10-Q

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
(Mark one)
[ X ] Quarterly Report Pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934
For the quarterly period ended March 31, 2008
or
[    ] Transition Report Pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934
For the transition period from___________ to ___________
Commission file number:   1-08246
SOUTHWESTERN ENERGY COMPANY
(Exact name of the registrant as specified in its charter)
Delaware	71-0205415
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
2350 N. Sam Houston Pkwy. E., Suite 125, Houston, Texas	77032
(Address of principal executive offices)	(Zip Code)
(281) 618-4700
(Registrant's telephone number, including area code)
Not Applicable
(Former name, former address and former fiscal year; if changed since last report)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
Yes:   X	No:
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company.  See the definitions of "large accelerated filer", "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer   X          Accelerated filer                 Non-accelerated filer          Smaller reporting company
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yes:	No:   X
Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date:
Class	Outstanding at April 22, 2008
Common Stock, Par Value $0.01	341,963,375

CAUTIONARY STATEMENT ABOUT FORWARD-LOOKING STATEMENTS

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, except as may be required by law.

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

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 fund our planned capital investments;

·

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

·

the impact of federal, state and local government regulation, including any increase in severance taxes;

·

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 future property acquisition or divestiture activities;

·

the effects of weather;

1

·

increased competition;

·

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 Securities and Exchange Commission (“SEC”).

We caution you that these forward-looking statements contained in this Form 10-Q 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 our Annual Report on Form 10-K for the year ended December 31, 2007 (the “2007 Annual Report on Form 10-K”), and all quarterly reports on Form 10-Q filed subsequently thereto, including this Form 10-Q (“Form 10-Qs&# 148;).

Should one or more of the risks or uncertainties described above or elsewhere in this Form 10-Q 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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PART I

FINANCIAL INFORMATION

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SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES
STATEMENTS OF OPERATIONS
(Unaudited)
		For the three months ended
		March 31,
		2008		2007
		(in thousands, except share/per share amounts)
Operating Revenues:
	Gas sales	$	360,671	$	211,644
	Gas marketing		137,227		55,317
	Oil sales		13,713		9,237
	Gas gathering, transportation and other		12,495		8,454
			524,106		284,652
Operating Costs and Expenses:
	Gas purchases - midstream services		132,452		53,217
	Gas purchases - gas distribution		51,895		47,981
	Operating expenses		23,996		20,037
	General and administrative expenses		23,740		16,748
	Depreciation, depletion and amortization		97,097		55,785
	Taxes, other than income taxes		7,416		7,125
			336,596		200,893
Operating Income			187,510		83,759
Interest Expense:
	Interest on long-term debt		17,086		4,125
	Other interest charges		648		381
	Interest capitalized		(6,205)		(3,048)
			11,529		1,458
Other Income			7		21
Income Before Income Taxes and Minority Interest			175,988		82,322
Minority Interest in Partnership			(135)		(83)
Income Before Income Taxes			175,853		82,239
Provision for Income Taxes - Deferred			66,824		31,251
Net Income		$	109,029	$	50,988
Earnings Per Share:
	Basic	$	0.32	$	0.15	(1)
	Diluted	$	0.31	$	0.15	(1)
Weighted Average Common Shares Outstanding:
	Basic	341,064,247		337,202,714		(1)
	Diluted	348,196,507		344,064,964		(1)
(1) Restated to reflect the two-for-one stock split effected on March 25, 2008.
The accompanying notes are an integral part of these consolidated financial statements.
4

SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES
BALANCE SHEETS
(Unaudited)
ASSETS
			March 31,		December 31,
			2008		2007
			(in thousands)
Current Assets
	Cash and cash equivalents		$	471	$	727
	Accounts receivable			216,903		177,680
	Inventories, at average cost			22,139		33,034
	Hedging asset - FAS 133			13,084		64,472
	Deferred income tax benefit			69,345		-
	Current assets held for sale (see Note 4)			51,973		58,877
	Other			23,468		28,551
		Total current assets		397,383		363,341
Property, Plant and Equipment, at cost
	Gas and oil properties, using the full cost method,       including $455.7 million in 2008 and $372.4 million       in 2007 excluded from amortization			4,393,487		4,020,448
	Gathering systems			190,113		158,604
	Gas in underground storage			13,349		13,349
	Other			90,044		85,983
				4,686,993		4,278,384
	Less: Accumulated depreciation, depletion and amortization			1,296,250		1,200,754
				3,390,743		3,077,630
Assets Held for Sale (see Note 4)				142,310		143,234
Other Assets				44,326		38,511
Total Assets			$	3,974,762	$	3,622,716
The accompanying notes are an integral part of these consolidated financial statements.
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SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES
BALANCE SHEETS
(Unaudited)
LIABILITIES AND STOCKHOLDERS' EQUITY
			March 31,		December 31,
			2008		2007
			(in thousands)
Current Liabilities
	Current portion of long-term debt		$	1,200	$	1,200
	Accounts payable			346,857		313,070
	Taxes payable			6,542		5,087
	Advances from partners			33,203		32,005
	Hedging liability - FAS 133			209,245		8,598
	Current deferred income taxes			-		20,909
	Current liabilities associated with assets held for sale (see Note 4)			33,759		39,118
	Other			21,427		10,908
		Total current liabilities		652,233		430,895
Long-Term Debt				1,076,600		977,600
Other Liabilities
	Deferred income taxes			519,780		479,196
	Long-term hedging liability			78,793		15,186
	Pension liability			13,628		12,268
	Liabilities associated with assets held for sale (see Note 4)			18,639		15,417
	Other			37,398		35,084
				668,238		557,151
Commitments and Contingencies
Minority Interest in Partnership				10,705		10,570
Stockholders' Equity
	Common stock, $0.01 par value; authorized 540,000,000     shares, issued 341,952,429 shares in 2008     and 341,581,672 in 2007 (1)			3,420		3,416
	Additional paid-in capital (1)			755,800		752,369
	Retained earnings			991,060		882,031
	Accumulated other comprehensive income (loss)			(178,578)		13,348
	Common stock in treasury, 224,393 shares in 2008     and 222,774 in 2007 (1)			(4,716)		(4,664)
				1,566,986		1,646,500
Total Liabilities and Stockholders' Equity			$	3,974,762	$	3,622,716
(1) 2007 restated to reflect the two-for-one stock split effected on March 25, 2008.
The accompanying notes are an integral part of these consolidated financial statements.
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SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES
STATEMENTS OF CASH FLOWS
(Unaudited)
			For the three months ended
			March 31,
			2008		2007
			(in thousands)
Cash Flows From Operating Activities
	Net income		$	109,029	$	50,988
	Adjustments to reconcile net income to
	net cash provided by operating activities:
		Depreciation, depletion and amortization		97,635		56,114
		Deferred income taxes		66,824		31,251
		Unrealized loss on derivatives		7,636		2,474
		Stock-based compensation expense		2,458		1,493
		Minority interest in partnership		135		83
	Change in assets and liabilities:
		Accounts receivable		(39,007)		(16,831)
		Inventories		21,218		14,627
		Under/over-recovered purchased gas costs		(3,792)		3,193
		Accounts payable		13,156		1,268
		Advances from partners and customer deposits		1,193		(3,148)
		Other assets and liabilities		20,602		(13,101)
	Net cash provided by operating activities			297,087		128,411
Cash Flows From Investing Activities
	Capital investments			(391,029)		(372,664)
	Proceeds from sale of property, plant and equipment			895		2,459
	Other items			(433)		(245)
	Net cash used in investing activities			(390,567)		(370,450)
Cash Flows From Financing Activities
	Payments on revolving long-term debt			(927,400)		(150,800)
	Borrowings under revolving long-term debt			426,400		341,600
	Proceeds from issuance of long-term debt			600,000		-
	Debt issuance costs			(8,883)		(1,278)
	Excess tax benefit for stock-based compensation			-		11,457
	Change in bank drafts outstanding			2,919		(3,901)
	Proceeds from exercise of common stock options			818		2,922
	Net cash provided by financing activities			93,854		200,000
Increase (decrease) in cash and cash equivalents				374		(42,039)
Cash and cash equivalents at beginning of year				1,832		42,927
Cash and cash equivalents at end of period			$	2,206	$	888
The accompanying notes are an integral part of these consolidated financial statements.
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SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES
STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY AND COMPREHENSIVE INCOME (LOSS)
(Unaudited)
									Accumulated
	Common Stock (1)				Additional				Other		Common
	Shares				Paid-In		Retained		Comprehensive		Stock in
	Issued		Amount		Capital (1)		Earnings		Income (Loss)		Treasury		Total
	(in thousands)
Balance at December 31, 2007	341,578	$	3,416	$	752,369	$	882,031	$	13,348	$	(4,664)	$	1,646,500
Comprehensive income:
Net income	-		-		-		109,029		-		-		109,029
Change in value of derivatives	-		-		-		-		(192,135)		-		(192,135)
Change in value of pension liability	-		-		-		-		209		-		209
Total comprehensive income (loss)													(82,897)
Stock-based compensation - FAS 123(R)	-		-		2,550		-		-		-		2,550
Exercise of stock options	365		4		814		-		-		-		818
Issuance of restricted stock	13		-		-		-		-		-		-
Cancellation of restricted stock	(7)		-		-		-		-		-		-
Issuance of stock awards	3		-		67		-		-		-		67
Treasury stock - non-qualified plan	-		-		-		-		-		(52)		(52)
Balance at March 31, 2008	341,952	$	3,420	$	755,800	$	991,060	$	(178,578)	$	(4,716)	$	1,566,986
(1) 2007 restated to reflect the two-for-one stock split effected on March 25, 2008.

