on Lessee.  Lessee shall be entitled to render performance to the Lessor under any Lease until such Lessor notifies Lessee of any such assignment. Lessee agrees that it will not assert against any assignee of a Lessor any defense, counterclaim or offset that Lessee may have against such Lessor. L essee also agrees to confirm in writing the receipt of the notice of assignment and such other matters as may be requested by any assignee.  In the event a Lessor assigns a Lease, the term “Equipment” as used herein or in any Lease Document with respect to such assignee shall mean only the Equipment described on the Schedules held by such assignee, the term “Lessor” as used herein or in any Lease Document with respect to such assignee shall mean only the assignee, and the term “Lease” as used herein or in any Lease Document with respect to such assignee shall mean only the Lease held by such assignee.

28.

Miscellaneous.  A Lessor’s failure at any time to require strict performance by Lessee of any of the provisions hereof shall not waive or diminish such Lessor’s right thereafter to demand strict compliance therewith or with any other provision.  Time is of the essence with respect to the obligations of Lessee under this Master Lease and each Lease.  It is the intention of the parties hereto to comply with any applicable usury laws; accordingly, it is agreed that, notwithstanding any provisions to the contrary in this Master Lease or any Lease, in no event shall this Master Lease or any Lease require the payment or permit the collection of interest or any amount in the nature of interest or fees in excess of the maximum permitted by applicable law.  Any provision of this Master Lease or a Lease which is unenforceable in any jurisdiction shall, as to such jurisdiction , be ineffective to the extent of such prohibition or unenforceability without invalidating the remaining provisions hereof, and any such prohibition or unenforceability in any jurisdiction shall not invalidate or render unenforceable such provision in any other jurisdiction.  The captions in this Master Lease or any other Lease Document are for convenience only and shall not define or limit any of the terms hereof or thereof.  Only the representations and warranties and indemnities made or agreed to in this Master Lease, any Lease, and any other Lease Documents relating thereto, and all other obligations that are accrued but not indefeasibly paid or performed in accordance with the applicable provisions of this Master Lease, or the related Lease or related Lease Documents, shall survive the expiration, termination or cancellation of this Master Lease or any Lease.  This Master Lease, together with the Schedules and Riders related thereto executed and delivered by any Lessor and Lessee, consti tute the entire understanding and agreement between such Lessor and Lessee and there is no understanding or agreement, oral or written, which is not set forth therein.  No Lease may be amended except by a writing signed by the Lessor thereunder and Lessee and shall be binding upon and inure to the benefit of the parties hereto, their permitted successors and assigns; provided, however, any amendment to this Master Lease by a Lessor under a Schedule or Schedules hereto shall only be binding with respect to the parties to such Schedules, and not as to any other Schedules entered into under this Master Lease.  The parties agree that this Master Lease is not intended by either party to give any benefits, rights, privileges, actions or remedies to any person, partnership, firm or corporation (other than a party or its permitted assignee) as a third party beneficiary or otherwise under any theory of law.  This Master Lease and any Schedule may be executed in several counterparts, each of which shall be an original and all of which shall constitute one and the same document, and any of the parties hereto may execute this Master Lease or a Schedule by signing any such counterpart; provided, however, to the extent that any Schedule would constitute chattel paper, as such term is defined in the UCC as in effect in any applicable jurisdiction, no security interest therein may be created through the transfer or possession of this Master Lease in and of itself without the transfer or possession of the original of such Schedule, and no security interest in a Schedule may be created by the transfer or possession of any counterpart of such Schedule other than the original thereof, which shall be identified as the document marked “Original No. 1 of 2.”

[REMAINDER OF PAGE INTENTIONALLY BLANK; EXECUTION PAGE FOLLOWS.]

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IN WITNESS WHEREOF, the parties hereto have caused this Master Lease Agreement to be executed in their respective corporate names by their duly authorized officers, all as of the date first written above.

LESSEE:

SOUTHWESTERN ENERGY COMPANY

By:  /s/ Greg D. Kerley
Name:  Greg D. Kerley
Title:  Executive Vice President & Chief Financial Officer

2350 N. Sam Houston Parkway

Suite 300

Houston, TX 77032

Telephone: 281-618-4700
Facsimile: 281-618-4820

Lessee’s Organizational Identification Number: 71-0205415

Lessee’s Location for purposes of Section 9-307 of the UCC:  Delaware

Lessee’s residence for federal income tax purposes:  Fayetteville, Arkansas

LESSOR:

SUNTRUST LEASING CORPORATION

By:  /s/ M. Powers
Name:  M. Powers
Title:  S-VP

Suntrust Leasing Corporation
c/o Hampton Plaza

300 E. Joppa Road, 7th Floor

Towson, MD 21286

Phone: 410-307-6600
Fax: 410-307-6702

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EXECUTION COPY

RIDER NO. 1 TO THE MASTER LEASE AGREEMENT

ENVIRONMENTAL RIDER

This Environmental Rider is being entered into pursuant to, and as part of, the Master Lease Agreement dated as of the 29th day of December, 2006 (including any and all riders, exhibits and supplements, the “Master Lease”) between SOUTHWESTERN ENERGY COMPANY (together with its successors and assigns, “Lessee”) and SUNTRUST LEASING CORPORATION (or such other party entering into any Schedule incorporating the terms of the Master Lease, including this Rider, and named as “Lessor” in such Schedule, together with their respective successors and assigns, “Lessor”).  All capitalized terms used but not defined herein are defined in the Master Lease.

ADDITIONAL REPRESENTATIONS, WARRANTIES AND COVENANTS.

29.

As used herein, the following terms shall have the following meaning:

29.1

“Adverse Environmental Condition” shall mean (i) the existence, or the continuation of the existence, of Environmental Contamination at, in, by, from or related to the Equipment, (ii) the environmental aspect of the transportation, storage, treatment or disposal of materials in connection with the operation of the Equipment, or (iii) the violation, or alleged violation, of any Environmental Law, permits or licenses of, by or from any governmental authority, agency or court relating to environmental matters connected with any of the Equipment.

29.2

“Affiliate” shall mean, with respect to any given person, any person who directly or indirectly through one or more intermediaries controls, or is controlled by, or is under common control with, such person.

29.3

“Environmental Claim” shall mean any accusation, allegation, notice of violation, claim, demand, abatement or other order or direction (conditional or otherwise) by any governmental authority or any person for personal injury (including sickness, disease or death), tangible property damage, damage to the environment or other adverse effects on the environment, or for fines, penalties or restrictions, resulting from or based upon any Adverse Environmental Condition.

29.4

“Environmental Contamination” shall mean any actual or threatened release, spill, emission, leaking, pumping, injection, presence, deposit, abandonment, disposal, discharge, dispersal, leaching or migration into the indoor or outdoor environment, or into or out of any of the Equipment, including, without limitation, the movement of any Hazardous Substance or other substance through or in the air, soil, surface water, groundwater or property.

29.5

“Environmental Law” shall mean any applicable present or future federal, state or local law, ordinance, order, rule or regulation and all judicial, administrative and regulatory decrees, judgments and orders, pertaining to health, industrial hygiene, the use, disposal or transportation of Hazardous Substances, Environmental Contamination, or pertaining to the protection of the environment, including, but not limited to, the Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”) (42 U.S.C. §9601 et seq.), the Hazardous Material Transportation Act (49 U.S.C. §1801 et seq.), the Federal Water Pollution Control Act (33 U.S.C. Section 1251 et seq.), the Resource Conservation and Recovery Act (42 U.S.C. §6901 et seq.), the Clean Air Act (42 U.S.C.  §7401 et seq.), the T oxic Substances Control Act (15 U.S.C. § 2601 et seq.), the Federal Insecticide, Fungicide, and Rodenticide Act (7 U.S.C. §1361 et seq.), the Occupational Safety and Health Act (19 U.S.C. §651 et seq.), the Noise Control Act of 1972 (42 U.S.C. §4901 et seq.), and the Hazardous and Solid Waste Amendments (42 U.S.C., §2601 et seq.), as these laws have been or may be amended or supplemented, and any successor thereto and any applicable analogous foreign, state or local statutes, and the rules, regulations and orders promulgated pursuant thereto.