STATEMENT OF COMPREHENSIVE INCOME (LOSS)
		For the three months ended
		March 31,
		2008		2007
		(in thousands)
Net income		$	109,029	$	50,988
Change in value of derivatives
	Current period reclassification to earnings		(11,712)		(12,270)
	Current period ineffectiveness		8,459		4,923
	Current period change in derivative instruments		(188,882)		(50,818)
	Total change in value of derivatives		(192,135)		(58,165)
Current period change in pension and other postretirement liability			209		-
Comprehensive income (loss), end of period		$	(82,897)	$	(7,177)
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

March 31, 2008

(1)

BASIS OF PRESENTATION

The financial statements included herein are unaudited; however, such information reflects all adjustments (consisting solely of normal recurring adjustments) which are, in the opinion of management, necessary for a fair presentation of the results for the interim periods. The Company's significant accounting policies, which have been reviewed and approved by the audit committee of the Company’s Board of Directors, are summarized in Note 1 of the Notes to Consolidated Financial Statements included in Item 8 of the Company's Annual Report on Form 10-K for the year ended December 31, 2007 (the "2007 Annual Report on Form 10-K").

In February 2008, the Board of Directors declared a two-for-one stock split with respect to the Company’s common stock, which was effected in March 2008. All historical per share information in the financial statements and footnotes has been adjusted to reflect the two-for-one stock split.

Certain reclassifications have been made to the prior years’ financial statements to conform to the 2008 presentation. The effects of the reclassifications were not material to the Company’s consolidated financial statements.

(2)

GAS AND OIL PROPERTIES

The Company utilizes the full cost method of accounting for costs related to the exploration, development, and acquisition of natural gas and oil reserves. Under this method, all such costs (productive and nonproductive), including salaries, benefits and other internal costs directly attributable to these activities are capitalized and amortized on an aggregate basis over the estimated lives of the properties using the units-of-production method. 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 natural 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 March 31, 2008 and 2007, the Company’s unamortized costs of natural gas and oil properties did not exceed this ceiling amount. At March 31, 2008, the ceiling value of the Company’s reserves was calculated based upon quoted market prices of $9.37 per Mcf for Henry Hub gas and $98.00 per barrel for West Texas Intermediate oil, adjusted for market differentials.  Cash flow hedges of gas production in place at March 31, 2008, decreased the calculated ceiling value by approximately $99.7 million (net of tax). The Company had approximately 259.5 Bcf of future gas production hedged at March 31, 2008. Decreases in market prices from March 31, 2008 levels, as well as changes in production rates, levels of reserves, the evaluation of costs excluded from amortization, future development costs, and service costs could result in future ceiling test impairments.

9

(3)

EARNINGS PER SHARE

The following table presents the computation of earnings per share for the three months ended March 31, 2008 and 2007, respectively.  For the period ended March 31, 2007, all shares and per share amounts (including exercise prices for assumed exercises of stock options) have been restated to reflect the two-for-one stock split effected on March 25, 2008:

	For the three months ended
	March 31,
	2008	2007
Net Income (in thousands)	$      109,029	$       50,988
Number of Common Shares:
Weighted average outstanding	341,064,247	337,202,714
Issued upon assumed exercise of outstanding stock options	6,797,795	6,492,410
Effect of issuance of nonvested restricted common shares	334,465	369,840
Weighted average and potential dilutive outstanding (1)	348,196,507	344,064,964
Net Income per Common Share:
Basic	$            0.32	$           0.15
Diluted	$            0.31	$           0.15

 (1)  Options for 396,840 shares for the three months ended March 31, 2008 and 873,330 shares for the comparable period of 2007 (as adjusted for the stock split) were excluded from the calculations because they would have had an antidilutive effect.  Additionally, 1,613 shares of restricted stock for the three months ended March 31, 2008 and 19,800 shares of restricted stock for the comparable period of 2007 (as adjusted for the stock split) were excluded from the calculations because they would have had an antidilutive effect.

(4)

ASSETS HELD FOR SALE

In November 2007, the Company entered into an agreement to sell all of the capital stock of Arkansas Western Gas Company (“AWG”) for $224 million plus working capital. Statement of Financial Accounting Standards No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets" (FAS 144), requires that long-lived assets or disposal groups to be sold should be classified as “held for sale” in the period in which certain criteria are met.  Accordingly, the assets and liabilities of AWG have been presented as “held for sale” in the March 31, 2008 and December 31, 2007 balance sheets.

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The following table presents the assets and liabilities of AWG as of March 31, 2008 and December 31, 2007:

	March 31,		December 31,
	2008		2007
	(in thousands)
Current Assets:
Cash	$	1,736	$	1,105
Accounts receivable		29,610		29,826
Inventory		14,485		23,737
Hedging asset - FAS 133		-		2,387
Deferred income tax benefit		4,504		-
Other current assets		1,638		1,822
	$	51,973	$	58,877
Long-term assets, including property, plant and equipment, net of
accumulated depreciation and amortization	$	142,310	$	143,234
Current Liabilities:
Accounts payable	$	2,742	$	3,700
Taxes payable		9,273		7,547
Deferred gas purchases		12,498		16,289
Customer deposits		7,545		7,551
Hedging liability - FAS 133		-		2,387
Other current liabilities		1,701		1,644
	$	33,759	$	39,118
Long-term Liabilities:
Deferred income taxes	$	18,427	$	15,066
Other long-term liabilities		212		351
	$	18,639	$	15,417

(5)

DEBT

Debt balances as of March 31, 2008 and December 31, 2007 consisted of the following:

	March 31,	December 31,
	2008	2007
	(in thousands)
Current portion of long-term debt:
7.15% Senior Notes due 2018	$         1,200	$     1,200
Long-term:
Variable rate (3.91% at March 31, 2008) unsecured revolving       credit facility	341,200	842,200
7.5% Senior Notes due 2018	600,000	-
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	35,400	35,400
Total long-term debt	1,076,600	977,600
Total debt	$  1,077,800	$  978,800

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On January 16, 2008, the Company issued $600 million of 7.5% Senior Notes due 2018 in a private placement. The 7.5% Senior Notes are redeemable at the Company’s election, in whole or in part, at any time at a redemption price equal to the greater of: (1) 100% of the principal amount of the notes to be redeemed then outstanding; and (2) the sum of the present values of the remaining scheduled payments of principal and interest on the notes to be redeemed (not including any portion of such payments of interest accrued to the date of redemption) discounted to the redemption date on a semiannual basis as determined in accordance with the indenture, plus 50 basis points, plus, in either of such cases, accrued and unpaid interest to the date of redemption on the notes to be redeemed. In addition, if the Company undergoes a “change of control,” as defined in the indenture, holders of the 7.5% Senior Notes will have the option to require the Company to purchase all or any portion of the notes at a purchase price equal to 101% of the principal amount of the notes to be purchased plus any accrued and unpaid interest to, but excluding, the change of control date. Payment obligations with respect to the 7.5% Senior Notes are currently guaranteed by the Company’s subsidiaries, SEECO, Inc. (SEECO), Southwestern Energy Production Company (SEPCO) and Southwestern Energy Services (SES), which guarantees may be unconditionally released in certain circumstances. The indentures governing the 7.5% Senior Notes and the Company’s other senior notes contain covenants that, among other things, restrict the ability of the Company and/or its subsidiaries to incur liens, to engage in sale and leaseback transactions and to merge, consolidate or sell assets.

In October 2007, the Company amended its unsecured revolving credit facility increasing the borrowing capacity to $1.0 billion.  The amendment also provides that the amount available under the revolving credit facility may be increased to $1.25 billion at any time upon the Company’s agreement with its existing or additional lenders. The interest rate on the amended credit facility is calculated based upon the Company’s debt rating and is currently 87.5 basis points over the current London Interbank Offered Rate (LIBOR). The revolving credit facility is currently guaranteed by the Company’s subsidiaries, SEECO, SEPCO, and SES and requires additional subsidiary guarantors if certain guaranty coverage levels are not satisfied. At March 31, 2008, the Company’s capital structure consisted of 41% debt and 59% equity and it was in compliance with the covenants of its debt agreements .

(6)

 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.  At March 31, 2008, our gas derivative instruments consisted of price swaps, costless collars and basis swaps. Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities" (FAS 133), as amended by FAS 137, FAS 138, FAS 149 and FAS 157 (see Note 7 below regarding the adoption of FAS 157 in the first quarter of 2008), requires that all derivatives be recognized in the balance sheet as either an asset or liability measured at its fair value. Accounting for qualifying hedges allows a derivative's gains and losses to be recorded as a component of other comprehensive income. Hedges that are not elected for hedge accounting treatment or that do not meet the requirements of FA S 133 cannot be recorded as a component of other comprehensive income. The Company’s hedging practices are summarized in Note 9 of the Notes to Consolidated Financial Statements in the 2007 Annual Report on Form 10-K.

At March 31, 2008, the Company's net liability recorded on the balance sheet related to its hedging activities was $269.8 million. Additionally, at March 31, 2008, the Company recorded a loss to other comprehensive income of $167.5 million related to its hedging activities which resulted in a current

12

deferred income tax benefit of $63.6 million. The amount recorded in other comprehensive income will be relieved over time and taken to the income statement as the physical transactions being hedged occur. Assuming the market prices of gas futures as of March 31, 2008 remain unchanged, the Company would expect to transfer an aggregate after-tax loss of approximately $120.3 million from accumulated other comprehensive income to earnings during the next 12 months. The change in accumulated other comprehensive income related to derivatives was a loss of $309.9 million ($192.1 million after tax) and a loss of $93.8 million ($58.2 million after tax) for the three months ended March 31, 2008 and 2007, respectively. The Company recorded a $7.6 million decrease in gas sales revenues during the first quarter of 2008 related to the ineffectiveness of cash flow hedges and changes in unrealized gains or losses for derivatives tha t were not accounted for as cash flow hedges. Additional volatility in earnings and other comprehensive income may occur in the future as a result of the application of FAS 133.