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29.6

“Environmental Loss” shall mean any loss, cost, damage, liability, deficiency, fine, penalty or expense (including, without limitation, reasonable attorneys’ fees, engineering and other professional or expert fees), investigation, removal, cleanup and remedial costs incurred or required to be incurred pursuant to Environmental Laws and damages to, loss of the use of or decrease in value of the Equipment arising out of or related to any Adverse Environmental Condition.

29.7

“Equipment” shall mean the Equipment described in the Schedule.

29.8

“Hazardous Substances” shall mean and include hazardous substances as defined in CERCLA; oil of any kind, petroleum products and their by products, including, but not limited to, sludge or residue; asbestos containing materials; polychlorinated biphenyls; any and all other hazardous or toxic substances; hazardous waste, as defined in CERCLA; medical waste; infectious waste; those substances listed in the United States Department of Transportation Table (49 C.F.R. §172.101); explosives; radioactive materials; and all other pollutants, contaminants and other substances regulated or controlled by the Environmental Laws and any other substance that requires special handling in its collection, storage, treatment or disposal under the Environmental Laws.

30.

Lessee hereby represents and warrants that:  (a) each of Lessee and its Permitted Operator shall use the Equipment so as to comply with all Environmental Laws; and (b) each of Lessee and its Permitted Operator has in full force and effect all federal, state and local licenses, permits, orders and approvals required to operate the Equipment in compliance with all Environmental Laws; except, in each such case, for any unintentional non-compliance with any such Environmental Laws, where such non-compliance could reasonably be expected to have a Material Adverse Effect or, the effect of which could reasonably be expected to result in a Material Risk.

31.

Lessee agrees that if required to return the Equipment or any item thereof to Lessor or Lessor’s agents, Lessee shall, or shall cause its Permitted Operator to, return such Equipment free from all Hazardous Substances (other than those substances that are necessary for the operation or storage of the Equipment as and to the extent consistent with Lessee’s compliance with Section 10 of the Master Lease and the Return Rider), and otherwise fully in compliance with all Environmental Laws.

32.

With respect to each Lease, the provisions of this Rider shall survive any expiration, cancellation or termination of such Lease.

[Signatures Follow On Next Page]

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SUNTRUST LEASING CORPORATION
Lessor


By: /s/ M. Powers
Name:  Michael J. Powers
Title:  Secretary SOUTHWESTERN ENERGY COMPANY
Lessee


By: /s/ Greg D. Kerley
Name:  Greg D. Kerley
Title:  Executive Vice President & Chief Financial Officer

WASHINGTON_DC/#1021.6

[Schedule]

RIDER NO. 2 TO THE MASTER LEASE AGREEMENT

RETURN RIDER

This Return Rider is being entered into pursuant to, and as part of, the Master Lease Agreement dated as of the __th day of December, 2006 (including any and all riders, exhibits and supplements, the “Master Lease”), between Southwestern Energy Company (together with its successors and assigns, “Lessee”) and Suntrust Leasing Corporation (or such other party entering into any Schedule incorporating the terms of the Master Lease, including this Rider, and named as Lessor in such Schedule, together with their respective successors and assigns (“Lessor”).  All capitalized terms used but not defined herein are defined in the Master Lease.

RETURN PROVISIONS:  In addition to the provisions of Section 10 of the Master Lease (provided that any inconsistency between the provisions of Section 10 and this Rider shall be resolved in favor of the provisions of this Rider), and provided that Lessee has not elected to exercise its option to purchase the Equipment or renew the Term of the Lease with respect to such Equipment (if and to the extent such option is exercisable in accordance with the applicable provisions of the Option Rider or Early Purchase Option Rider to the Schedule pertaining to such Equipment), the Lessee shall at its expense return the Equipment in accordance with the following requirements:

(a)

Return Inspection.  Not more than one hundred eighty (180) days prior to the then scheduled expiration date of the Basic Term of such Lease, or on such earlier date on which the Equipment is to be returned upon a termination or cancellation of such Lease by Lessor pursuant to the applicable provisions of the Master Lease (the “Required Return Date”), Lessor, at Lessee’s sole expense, will engage the original manufacturer or a qualified consultant to conduct a detailed physical inspection of the Equipment, conduct various tests in accordance with Prudent Industry Practice and review performance, utilization, inspection, maintenance and repair data, records and reports to determine that the Equipment’s actual condition is in accordance with the maintenance, operation, return and other provisions of the Master Lease relating to the condition in which the Equipment is to be kept and maintained during t he Term of each Lease.  All discrepancies resulting from the manufacturer’s or consultant’s evaluation will be corrected, repaired and re-evaluated at the Lessee’s sole expense.

The manufacturer or consultant shall provide an in-depth field service report detailing the inspection, including an itemized listing of equipment, noting any deficiencies and the costs for repair.  The manufacturer or consultant shall certify that the Equipment, and primary components have been properly inspected, examined and tested, and are either (1) operating within the manufacturer’s recommended and published specifications and tolerances and are in compliance with the terms of the Lease, and/or (2) identify those items that are not in compliance with the return conditions and provide an estimate of the cost of repair for those items not in compliance.

For the purposes hereof, “Prudent Industry Practice” means at a particular time, those practices, methods and acts which are in accordance with specifications and standards of prudence applicable to the natural gas drilling industry and which are generally engaged in or approved by the natural gas drilling industry at such time with respect to equipment of the same or similar type as the Equipment.  Prudent Industry Practice is not intended to mean the optimum practice, method or act, to the exclusion of all others, but rather is a spectrum of possible practices, methods and acts which could have been expected to accomplish the desired result at the lowest reasonable cost consistent with reliability, safety and expedition and all Applicable Laws and other Applicable Requirements, but Prudent Industry Practice is intended to mean at least the same standard as Lessee would, in the prudent management of its own properties and equipment , use from time to time.

(b)

Storage.  At Lessor’s request, Lessee shall provide insurance and safe and secure storage of the Equipment without charge to the Lessor in a manner consistent with the manufacturer’s

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recommendations for up to 90 days following the Required Return Date at accessible locations in the states of Arkansas or Texas satisfactory to Lessor.

(c)

Supplemental Return Conditions.

(i)

From the date of Lessee’s notice of return to Lessor until Lessee’s return of the Equipment, Lessor shall have the right to attempt a private sale of the Equipment from a mutually convenient location selected by Lessee and consistent with Lessor’s remarketing purposes.  During this time, the Equipment shall remain fully operational and Lessee agrees to demonstrate and allow inspection of the Equipment to potential buyers(s) presented by Lessor, or its agent, provided reasonable notice is provided to Lessee and such buyer(s) expressly assume, for the benefit of Lessee and Operator, all liability for injury to or death of any individual exercising, either on behalf of Lessor or any potential purchaser, the rights of inspection hereunder, but only to the extent such injury or death is the direct result of the gross negligence or willful misconduct of such party.

(ii)

Equipment will be returned with all manuals, maintenance records, log books, plans, drawings and schematics, inspection and overhaul records, operating requirements or other materials pertinent to the Equipment’s operation, maintenance, assembly and disassembly.

(iii)

Equipment will be returned with all parts, components, accessories, pumps, motors and blocks as originally delivered, ordinary wear and tear excepted, and as necessary to operate the Equipment for its intended purpose, including but not limited to trucks, trailers, a complete set of drilling equipment for the rated depth, derrick mast and substructures, draw works and diesel engines, power generators, mud pumps, mixers and tanks, closing unit, complete drill string (pipe, collars and kelly) and blowout preventers, choke manifold, water and fuel tanks, controls and gauges, and all original auxiliary equipment such as hoists, lighting, control houses, forklifts, hoses, etc.

(iv)

There will be no structural or mechanical damage, except ordinary wear and tear.  Frames, structural members, accessories and attachments must be structurally sound without breaks or cracks, ordinary wear and tear excepted, and in compliance with all federal, state, local and other regulatory requirements.  Any structural repairs shall have been made in observance of customary and professional standards and all other Applicable Requirements, and in a workmanlike manner so as not to detract from the Equipment’s functionality or integrity.

(v)

Equipment will be able to perform its required tasks effectively without repair, including (but not limited to) electronic, electrical and mechanical controls, pumps, motors, belts, hoses, pins, bushings, measuring devices, screws, barrels, ways, rams, and clamps, and be operational and in compliance with all Federal, state, local and other regulatory requirements and Applicable Laws, and shall be within the manufacturer’s design performance characteristics and tolerances.

(vi)

Diesel engines, generators and hydraulic systems shall operate without excessive noise, exhaust and vibration, free of all material fluid leaks, and all fluids shall be free of any cross-contamination.  Diesel engines and generators must be mechanically sound and operate within the manufacturer’s specifications with regard to oil pressure, coolant temperature and other pressures.  Generator, generator part and/or generator accessory will have at least half (50%) hours remaining, on each generator, generator part and/or generator accessory, according to the then current manufacturer’s maintenance program overhaul interval.

(vii)

Equipment will be reasonably clean in accordance with Prudent Industry Practice, de-identified of any and all markings except original manufacturer and regulatory markings, and rust free.  Sumps and tanks must be reasonably clean and dry.

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[Schedule]

(viii)

All internal fluids such as lube oil and hydraulic oil are to be filled to operating levels with no sludge or residue remaining.  Filler caps are to be secured and disconnected.  Hoses are to be sealed to avoid spillage.

(ix)

All locking keys are to be together and secured to a major external component of the Equipment.

(x)

Equipment with predictable or scheduled replacements or overhaul lives shall have not less than 50% useful life remaining before the next such replacement, overhaul, recalibration, refurbishment or rebuild.

(xi)

The disassembly will be performed according to the manufacturer’s recommendations and with any transportation devices, such as metal skids, lifting slings, and brackets, which were with the Equipment when it was originally delivered, or replacement devices that are equally suitable for the purposes contemplated herein.  All proper blueprinting, mapping, tagging and labeling of each individual part including cables, electrical apparatus and wires will be included.  Equipment shall be returned free from all Hazardous Substances (other than those substances that are necessary for the operation or storage of the Equipment as and to the extent consistent with Lessee’s compliance with Section 10 of the Master Lease and the Return Rider), and otherwise fully in compliance with all Environmental Laws.  All waste material and fluid must be removed from the Equipment and dis posed of in accordance with then current waste disposal laws, and all other Applicable Laws.  Lessor shall be held harmless for any damages to the disassembly site.

SUNTRUST LEASING CORPORATION
Lessor


By: /s/ M. Powers
Name:  Michael J. Powers
Title:  Secretary SOUTHWESTERN ENERGY COMPANY
Lessee


By: /s/ Greg D. Kerley
Name: Greg D. Kerley
Title:  Executive Vice President & Chief Financial Officer  

32

[Schedule]

RIDER NO. 3 TO THE MASTER LEASE AGREEMENT

REMOVAL RIDER

This Removal Rider is being entered into pursuant to, and as part of, the Master Lease Agreement dated as of the 29th day of December, 2006 (including any and all riders, exhibits and supplements, the “Master Lease”), between Southwestern Energy Company (together with its successors and assigns, “Lessee”) and Suntrust Leasing Corporation (or such other party entering into any Schedule incorporating the terms of the Master Lease, including this Rider, and named as Lessor in such Schedule, together with their respective successors and assigns (“Lessor”).  All capitalized terms used but not defined herein are defined in the Master Lease.

1.

So long as no Default or Event of Default has occurred and is continuing under the Lease to which this Rider is related, Lessee, at its option, may, in the ordinary course of its business, temporarily (but, as to each affected Removed Part (as defined below), in no event more than 90 days, in the aggregate, during any twelve (12) month period during the Term of such Lease, or beyond the expiration or earlier cancellation or termination of such Lease) remove any spare part or individual component that is included in the Equipment under such Lease (each such spare part or component, a “Removed Part”), and use such Removed Part in connection with, or add, affix or attach it to the Equipment of another Lessor under a Schedule to this Master Lease, in each such case, subject to the following conditions:

(a) unless and until Lessee has replaced the Removed Part in accordance with clause (c) below, the Lessor of the Equipment with respect to which such Removed Part is used, added, affixed or attached (the “Benefited Lessor”), effectively agrees that it will not acquire any right, title or interest in such Removed Part by reason of the installation of such Removed Part on or with such Benefited Lessor’s Equipment, and that such Removed Part shall not be subject to any Lien or other interest in favor of such Benefited Lessor, and it shall cooperate with the recovery of such Removed Part by the Lessor of the Removed Part (the “Burdened Lessor”) (and, each Lessor under a Schedule to this Master Lease hereby agrees as such and agrees that such agreement shall remain in full force and effect and be relied upon by each Lessor under any Schedule related to this Master Lease);

(b) the aggregate Original Equipment Cost of all Removed Parts under a Lease removed and not replaced in accordance with clause (c) below shall not on any day exceed fifteen percent (15.00%) percent of the Original Equipment Cost of the items of Equipment leased under such Lease; and

(c) no later than the 60 days after removing the Removed Part, such Removed Part shall be replaced by Lessee’s either (i) substituting for the Removed Part another spare part or individual component that is a new or reconditioned replacement part or component (each, a “Replacement Part”), which such Replacement Part shall be free and clear of all Liens (other than Permitted Liens) and shall have a fair market value, utility and remaining use life at least equal to that of the Removed Part (assuming such Removed Part was in the condition required by the Lease), at which time the Burdened Lessor agrees that its right, title and interest in such Removed Part shall cease and such right, title and interest in such Removed Part shall be vested in the Benefited Lessor free and clear of any Lessor’s Liens arising by, through or under, or in favor of the Burdened Lessor (and Lessee hereby co venants and agrees that such Removed Part shall be free and clear of all other Liens, other than Permitted Liens) or (ii) reattaching, reinstalling or relocating the Removed Part back on or with the Equipment of the Burdened Lessor, and, in either such case, installing such Replacement Part or reattached, reinstalled or relocated Removed Part in accordance with, and after such installation causing the Replacement Part or Removed Part, as the case may be, to be in compliance with all Applicable Requirements, and the other provisions of the related Lease and other Lease Documents.

2.

Lessor shall be indemnified against any Loss (as defined in Section 19 of the Master Lease) suffered by Lessor by reason of the rights granted to Lessee in this Rider, whether by the provision for same, or in connection with any of the undertakings contemplated herein, including, after giving effect to

33

[Schedule]

any exclusions provided for in any applicable indemnities.

3.

Lessee shall be deemed to have conveyed or caused to be conveyed to Burdened Lessor good and marketable title to each Replacement Part, and each Replacement Part shall be subject to the provisions of the Lease to which the Removed Part was subject, and Lessee agrees to execute and/or deliver any bills of sale, amendments to the related Schedule, filings or other assurances reasonably requested by Lessor; and

4.

Lessee shall be responsible for and pay, and reimburse Lessor for, any taxes or costs relating to any such removal, and any temporary or permanent replacement of parts or components pursuant to this Rider.

SUNTRUST LEASING CORPORATION
Lessor


By: /s/ M. Powers
Name:  Michael J. Powers
Title:  Secretary SOUTHWESTERN ENERGY COMPANY
Lessee


By: /s/ Greg D. Kerley
Name: Greg D. Kerley
Title:  Executive Vice President & Chief Financial Officer  

34

[Schedule]

EXHIBIT 1

Form of SCHEDULE

SCHEDULE NO. ____

DATED AS OF ____________, 2006

TO MASTER LEASE AGREEMENT

DATED AS OF DECEMBER 29, 2006

THIS SCHEDULE NO. ___ dated as of ________________, 2006, between SOUTHWESTERN ENERGY COMPANY (together with its successors and assigns, “Lessee”), and [LESSOR] (together with its successors and assigns, “Lessor”) is executed pursuant to the Master Lease Agreement dated as of December 29, 2006 (the “Master Lease”), between Lessee and SUNTRUST LEASING CORPORATION (together with its successors and assigns, “STLC”).

Section 2.

Lease; Equipment.  