(7)

FAIR VALUE MEASUREMENTS

Effective January 1, 2008, the Company adopted Statement of Financial Accounting Standards No. 157, "Fair Value Measurements" (FAS 157), which defines fair value, provides a framework for measuring fair value under generally accepted accounting principles (GAAP) and expands required disclosures about fair value measurements. The Company also adopted Statement of Financial Accounting Standards No. 159, "The Fair Value Option for Financial Assets and Financial Liabilities" (FAS 159), on January 1, 2008, which allows an entity the irrevocable option to elect fair value for the initial and subsequent measurement for certain financial assets and liabilities on a contract-by-contract basis. The Company does not plan to elect to use the fair value option under FAS 159 for any of its financial instruments that are not currently measured at fair value.

FAS 157 establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. As presented in the tables below, this hierarchy consists of three broad levels. Level 1 valuations consist of unadjusted quoted prices in active markets for identical assets and liabilities and has the highest priority. Level 2 fair value valuations rely on quoted market information for the calculation of fair market value. Level 3 valuations are internal estimates and have the lowest priority. Per FAS 157, the Company has classified its derivatives into these levels depending upon the data relied on to determine the fair values. The Company’s natural gas swaps are estimated using internal discounted cash flow calculations using the NYMEX futures index and are designated as Level 2. The fair values of collars and natural gas basis swaps are estimated using internal discounted cash flow calculations based upon forward commodity price curves or quotes obtained from counterparties to the agreements and are designated as Level 3. Assets and liabilities measured at fair value on a recurring basis are summarized below:

	March 31, 2008
	(in thousands)
	Fair Value Measurements Using:
	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Assets/Liabilities at Fair Value
Derivative assets	$	-	$	3,688	$	57,979	$	61,667
Derivative liabilities		-		(220,017)		(111,492)		(331,509)
Total	$	-	$	(216,329)	$	(53,513)	$	(269,842)

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The table below presents a reconciliation for assets and liabilities measured at fair value on a recurring basis using significant unobservable inputs (Level 3) during the first quarter of 2008. The fair values of Level 3 derivative instruments are estimated using proprietary valuation models that utilize both market observable and unobservable parameters. Level 3 instruments presented in the table consist of net derivatives valued using pricing models incorporating assumptions that, in management’s judgment, reflect the assumptions a marketplace participant would have used at March 31, 2008.

Total Gains and Losses (Level 3 Only)
	Net
	Derivatives
	(in thousands)
Balance at January 1, 2008	$	32,767
Total gains or losses (realized/unrealized):
Included in earnings(1)		9,333
Included in other comprehensive income (loss)		(84,378)
Purchases, Issuances and Settlements		(11,235)
Transfers in to/out of Level 3		-
Balance at March 31, 2008	$	(53,513)
Change in unrealized gains (losses) included in earnings relating to derivatives still held as of March 31, 2008	$	(1,902)

(1)  Reported in gas sales revenue in the consolidated statements of operations.

(8)

SEGMENT INFORMATION

The Company’s three reportable business segments, Exploration and Production (E&P), Midstream Services and Natural Gas Distribution, 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 are expected to increase in the future as the level of production from our Fayetteville Shale properties continues to increase. Revenues for the Natural Gas Distribution segment arise from the transportation and sale of natural gas at retail by AWG. Following the consummation of the pending sale of AWG, the Company will not have any natural gas distribution operations.

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 of the Notes to Consolidated Financial Statements included in Item 8 of the 2007 Annual Report on Form 10-K. Management evaluates the performance of its segments based on operating income, defined as operating revenues less operating costs and expenses. Income before income taxes 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 and corporate items.

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	Exploration And Production	Midstream Services	Natural Gas Distribution	Other		Total
	(in thousands)
Three months ended March 31, 2008:
Revenues from external customers	$    297,099	$     145,523	$     81,484	$          -		$    524,106
Intersegment revenues	14,918	259,802	2,707	112		277,539
Operating income	165,710	10,161	11,590	49		187,510
Other income (expense)	114	-	(107)	-		7
Depreciation, depletion and amortization expense	93,306	2,037	1,718	36		97,097
Interest expense (1)	8,770	1,551	1,208	-		11,529
Provision for income taxes (1)	59,629	3,272	3,904	19		66,824
Assets	3,351,181	354,207	194,283	75,091	(2)	3,974,762	(2)
Capital investments (3)	376,514	31,445	991	908		409,858
Three months ended March 31, 2007:
Revenues from external customers	$    151,455	$     56,319	$     76,878	$          -		$    284,652
Intersegment revenues	9,806	122,270	116	112		132,304
Operating income	74,310	11	9,381	57		83,759
Other income (expense)	72	-	(51)	-		21
Depreciation, depletion and amortization expense	53,074	1,042	1,634	35		55,785
Interest expense (1)	93	-	1,365	-		1,458
Provision for income taxes (1)	28,197	4	3,027	23		31,251
Assets	2,151,721	148,035	185,956	61,086	(2)	2,546,798	(2)
Capital investments (3)	301,198	21,620	2,604	1,831		327,253

(1)

Interest expense and the provision for income taxes by segment are allocated as they are incurred at the corporate level.