(a)

Pursuant to Section 1.1 of the Master Lease, Lessee and Lessor hereby agree as follows:  i) all of the provisions of the Master Lease are incorporated herein by reference and capitalized terms used herein and not defined herein shall have the meanings ascribed to such terms in the Master Lease; ii) to the extent the provisions of the Master Lease conflict with the provisions of this Schedule, the provisions of this Schedule shall control; and iii) this Schedule, incorporating the terms and conditions of the Master Lease and all of the exhibits, orders and attachments thereto and hereto, constitute a separate Lease with respect to the Equipment covered hereby; and that, although STLC is referenced in the Master Lease as the original Lessor, the Lessor named above (and its successors and assigns) shall be the Lessor under the Lease created hereby, and under all of the Lease Documents relati ng to the “Equipment” leased pursuant hereto (as described in subsection 1(b) below).

(b)

Lessor hereby leases to Lessee, and Lessee hereby leases from Lessor the equipment and other property described in the attached Exhibit A (together with all accessories, attachments, parts, repairs, additions, upgrades and accessions thereto and all replacements and substitutions therefor, the “Equipment”), which is incorporated herein by this reference.  The aggregate original equipment cost (the “Original Equipment Cost”) for all of the Equipment is [$___________].  The Original Equipment Cost for each item of Equipment is as specified in the attached Exhibit A.

Section 3.

Equipment Location.  Lessee hereby certifies that the description of the Equipment set forth in the attached Exhibit A is accurate, complete and reasonably identifies the Equipment for UCC purposes.  Such Equipment shall be located at the county, and within the zip code, set forth below on the Acceptance Date (as defined below) and relocated from time to time in accordance with the applicable terms and conditions of the Master Lease:  County: ______________   Zip Code: ________________.

Section 4.

Term.  The Term with respect to the Equipment covered by this Schedule shall commence on the date of the Certificate of Acceptance executed by Lessee with respect thereto (the “Acceptance Date”) and continue to January 1, 2007 (the “Commencement Date”), and thereafter for a continuous period (the “Basic Term”) of ninety-six (96) consecutive months following the Commencement Date.

Section 5.

Rent.  b) For the period from the Acceptance Date to the Commencement Date, Lessee shall pay as Rent (“Interim Rent”) for the Equipment, the per diem, pro rata portion of the periodic Basic Rent (as defined below), in an amount equal to $____________ for each day of such interim period.  Interim Rent shall be due on the Commencement Date.  c) Commencing on January 31, 2007 and on the last day of each consecutive month thereafter (each, a “Payment Date”) during the Basic Term, Lessee shall pay to Lessor as Rent (“Basic Rent”) for the Equipment an amount equal to $____________ for each month during the Basic Term (calculated as 1.12351% of Original Equipment Cost).

35

[Schedule]

All amounts due under this Schedule, including but not limited to Interim Rent and Basic Rent, and all other payments due under the Lease as to which this Schedule is a part shall be paid in lawful money of the United States of America in immediately available funds to the following account, or to such other account as designated by Lessor to Lessee in writing:

Clearing Bank:  _________________

ABA:  _________________

Beneficiary:  _________________

Account:  _________________

Lessee:  SOUTHWESTERN ENERGY COMPANY

Any payment received after 12:00 p.m. New York time will be deemed received on the next succeeding business day.  

Section 6.

Representations and Warranties.  Lessee represents and warrants that (a) all of its representations and warranties contained in the Master Lease were not materially incorrect or misleading as of the date made, remain materially accurate as of the date of this Schedule and are hereby reaffirmed and (b) no Default or Event of Default has occurred or would result from this Lease.

Section 7.

Interest in Equipment.  Notwithstanding anything in any Lease Document to the contrary, the Equipment is and shall at all times be and remain the sole and exclusive personal property of Lessor, and notwithstanding any trade-in or down payment by Lessee or on its behalf with respect to the Equipment, Lessee shall have no right, title or interest therein or thereto except as to the use thereof subject to the terms or conditions of this Lease.  

Section 8.

Riders, Certificates and Agreements.  The Riders, certificates and agreements executed in connection with this Schedule are checked below:

þ Stipulated Loss Value Rider

þ End of Term Option Rider

þ Early Purchase Option Rider

þ Acceptance Certificate

þ Acknowledgment and Agreement of Use

Section 9.

Article 2A Notice.  IN ACCORDANCE WITH THE REQUIREMENTS OF ARTICLE 2A OF THE UNIFORM COMMERCIAL CODE AS ADOPTED IN THE APPLICABLE STATE, LESSOR HEREBY MAKES THE FOLLOWING DISCLOSURES TO LESSEE PRIOR TO EXECUTION OF THE LEASE, (A) THE SUPPLIERS ARE LISTED ON EXHIBIT A HERETO, (B) LESSEE IS ENTITLED TO THE PROMISES AND WARRANTIES, INCLUDING THOSE OF ANY THIRD PARTY, PROVIDED TO LESSOR BY SUPPLIERS, WHICH ARE SUPPLYING THE EQUIPMENT IN CONNECTION WITH OR AS PART OF THE CONTRACT BY WHICH LESSOR ACQUIRED THE EQUIPMENT OR THE RIGHT TO POSSESSION AND USE OF THE EQUIPMENT AND (C) WITH RESPECT TO SUCH EQUIPMENT, LESSEE MAY COMMUNICATE WITH SUPPLIERS AND RECEIVE AN ACCURATE AND COMPLETE STATEMENT OF SUCH PROMISES AND WARRANTIES, INCLUDING ANY DISCLAIMERS AND LIMITATIONS OF THEM OR OF REMEDIES. TO THE EXTENT PERMITTED BY APPLICABLE LAW, LESSEE HEREBY WAIVES ANY AND ALL RIG HTS AND REMEDIES CONFERRED UPON A LESSEE IN ARTICLE 2A (EXCEPT, TO THE EXTENT APPLICABLE, ANY SUCH RIGHT OR REMEDY AVAILABLE TO A LESSEE UNDER 2A-522 OF THE UCC IN THE EVENT THAT THE LESSOR IS INSOLVENT AND FAILS TO PERFORM ITS OBLIGATION TO DELVER CONFORMING EQUIPMENT UNDER A LEASE) AND ANY RIGHTS NOW OR HEREAFTER CONFERRED BY STATUTE OR OTHER APPLICABLE LAW WHICH MAY LIMIT OR MODIFY ANY OF LESSOR’S RIGHTS OR REMEDIES UNDER THE DEFAULT AND REMEDIES SECTION OF THE MASTER LEASE.

36

[Schedule]

Section 10.

Miscellaneous.  This Schedule may be executed in several counterparts, each of which shall be an original and all of which shall constitute one and the same document, and any of the parties hereto may execute this Schedule by signing any such counterpart; provided, however, to the extent that this Schedule would constitute chattel paper, as such term is defined in the UCC as in effect in any applicable jurisdiction, no security interest therein may be created without the transfer or possession of the original of this Schedule, and no security interest in this Schedule may be created by the transfer or possession of any counterpart of this Schedule other than the original hereof, which shall be identified as the document marked “Original No. 1 of 2.”

[REMAINDER OF PAGE INTENTIONALLY BLANK; EXECUTION PAGE FOLLOWS.]

37

[Schedule]

IN WITNESS WHEREOF, the parties hereto have caused this Schedule to be executed in their respective corporate names by their duly authorized officers, all as of the date first written above.

LESSEE:

SOUTHWESTERN ENERGY COMPANY

By:
Name:
Title:

LESSOR:

[LESSOR]


By:
Name:
Title:

ORIGINAL: __ OF 2

[EXECUTION PAGE OF SCHEDULE NO. ____]

WASHINGTON_DC/#1021.6

EXECUTION COPY

EXHIBIT A

Description of Equipment

Quantity Supplier Description Serial Number Original Equipment Cost

WASHINGTON_DC/#1020.3

[Stipulated Loss Value Rider]

STIPULATED LOSS VALUE RIDER

This Stipulated Loss Value Rider dated as of December ___, 2006 (this “Rider”) is attached to and made a part of Schedule No. ___ dated as of December ___, 2006 (the “Schedule”) between SOUTHWESTERN ENERGY COMPANY (together with its successors and assigns, “Lessee”), and [LESSOR] (together with its successors and assigns, “Lessor”) executed pursuant to the Master Lease (as defined in the Schedule).  Capitalized terms used in this Rider and not defined herein shall have the meanings ascribed to such terms in the Schedule (including other Riders thereto), including the Master Lease incorporated therein.   To the extent the provisions of the Master Lease or the Schedule conflict with the provisions of this Rider, the provisions of this Rider shall control.

The Stipulated Loss Value for the Equipment covered by the Schedule shall equal the product of the Original Equipment Cost for the Equipment and the percentage factor set forth in the following table corresponding to the rental payment number with which payment of the Stipulated Loss Value and Basic Rent is due.

Rental Payment Number	Percent of Equipment Cost	Rental Payment Number	Percent of Equipment Cost	Rental Payment Number	Percent of Equipment Cost
1	103.50	33	82.49	65	55.48
2	103.33	34	81.72	66	54.56
3	103.10	35	80.94	67	53.63
4	102.62	36	80.16	68	52.70
5	102.01	37	79.37	69	51.77
6	101.39	38	78.58	70	50.83
7	100.76	39	77.78	71	49.88
8	100.13	40	76.98	72	48.93
9	99.50	41	76.17	73	47.98
10	98.85	42	75.36	74	47.02
11	98.20	43	74.55	75	46.05
12	97.55	44	73.73	76	45.08
13	96.88	45	72.91	77	44.11
14	96.21	46	72.08	78	43.13
15	95.54	47	71.25	79	42.15
16	94.86	48	70.41	80	41.17
17	94.18	49	69.57	81	40.18
18	93.49	50	68.73	82	39.18
19	92.79	51	67.87	83	38.18
20	92.09	52	67.02	84	37.18
21	91.38	53	66.16	85	36.17
22	90.67	54	65.29	86	35.16
23	89.95	55	64.43	87	34.15
24	89.23	56	63.55	88	33.12
25	88.50	57	62.67	89	32.11
26	87.76	58	61.79	90	31.09
27	87.03	59	60.91	91	30.08
28	86.28	60	60.01	92	29.07
29	85.53	61	59.12	93	28.05
30	84.78	62	58.22	94	27.04
31	84.02	63	57.31	95	26.02
32	83.26	64	56.40	96	25.00

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WASHINGTON_DC/#1020.3

EXECUTION COPY

IN WITNESS WHEREOF, the parties hereto have caused this Stipulated Loss Value Rider to be executed in their respective corporate names by their duly authorized officers, all as of the date first written above.

LESSEE:

SOUTHWESTERN ENERGY COMPANY

By:
Name:
Title:

LESSOR:

[LESSOR]


By:
Name:
Title:

WASHINGTON_DC/#1023.10

[End of Term Option Rider]

END OF TERM OPTION RIDER

This End of Term Option Rider dated as of December ___, 2006 (this “Rider”) is attached to and made a part of Schedule No. ___ dated as of December ___, 2006 (the “Schedule”) between SOUTHWESTERN ENERGY COMPANY (together with its successors and assigns, “Lessee”), and [LESSOR] (together with its successors and assigns, “Lessor”) executed pursuant to the Master Lease (as defined in the Schedule).  Capitalized terms used in this Rider and not defined herein shall have the meanings ascribed to such terms in the Schedule (including other Riders thereto), including the Master Lease incorporated therein.  To the extent the provisions of the Master Lease or the Schedule conflict with the provisions of this Rider, the provisions of this Rider shall control.

Section 11.

Delivery of Notice.  d) At least two hundred seventy (270) days prior to the scheduled expiration of the Basic Term of the Lease (the “Scheduled Expiration Date”), Lessee shall deliver its revocable written notice to Lessor of Lessee’s intent to exercise its option to renew the Basic Term of the Lease pursuant to paragraph (b) below (the “Renewal Notice”); and the failure to provide the Renewal Notice by such date shall be deemed an irrevocable election to either purchase or return the Equipment pursuant to the applicable provisions of this Rider and the Master Lease.  

(b)

At least one hundred eighty (180) days prior to the Scheduled Expiration Date, Lessee shall deliver its irrevocable written notice to Lessor of Lessee’s intent to either (such notice, selecting only one of the following three alternative options): (A) return the Equipment to Lessor pursuant to Section 10 of the Master Lease and the Return Rider; (B) exercise its option to purchase the Equipment pursuant to paragraph (c) below; or (C) if Lessee has previously provided its Renewal Notice and has been proceeding to renew the Lease in accordance with paragraph (b) below, exercise its option to renew the Lease pursuant to paragraph (b) (with respect to the selected option, the “Final Notice”).  If for any reason Lessee does not provide the Final Notice one hundred eighty (180) days prior to the Scheduled Expiration Date, Lessee shall be deemed to have elected to return th e Equipment to Lessor pursuant to Section 10 of the Master Lease and the Return Rider.

Section 12.

Option to Renew.  Provided that no Default or Event of Default has occurred and is continuing under the Lease to which this Rider relates and that the Lease of the Equipment leased under the Schedule has not been earlier terminated, Lessee shall, if so elected in its Renewal Notice, renew the Lease, at the expiration of the term thereof, with respect to all but not less than all of the Equipment leased thereunder, on the terms and conditions of such Lease, for a negotiated renewal term at a periodic rent equal to the Fair Market Rental Value of such Equipment determined at the time of renewal.  After giving Lessor the Notice of its intent to renew the Lease, Lessee shall engage in negotiations with Lessor to determine the periodic rent to be paid during the renewal term.  Not less than one hundred eighty (180) days before the Scheduled Expiration Date, Lessee shall give Lessor written n otice of its acceptance of the renewal terms mutually agreed upon during negotiations.  Such election shall be effective with respect to all of the Equipment leased under the Lease.  For purposes of this Section, “Fair Market Rental Value” shall be deemed to be an amount equal to the rental, as installed and in use, obtainable in an arms’ length transaction for a complete, erected onshore drilling rig ready and in-place for its intended use and purpose at the drill site (and any implied cost to dismantle, move and re-erect the drilling rig from the drill site shall not be a deduction from value) between a willing and informed lessor and a willing and informed lessee under no compulsion to lease.

If Lessee and Lessor are unable to agree on the Fair Market Rental Value at least one hundred eighty (180) days prior to the Scheduled Expiration Date, then an independent appraiser (which appraiser shall be a Senior Accredited Member of the American Society of Appraisers) selected by Lessor and approved by Lessee shall determine Fair Market Rental Value, which determination shall be final, binding and conclusive.  Lessee shall bear all reasonable costs associated with the appraisal.

If, at least one hundred eighty (180) days prior to the Scheduled Expiration Date, Lessee and Lessor are unable to agree on the length of the renewal term (after reasonable negotiations exercised in good faith), Lessee shall provide its Final Notice pursuant to paragraph (a)(ii) above, thereby irrevocably electing to either purchase or return the Equipment (as provided above), and if for any reason Lessee

42

WASHINGTON_DC/#1023.10

[End of Term Option Rider]

fails to timely provide the Final Notice making such election, Lessee shall be deemed to have elected to purchase the Equipment pursuant to paragraph (c) below.

Section 13.

Option to Purchase.  On the Scheduled Expiration Date, provided that no Default or Event of Default has occurred and is continuing under the Lease to which this Rider relates and that the Lease of the Equipment leased under the Schedule has not been earlier terminated, Lessee shall, if so elected in its Notice, purchase on an AS IS, WHERE IS BASIS, all (and not less than all) of the Equipment leased thereunder for a price equal to the Fair Market Value (as defined below) (the “Purchase Option Price”), together with all taxes (except for those taxes the liability for which has been expressly excluded in Sections 9 and 19 of the Master Lease) and charges upon sale and all other amounts accrued and unpaid under the Lease.  Such amounts shall be paid to Lessor in immediately available funds on the Scheduled Expiration Date.  Lessor and Lessee agree that the Purchase Option Price represents a reasonable prediction of the fair market value of the Equipment as of the Scheduled Expiration Date.  