(2)

Other assets include corporate assets not allocated to segments and assets for non-reportable segments.

(3)

Capital investments include an increase of $16.8 million and a reduction of $46.3 million for the three-month periods ended March 31, 2008 and 2007, respectively, relating to the change in accrued expenditures between periods.

Included in intersegment revenues of the Midstream Services segment are $239.1 million and $107.0 million for the first quarters of 2008 and 2007, 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 and other 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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INTEREST AND INCOME TAXES PAID

The following table provides interest and income taxes paid during each period presented:

	For the three months ended
	March 31,
	2008		2007
	(in thousands)
Interest payments	$	5,702	$	1,181
Income tax payments	$	-	$	-

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CONTINGENCIES AND COMMITMENTS

Operating Commitments

The Company has various operating commitments in the normal course of its operations. In the first quarter of 2008, the Company exercised the first of its three options to increase the volumes to be transported on each of the two pipeline laterals and related facilities being constructed by Texas Gas Transmission, LLC for which the Company is the anchor shipper. The options exercised will allow the Company to transport up to 600,000 MMBtu per day on the Fayetteville Lateral and up to 480,000 MMBtu per day on the Greenville Lateral. Other than the increase in pipeline volume commitments, the Company has not made any new material operating commitments or modified its disclosed material commitments from those disclosed in the 2007 Annual Report on Form 10-K.

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 currently pending will not have a material effect on the results of operations or the financial position of the Company.

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STOCK-BASED COMPENSATION

The Company has incentive plans that provide for the issuance of equity awards, including stock options and restricted stock. These plans are discussed more fully in Note 10 of the Notes to Consolidated Financial Statements included in Item 8 of the 2007 Annual Report on Form 10-K.

For the three months ended March 31, 2008 and 2007, the Company recorded compensation cost of $0.8 million and $0.7 million, respectively, in general and administrative expense related to stock options. An additional amount of $0.2 million for each of the same respective periods 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 Company also recorded a deferred tax benefit of $0.2 million related to stock options for the three months ended March 31, 2008, compared to a deferred tax benefit of $0.3 million for the comparable period in 2007. A total of $6.6 million of unrecognized compensation costs related to stock options not yet vested is expected to be recognized over future periods.

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For the three-month periods ended March 31, 2008 and 2007, the Company recorded compensation cost of $0.9 and $0.7 million, respectively, in general and administrative expense related to prior restricted stock grants. Additional amounts of $0.7 million and $0.5 million for the same respective periods 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. As of March 31, 2008, there was $12.8 million of total unrecognized compensation cost related to nonvested shares of restricted stock.

The following tables summarize stock option activity for the first three months of 2008 and provide information for options outstanding at March 31, 2008. The number of options and exercise prices have been restated, as necessary, to reflect the two-for-one stock split effected on March 25, 2008:

	Number  of Options	Weighted Average Exercise  Price
Outstanding at December 31, 2007	8,552,874	$     4.81
Granted	14,000	27.12
Exercised	(365,356)	2.24
Forfeited or expired	-	-
Outstanding at March 31, 2008	8,201,518	$     4.97
Exercisable at March 31, 2008	7,345,909	$     2.84

During the first three months of 2008, there were 14,000 options granted, compared to no options granted during the first three months of 2007. The total intrinsic value of options exercised during the first three months of 2008 and 2007 was $9.4 million and $31.2 million, respectively. Associated with the exercise of stock options, the Company recorded a tax benefit of $11.5 million in the first three months of 2007. The tax benefit was recorded as an increase in additional paid-in capital.

	Options Outstanding				Options Exercisable
Range of Exercise Prices	Options Outstanding at March 31, 2008	Weighted Average Exercise Price	Weighted Average Remaining Contractual Life (Years)	Aggregate Intrinsic Value (in thousands)	Options Exercisable at March 31, 2008	Weighted Average Exercise Price	Aggregate Intrinsic Value (in thousands)
$0.75 - $1.00	2,931,444	$       0.88	2.3		2,931,444	$      0.88
$1.01 - $2.50	2,021,166	1.37	4.2		2,021,166	1.37
$2.51 - $6.00	1,305,310	2.75	5.7		1,305,310	2.75
$6.01 - $17.75	1,060,888	10.42	4.1		926,536	9.36
$17.76 - $27.18	882,710	23.49	6.1		161,453	20.07
	8,201,518	$       4.97	4.0	$  235,570	7,345,909	$       2.84	$  226,621

The following table summarizes restricted stock activity for the first quarter of 2008. The number of shares and the grant date fair values have been restated, as necessary, to reflect the two-for-one stock split effected on March 25, 2008:

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	Number of  Shares	Weighted Average Grant Date  Fair Value
Unvested shares at December 31, 2007	791,030	$   19.89
Granted	12,500	28.74
Vested	(17,786)	13.99
Forfeited	(7,097)	22.72
Unvested shares at March 31, 2008	778,647	$   20.14

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PENSION PLAN AND OTHER POSTRETIREMENT BENEFITS

The Company applies Statement of Financial Accounting Standards No. 158, "Employers' Accounting for Defined Benefit Pension and Other Postretirement Plans." Substantially all employees are covered by the Company's defined benefit pension and postretirement benefit plans. Net periodic pension and other postretirement benefit costs include the following components for the three-month periods ended March 31, 2008 and 2007:

	Pension Benefits
	For the three months ended March 31,
	2008	2007
	(in thousands)
Service cost	$       1,408	$      996
Interest cost	1,210	1,060
Expected return on plan assets	(1,255)	(1,140)
Amortization of prior service cost	122	119
Amortization of net loss	174	115
Net periodic benefit cost	$    1,659	$      1,150

	Postretirement Benefits
	For the three months ended March 31,
	2008	2007
	(in thousands)
Service cost	$      165	$        104
Interest cost	77	54
Expected return on plan assets	(24)	(20)
Amortization of transition obligation	22	22
Amortization of prior service cost	3	-
Amortization of net loss	17	5
Net periodic benefit cost	$      260	$      165

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The Company currently expects to contribute $8.1 million to the pension plans and $0.4 million to the postretirement benefit plans in 2008. As of March 31, 2008, no contributions have been made to the pension plans, and $0.1 million has been contributed to the postretirement benefit plans.

The Company also maintains a non-qualified defined contribution supplemental retirement savings plan for certain key employees whereby participants may elect to defer and contribute a portion of their compensation, as permitted by the plan. The Company maintains supplemental retirement savings plan assets that are accounted for in accordance with EITF Issue No. 97-14, “Accounting for Deferred Compensation Arrangements Where Accounts are Held in a Rabbi Trust and Invested” (EITF 97-14), and the underlying assets are held in a Rabbi Trust.  Shares of the Company’s common stock purchased under a non-qualified deferred compensation arrangement are held in a Rabbi Trust and are presented as treasury stock. As of March 31, 2008, 224,393 shares were accounted for as treasury stock, compared to 222,774 shares at December 31, 2007.

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ASSET RETIREMENT OBLIGATIONS

Financial Accounting Standards No. 143, "Accounting for Asset Retirement Obligations," (FAS 143) requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made, and that the associated asset retirement costs be capitalized as part of the carrying amount of the long-lived asset. The Company owns natural gas and oil properties which require expenditures to plug and abandon the wells when reserves in the wells are depleted. These expenditures under FAS 143 are recorded in the period the liability is incurred (at the time the wells are drilled or acquired). The following table summarizes the Company's activity related to asset retirement obligations (in thousands) for the three-month period ended March 31, 2008 and for the year ended December 31, 2007:

Asset retirement obligation at January 1	$  12,114	$    10,545
Accretion of discount	124	481
Obligations incurred	914	2,236
Obligations settled/removed	(301)	(499)
Revisions of estimates	-	(649)
Asset retirement obligation at March 31, 2008 and December 31, 2007	$  12,851	$  12,114
Current liability	729	720
Long-term liability	12,122	11,394
Asset retirement obligation at March 31, 2008 and December 31, 2007	$  12,851	$  12,114

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INVENTORY

Inventory recorded in current assets includes $11.5 million at March 31, 2008, and $25.0 million at December 31, 2007, for gas in underground storage owned by the Company’s E&P segment, and $10.5 million at March 31, 2008, and $8.1 million at December 31, 2007, for tubulars and other equipment used in the Company’s E&P segment. Additionally, the Natural Gas Distribution segment has current gas in underground storage of $12.2 million at March 31, 2008, and $21.6 million at December 31, 2007, that is classified in the balance sheets as “Current Assets Held for Sale.”

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Other assets includes $15.6 million at March 31, 2008, and $16.7 million at December 31, 2007, for non-current inventory held by the Midstream Services segment consisting primarily of tubulars that will be used to construct gathering systems for the Fayetteville Shale play.

(15)

SUBSEQUENT EVENTS

On April 3, 2008, the Company announced that its wholly-owned subsidiary had entered into a definitive purchase and sale agreement with XTO Energy Inc. for the sale of certain oil and gas leases, wells and gathering equipment held by the Company in its Fayetteville Shale play for approximately $519.6 million in cash.  The sale included 55,631 net acres, or approximately 6% of the Company’s approximately 906,700 net acres in the play as of December 31, 2007, and approximately 10.5 MMcf per day of production from the Fayetteville Shale as of March 17, 2008.  The acreage is located in the southeast portion of the Company's focus area, and the transaction is scheduled to close in the second quarter of 2008.

(16)

NEW ACCOUNTING PRONOUNCEMENTS

In February 2008, the Financial Accounting Standards Board (FASB) issued FASB Staff Position FAS 157-2, Effective Date of FASB Statement No. 157 (“FSP FAS 157-2”). FSP FAS 157-2 delays the effective date of FAS 157 to fiscal years beginning after November 15, 2008 for all nonfinancial assets and nonfinancial liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually). FSP FAS 157-2 is effective for the Company’s fiscal year beginning January 1, 2009. The adoption of FSP FAS 157-2 is not expected to have a material impact on the Company’s consolidated financial statements.