For purposes of this Rider, “Fair Market Value” shall mean an amount equal to the price of the Equipment, as installed and in use, that a willing and informed buyer (who is neither a lessee in possession nor a used equipment dealer) would pay for the Equipment in an arms’ length transaction with a willing and informed seller under no compulsion to sell (and assuming that, as of the date of determination, the Equipment is in at least the condition required by the Lease).   The costs of removing and transporting the Equipment from its current location to a willing buyer shall not be deducted from the value of the Equipment.  If Lessee and Lessor are unable to agree on the Fair Market Value at least ninety (90) days prior to the Scheduled Expiration Date, then an independent appraiser (which appraiser shall be a Senior Accredited Member of the American Society of Appraisers) selected by Lessor and approved by Lessee shall determine Fair Market Value, which determination shall be final, binding and conclusive.  Lessee shall bear all reasonable costs associated with the appraisal.

Notwithstanding any election of Lessee to purchase the Equipment in accordance with this Rider, the provisions of the Lease shall continue in full force and effect until the passage of ownership of the Equipment upon the date of purchase.  Upon the purchase of all of the Equipment and receipt by Lessor of the Purchase Option Price, together with all taxes (except for those taxes the liability for which has been expressly excluded in Sections 9 and 19 of the Master Lease) and charges upon sale and all other amounts accrued and unpaid under the Lease, Lessor will transfer, on an AS IS WHERE IS BASIS, all of Lessor’s interest in such Equipment, and at Lessee’s expense shall execute and deliver a bill of sale as reasonably may be required to convey any interest of Lessor in and to such Equipment.  Lessor shall not be required to make and may specifically disclaim any representation or warranty as to the Equipment so purchased or as to any other matters other than as to the absence of Lessor’s Liens.

Section 14.

Exercise of Option Under All Schedules.  Lessee hereby agrees that an additional condition to its exercising any of the options in clauses (i) or (ii) of paragraph (a) above shall be the exercise of that same option with respect to, and in accordance with, all (and not less than all) of all of the items of Equipment leased under all of the other Schedules to which Lessor is a party.

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43

WASHINGTON_DC/#1023.10

EXECUTION COPY

IN WITNESS WHEREOF, the parties hereto have caused this End of Term Option Rider to be executed in their respective corporate names by their duly authorized officers, all as of the date first written above.

LESSEE:

SOUTHWESTERN ENERGY COMPANY


By:
Name:
Title:

LESSOR:

[LESSOR]


By:
Name:
Title:

[Early Purchase Option Rider]

EARLY PURCHASE OPTION RIDER

This Early Purchase Option Rider dated as of December ___, 2006 (this “Rider”) is attached to and made a part of Schedule No. __ dated as of December ___, 2006 (the “Schedule”) between SOUTHWESTERN ENERGY COMPANY (together with its successors and assigns, “Lessee”), and [LESSOR] (together with its successors and assigns, “Lessor”) executed pursuant to the Master Lease (as defined in the Schedule).  Capitalized terms used in this Rider and not defined herein shall have the meanings ascribed to such terms in the Schedule, including the Master Lease incorporated therein.   To the extent the provisions of the Master Lease or the Schedule conflict with the provisions of this Rider, the provisions of this Rider shall control.

Section 15.

Early Purchase Option.  On the next business day immediately following the 84^th Payment Date (the “Early Purchase Date”) and provided that no Default or Event of Default under the Lease to which this Rider relates has occurred and is continuing, and that the Lease of the Equipment leased under the Lease has not been earlier terminated, Lessee may, UPON AT LEAST NINETY (90) DAYS PRIOR WRITTEN NOTICE TO LESSOR OF LESSEE’S IRREVOCABLE ELECTION TO EXERCISE SUCH OPTION, purchase on an AS IS, WHERE IS BASIS all (but not less than all) of the Equipment leased thereunder for a price equal to 32.455 % of the Original Equipment Cost exclusive of the rent payment due for the period (the “Early Purchase Option Price”), together with all taxes (except for those taxes the liability for which has been expressly excluded in Sections 9 and 19 of the Master Lease) and charges upon sale and all other amounts accrued and unpaid under the Lease.  Such amounts shall be paid to Lessor in immediately available funds on the Early Purchase Date.  Lessor and Lessee agree that the Early Purchase Option Price represents a reasonable prediction of the fair market value of the Equipment as of the Early Purchase Date.  

Section 16.

AS IS, WHERE IS Sale.  Notwithstanding any election of Lessee to purchase the Equipment in accordance with this Rider, the provisions of the Lease shall continue in full force and effect until the passage of ownership of the Equipment upon the date of purchase.  Upon the purchase of all of the Equipment and receipt by Lessor of the Early Purchase Option Price, together with all taxes (to the extent payable pursuant to paragraph 1 above) and charges upon sale and all other amounts accrued and unpaid under the Lease, Lessor will transfer, on an AS IS, WHERE IS BASIS, all of Lessor’s interest in such Equipment, at Lessee’s expense shall execute and deliver a bill of sale as reasonably may be required to convey any interest of Lessor in and to such Equipment.  Lessor shall not be required to make and may specifically disclaim any representation or warranty as to the Equipment so p urchased or as to any other matters other than Lessor’s Liens.

Section 17.

Exercise of Options Under All Schedules.  Lessee hereby agrees that an additional condition to its exercising the option provided in this Rider shall be the exercise of that same option with respect to, and in accordance with, all (and not less than all) of the items of Equipment leased under all of the Schedules numbered __ through __ entered into pursuant to the Master Lease (the “Related Lessor Schedules”).  Notwithstanding the foregoing, a Default or Event of Default under fewer than all of the Related Lessor Schedules shall not limit Lessee’s right to exercise the early purchase option provided in the Early Purchase Option Rider with respect to any of the remaining Schedules with respect to which no Default or Event of Default has occurred.

[REMAINDER OF PAGE INTENTIONALLY BLANK; EXECUTION PAGE FOLLOWS.]

45

EXECUTION COPY

IN WITNESS WHEREOF, the parties hereto have caused this Early Purchase Option Rider to be executed in their respective corporate names by their duly authorized officers, all as of the date first written above.

Lessee:  

SOUTHWESTERN ENERGY CORPORATION

By:
Name:
Title:

Lessor:

[LESSOR]


By:
Name:
Title:

WASHINGTON_DC/#980.6

EXHIBIT 2

FORM OF ACCEPTANCE CERTIFICATE

ACCEPTANCE CERTIFICATE

[LESSOR]

[LESSOR’S ADDRESS]

Reference is made herein to Schedule No. ___ dated as of December __, 2006 (the “Schedule”) between SOUTHWESTERN ENERGY COMPANY (together with its successors and assigns, “Lessee”) and [LESSOR] (together with its successors and assigns, “Lessor”) executed pursuant to the Master Lease (as defined in the Schedule).  Capitalized terms used in this Acceptance Certificate and not defined herein shall have the meanings ascribed to such terms in the Schedule, including the Master Lease incorporated therein.   

Lessee hereby certifies to Lessor that (i) all Equipment described in the Schedule has been delivered and installed (if applicable), (ii) Lessee has inspected that Equipment, and all such testing as it deems necessary has been performed by Lessee, Supplier or the manufacturer thereof, (iii) Lessee accepts the Equipment for all purposes of the Lease, (iv) neither a Default nor an Event of Default has occurred, (v) the representations and warranties made by Lessee pursuant to or under the Lease or any related Lease Document are true and correct as if made on the date hereof and (vi) Lessee has reviewed and approves each Supply Contract (as defined in the Master Lease and having the meaning ascribed thereto in UCC § 2A), if any, covering the Equipment described in the Schedule.

WASHINGTON_DC/#980.6

47

This Acceptance Certificate is made for the benefit of Lessor, and no other party may rely on this Acceptance Certificate.

Dated:   December __, 2006.

LESSEE:

SOUTHWESTERN ENERGY COMPANY

By:

Name:

Title:

EXHIBIT 3

FORM OF ACKNOWLEDGMENT AND AGREEMENT

ACKNOWLEDGEMENT AND AGREEMENT

THIS ACKNOWLEDGEMENT AND AGREEMENT (this “Acknowledgement and Agreement”) is being entered into as of December _____, 2006, by and among [_____________________], (together with its successors and assigns, the “Lessor”), SOUTHWESTERN ENERGY CORPORATION (“Lessee”), and DESOTO DRILLING, INC. (“Operator”).

RECITALS

A.

Pursuant to the request by the Lessee, and concurrently with the entering into of this Acknowledgement and Agreement, Lessor is (1) purchasing an onshore drilling rig, including the related equipment, and other property as described in Annex A hereto and as more particularly described in the Lease (as hereinafter defined), (the “Equipment”), and (2) leasing the Equipment to Lessee pursuant to that certain Schedule entered into between Lessee and Lessor concurrently with this Acknowledgement and Agreement (the “Schedule”), incorporating the Master Lease, as defined in the Schedule, together with all related schedules, riders and attachments (as amended and supplemented, the “Lease”).  Capitalized terms not defined in this Acknowledgement and Agreement are defined in the Lease.

B.

In order to induce Lessor to purchase the Equipment, and lease it to Lessee pursuant to the Lease, and as a condition to Lessor’s undertaking the same, Lessee and Operator are entering into this Acknowledgement and Agreement having the terms and conditions set forth below.

NOW THEREFORE, in consideration of the premises and other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, and intending to be legally bound hereby, Lessor, Lessee and Operator agree as follows:

1.

Incorporation of Recitals and Defined Terms.  The Recitals are hereby incorporated into this Acknowledgement and Agreement, and acknowledged as being true and correct by all parties to this Acknowledgement and Agreement.

2.

Confirmation and Acknowledgement.

(a)

Lessee’s Confirmation.  Lessee hereby represents and confirms that Operator is a “Permitted Operator” and that the Use Agreement complies with all of the conditions of Section 13 of the Master Lease.

(b)

Lessor’s Acknowledgment.  Relying on Lessee’s confirmation and representation in subsection (a) above, and the other representations, warranties and agreements herein, in the Master Lease and in the other related Lease Documents, Lessor hereby acknowledges and agrees that Operator shall be undertaking all of the responsibilities contemplated to be taken by a Permitted Operator hereunder, and under the Master Lease and all of the related Lease Documents.

3.

Agreements of Lessee and Operator.  This Acknowledgement and Agreement constitutes a Lease Document and Relevant Third Party Document for purposes of the Lease.  Each of the following agreements by Lessee and Operator  are made for the benefit of, and may be enforced by Lessor:

(a)

Use Agreement.  Except as expressly provided in Section 4 below, (i) no material provision of the Use Agreement shall be modified or waived if such modification or waiver either causes the Use Agreement to be inconsistent with the Lease or this Acknowledgement and Agreement, or impairs Lessor’s rights under the Lease or this Acknowledgement and Agreement, or (as assigned hereby) under the Use Agreement, and (ii) the Use Agreement shall not extend beyond the Term of the Lease.

49

(b)

Subject and Subordinate.  The rights of Operator (and any party claiming through Operator) with respect to the Equipment shall be subject and subordinate in all respects to Lessor’s rights, title and interests in the Equipment, including, all of its rights and remedies hereunder and under any related Lease Documents.

(c)

Location; Inspection.  The Operator shall provide written notice to Lessee and Lessor of the location of the Equipment from time to time, as and when such information is required to be provided by Lessee under the Lease.  Operator agrees that Lessor or its designated employee(s) or agent(s) may inspect the Equipment, any component thereof and all logs, manuals, certificates and records with respect thereto pursuant to, and subject to the limitations set forth in, the Lease.

(d)

No Inconsistent Actions.  Operator acknowledges that it has received from Lessee a current executed copy of all of the documents and agreements constituting the Lease, and that it shall take all necessary actions to remain aware of the then current provisions of the Lease.  Neither Lessee nor Operator will take any action under, or enter into any agreement relating to, the Use Agreement that conflicts with the Lease or this Acknowledgement and Agreement.  Without limiting the foregoing, the Equipment shall not be managed, used, operated, equipped, maintained, repaired, modified, inspected, serviced, located, leased, subleased, assigned, interchanged, conveyed, encumbered, transferred or otherwise disposed of, in a manner that conflicts with the Lease or this Acknowledgement and Agreement.

(e)

Return of Equipment.  Upon the cancellation, termination or expiration of the Lease, unless Lessee has purchased the Equipment pursuant to the Lease, the Use Agreement shall terminate and possession and control of the Equipment will be relinquished to Lessor, except as otherwise elected by Lessor in connection with its exercise of remedies under the Lease and the related Lease Documents.

(f)

Interest in Equipment.  Operator hereby acknowledges and agrees that: (i) it does not have, and it hereby disclaims, any present or future right, title or interest (other than Operator’s contractual right to use the Equipment, as and to the extent provided in the Use Agreement) in or to the Equipment, or any part thereof, and it will keep all of the same free and clear of Liens attributable to Operator, other than Permitted Liens, and (ii) title to any upgrades, modifications, additions, parts, and other related equipment, property or software, attached or added to, incorporated into, or otherwise made a part of the Equipment by Operator or any service provider or vendor pursuant to the Use Agreement, will vest in Lessor, free and clear of Liens for which Operator is responsible, other than Permitted Liens.

4.

Lessee Remains Liable.  Lessee agrees that it is and shall remain fully responsible for all of its obligations under the Lease notwithstanding any provision of the Use Agreement, including, any agreement by Operator to perform its obligations thereunder.  However, Lessor hereby confirms that full, timely and indefeasible performance by Operator of any obligation by Lessee under the Lease in accordance with the applicable provisions thereof shall satisfy such obligations of Lessee.  Without limiting the foregoing, Lessee shall remain responsible for (a) obtaining and maintaining (or causing Operator to obtain and maintain) all of the insurance coverages required under the Lease, in strict accordance with the provisions thereof, and (b) providing, or causing Operator to provide, evidence satisfactory to Lessor of such insurance as and when such evidence is required under the Lease.

5.

Assignment.  Operator shall not sell, assign, sublease, convey, mortgage, exchange or otherwise transfer or relinquish possession of or dispose of, create, assume or suffer to exist any Liens other than Permitted Liens on or with respect to the Equipment.  Each of Lessee and Operator will promptly take such action as directed by Lessor to duly cure any breach of the foregoing. Subject to the foregoing, this Acknowledgement and Agreement shall be binding upon and inure to the benefit of Lessor, Lessee and Operator and their respective permitted successors and assigns.

6.

Lessor’s Rights Upon Default.  Without limiting any term of this Acknowledgement and Agreement or the Lease, upon the occurrence of and the continuation of any Event of Default (whether or not arising hereunder), under the Lease to which this Acknowledgement and Agreement relates, Operator agrees that Lessor shall have the right at its sole election to exercise any and all of its rights, powers and

50

remedies under the Lease and the related Lease Documents.  Each of Lessee and Operator agrees to cooperate with Lessor’s lawful exercise of any such rights, powers and remedies, including the return of the Equipment to Lessor in accordance with the Lease.  Operator shall be liable for any costs, charges or expenses incurred by Lessor in accordance with Sections 16 and 18.1 of the Lease in enforcing or protecting its rights under this Acknowledgement and Agreement.

7.

Indemnity.  Without limiting or otherwise prejudicing any Indemnitee’s rights under any other provision of this Acknowledgement and Agreement, the Lease or the other Lease Documents, Lessee hereby reaffirms for the benefit of Lessor the indemnity and related provisions contained in the Lease and any other Lease Documents, all of which shall be deemed incorporated herein by this reference.  Operator hereby adopts as its own obligations such indemnity and such related provisions.

8.

DISCLAIMER.  LESSOR SHALL NOT BE DEEMED TO HAVE MADE, AND HEREBY DISCLAIMS, ANY REPRESENTATION OR WARRANTY, EITHER EXPRESS OR IMPLIED, AS TO THE EQUIPMENT, INCLUDING ANY RELATED EQUIPMENT, OR ANY MATTER WHATSOEVER, INCLUDING, THE EQUIPMENT’S DESIGN, CONDITION, MERCHANTABILITY, FITNESS FOR ANY PARTICULAR PURPOSE, TITLE, ABSENCE OF ANY PATENT, TRADEMARK OR COPYRIGHT INFRINGEMENT OR LATENT DEFECT (WHETHER OR NOT DISCOVERABLE BY LESSEE, OPERATOR OR ANY OTHER PERSON), COMPLIANCE OF THE EQUIPMENT WITH ANY APPLICABLE LAW, CONFORMITY OF THE EQUIPMENT TO THE PROVISIONS AND SPECIFICATIONS OF ANY PURCHASE DOCUMENT OR TO THE DESCRIPTION SET FORTH IN THE LEASE, OR ANY INTERFERENCE OR INFRINGEMENT, OR ARISING FROM ANY COURSE OF DEALING OR USAGE OF TRADE, NOR SHALL LESSOR BE LIABLE, FOR ANY INDIRECT, INCIDENTAL, SPECIAL OR CONSEQUENTIAL DAMAGES OR FOR STRICT OR ABSOLUTE LIABILIT Y IN TORT; AND EACH OF LESSEE AND OPERATOR HEREBY WAIVES ANY CLAIMS ARISING OUT OF ANY OF THE FOREGOING.

9.

Further Assurances; Notices; Power of Attorney.

(a)

Further Assurances.  Each of Lessee and Operator respectively agrees that it will promptly execute and deliver or cause to be executed and delivered any and all further instruments, assurances and documents as Lessor may reasonably request from time to time consistent with the purposes of this Acknowledgement and Agreement and the Lease to which it relates; and each of them hereby authorizes Lessor to complete and file any Uniform Commercial Code financing statements and other filings, in each such case, as Lessor deems desirable in order to establish, perfect and afford first priority to its interest in the Equipment

(b)

Notices.  All notices, requests, demands and other communications shall be in writing and shall be (a) personally delivered or (b) sent by overnight courier of national reputation, and shall be deemed to have been given on (i) the date received if personally delivered and (ii) the next business day if sent by overnight courier.  All communications shall be addressed to the party to whom notice is being given at its address set forth below its signature on the Lease, or such other address as such party may designate in writing to the other party.  If notice to Lessee of any intended disposition of the Equipment or any other intended action is required by law in a particular instance, such notice shall be deemed commercially reasonable if given (in the manner specified in this Section) at least 10 calendar days prior to the date of intended dis position or other action.

(c)

Power of Attorney.  Each of Lessee and Operator respectively acknowledges that Lessor may exercise its power of attorney granted under the Lease and the related Lease Documents after an Event of Default has occurred and while the same shall be continuing as and when Lessor deems necessary or appropriate to carry out the intent of this Acknowledgement and Agreement.

10.

No Assumption.  Nothing in this Acknowledgement and Agreement shall constitute (a) an assumption by Lessor of any responsibility for the performance by any Person under, or any liability arising in connection with, the Equipment or (b) a waiver or limitation of any of Lessor’s rights or remedies, or Lessee’s or Operator’s respective obligations, under the Lease Documents.

51

11.

[Intentionally Omitted.]

12.

Miscellaneous.

(a)

Governing Law; Binding Effect.  This Acknowledgement and Agreement shall each be deemed to be a contract made under and governed by the internal laws of the State of New York (excluding the laws applicable to conflicts or choice of law other than sections 5-1401 and 5-1402 of the general obligations law of the State of New York), including all matters of construction, validity and performance, and shall be binding upon each of Lessor, Lessee and Operator and their respective successors and assigns and shall inure to the benefit of Lessor and its successors and assigns.  Each of Lessee and Operator hereby irrevocably consents and agrees that any legal action, suit or proceeding arising out of or in any way in connection with this Acknowledgement and Agreement may be instituted or brought in the courts of the State of New York or the U.S. District Court for the Souther n District of New York, as Lessor may elect.  EACH OF LESSEE AND OPERATOR ALSO HEREBY KNOWINGLY AND FREELY WAIVES ALL RIGHTS TO TRIAL BY JURY IN ANY LITIGATION ARISING HEREFROM OR IN RELATION HERETO.  All of Lessor’s rights and privileges and indemnities contained herein (including the indemnities and other provisions incorporated herein pursuant to Section 7 hereof), shall survive the termination, cancellation or expiration of the Lease, the Use Agreement or this Acknowledgement and Agreement.

(b)

Entire Agreement; Modifications; Etc.  This Acknowledgement and Agreement and the Lease Documents contain the entire agreement among the parties hereto regarding the subject matter hereof and completely and fully supersede all other prior agreements, both written and oral, among the parties relating to the subject matter of this Acknowledgement and Agreement.  Any agreements, acknowledgments, indemnifications, representations and warranties in this Acknowledgement and Agreement by Lessee and/or Operator in favor of Lessor shall be deemed to supplement and be a part of the Lease but the Lease Documents shall otherwise remain unmodified and in full force and effect.  This Acknowledgement and Agreement may not be amended except by a writing signed by a Lessor and Lessee and shall be binding upon and inure to the benefit of the parties hereto, their permitted succes sors and assigns; provided, however, any amendment to this Acknowledgement and Agreement by a Lessor shall only be binding with respect to the parties hereto, and not as to any other related Lease Document.  Any waiver shall be effective only in the specific instance and for the specific purpose for which it is given.  No failure to exercise, or delay in exercising, any right hereunder shall operate as a waiver of such right; nor shall any failure to exercise, or partial exercise of, any right under this Acknowledgement and Agreement preclude any other or further exercise of such right or the exercise of any other right.  Any provision of this Acknowledgement and Agreement which is unenforceable in any jurisdiction shall, as to such jurisdiction, be ineffective to the extent of such prohibition or unenforceability without invalidating the remaining provisions hereof, and any such prohibition or unenforceability in any jurisdiction shall not invalidate or render unenforceable such provision in any other jurisdiction.  This Acknowledgement and Agreement may be executed in any number of counterparts, each of which shall be an original but all of which when taken together shall constitute but a single instrument.  The headings in this Acknowledgement and Agreement are for convenience only and shall not limit or otherwise affect any of the terms hereof.  As between themselves, each of Operator and Lessee hereby waives any and all rights and claims based on suretyship as and to the extent the same may be, or are deemed to be, available to either or both of them by reason of their indemnities and other agreements hereunder.  

(SIGNATURES ON NEXT PAGE)

52

IN WITNESS WHEREOF, the parties hereto have caused this Acknowledgement and Agreement to be executed by their respective duly authorized representatives as of the date first above written.

[_______________________________] Lessor By:   Name:   Title:	SOUTHWESTERN ENERGY CORPORATION Lessee By:   Name:   Title:
Notice Information:	Notice Information: Telephone: Facsimile:
	DESOTO DRILLING, INC. Operator By:   Name:   Title:
	Notice Information: Telephone: Facsimile:

53

CHICAGO/#1578913.20

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
DeSoto Drilling, Inc.	Arkansas
Southwestern Midstream Services Company	Arkansas
Southwestern Energy Services Company	Arkansas
DeSoto Gas Gathering 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, 333-125714 and 333-121720) and Form S-3 (File Nos. 333-125859 and 333-126884) of Southwestern Energy Company of our report dated February 28, 2007 relating to the consolidated 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
February 28, 2007

EX-23

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, 2006, 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, 333-110140, 333-125714 and 333-121720) and Form S-3 (File Nos. 333-125859 and 333-126884).

NETHERLAND, SEWELL & ASSOCIATES, INC.
By	/s/ DANNY D. SIMMONS
	Danny D. Simmons, P.E.
	Executive Vice President

Houston, Texas
February 26, 2007

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)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) 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:	February 28, 2007		/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)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) 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:	February 28, 2007		/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, 2006 (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: February 28, 2007	/s/ HAROLD M. KORELL
	Harold M. Korell
	Chief Executive Officer
Dated: February 28, 2007	/s/ GREG D. KERLEY
	Greg D. Kerley
	Chief Financial Officer

CORRESP

Southwestern Energy Company
P.O. Box 13408
Fayetteville, AR 72702-1408

February 28, 2007

Securities and Exchange Commission
ATTN: Filing Desk, Stop 1-4
450 Fifth Street, N. W.
Washington, DC 20549-1004

Gentlemen:

Pursuant to regulations of the Securities and Exchange Commission, submitted herewith for filing on behalf of Southwestern Energy Company is an Annual Report on Form 10-K for the year ended December 31, 2006.

This filing is being effected by direct transmission to the Commission's EDGAR System.

Very truly yours,
 

Stanley T. Wilson
Controller