In March, 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities – an amendment of FASB Statement No. 133” (FAS 161). FAS 161 requires enhanced disclosures for derivative instruments and hedging activities that include how and why an entity uses derivatives, how instruments and the related hedged items are accounted for under FAS 133 and related interpretations, and how derivative instruments and related hedged items affect the entity’s financial position, results of operations and cash flows. FAS 161 is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008. The Company is currently reviewing the standard to assess the impact of the adoption of FAS 161.

ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.

The following updates information as to Southwestern Energy Company's financial condition provided in our 2007 Annual Report on Form 10-K and analyzes the changes in the results of operations between the three-month periods ended March 31, 2008 and 2007. For definitions of commonly used gas and oil terms used in this Form 10-Q, please refer to the "Glossary of Certain Industry Terms" provided in our 2007 Annual Report on Form 10-K.

The following discussion contains forward-looking statements that involve risks and uncertainties. Our actual results could differ materially from those anticipated in our forward-looking statements for many reasons, including the risks described in the “Cautionary Statement About Forward-Looking Statements” in the forepart of this Form 10-Q, in Item 1A, "Risk Factors" in Part I and elsewhere in our 2007 Annual Report on Form 10-K, and Item 1A, “Risk Factors” in Part II in this Form 10-Q. You

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should read the following discussion with our consolidated financial statements and the related notes included in this Form 10-Q.

OVERVIEW

Southwestern Energy Company is an independent energy company primarily focused on the exploration and production of natural gas within the United States. Our operations primarily are located in Arkansas, Oklahoma and Texas. We are also focused on creating and capturing additional value at and beyond the wellhead through our established natural gas gathering and marketing businesses, which we refer to collectively as our Midstream Services.  We operate principally in three segments: Exploration and Production (E&P), Midstream Services and Natural Gas Distribution.  Following the consummation of the pending sale of our utility subsidiary, Arkansas Western Gas Company (“AWG”), which is subject to certain closing conditions and regulatory approvals and is expected to close approximately mid-year 2008, we will cease to have any natural gas distribution operations. The assets and liabilities of AWG have been reclassified as “held for sale” in our March 31, 2008 and December 31, 2007 balance sheets, however, the results of operations for AWG continue to be consolidated in the statements of operations and are not presented as “discontinued operations.” We refer you to Note 4 to the consolidated financial statements included in this Form 10-Q for additional information.

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 natural gas, our ability to control costs and our ability to market natural gas on economically attractive terms to our customers.

In the first quarter of 2008, our gas and oil production increased to 39.1 Bcfe, up 71% from the first quarter of 2007.  The increase in 2008 production primarily resulted from a significant increase in production from our Fayetteville Shale play as a result of our ongoing development program. The average price realized for our gas production, including the effects of hedges, increased approximately 15% to $7.70 per Mcf for the three months ended March 31, 2008, as compared to the same period last year.

We reported net income of $109.0 million in the first quarter of 2008, or $0.31 per share on a fully diluted basis, up 114% from the prior year, due to increased production volumes in our E&P segment and higher realized natural gas prices, which were only partially offset by increased operating costs and expenses. As a result, operating income for our E&P segment was $165.7 million for the first quarter of 2008, up 123% from the comparable period of 2007. Operating income for our Midstream Services segment was $10.2 million for the first quarter of 2008, up from approximately breakeven in the first quarter of 2007, due primarily to an increase in gathering revenues related to our Fayetteville Shale play. Operating income for our Natural Gas Distribution segment increased 24% to $11.6 million for the three months ended March 31, 2008, primarily due to colder weather and a rate increase implem ented in August 2007.

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Our capital investments increased approximately 25% to $409.9 million for the first quarter of 2008, of which $376.5 million was invested in our E&P segment.

RESULTS OF OPERATIONS

Exploration and Production

	For the three months
	ended March 31,
	2008	2007
Revenues (in thousands)	$312,017	$161,261
Operating income (in thousands)	$165,710	$74,310
Gas production (MMcf)	38,205	21,886
Oil production (MBbls)	142	167
Total production (MMcfe)	39,057	22,891
Average gas price per Mcf, including hedges	$7.70	$6.71
Average gas price per Mcf, excluding hedges	$7.46	$6.19
Average oil price per Bbl	$96.55	$55.17
Average unit costs per Mcfe:
Lease operating expenses	$0.77	$0.74
General & administrative expenses	$0.42	$0.47
Taxes, other than income taxes	$0.16	$0.27
Full cost pool amortization	$2.30	$2.24

Revenues, Operating Income and Production

Revenues. Revenues for our E&P segment were up 93% for the three months ended March 31, 2008, compared to the same period in 2007, primarily due to increased production volumes and higher gas and oil prices realized for our production.  We expect our production volumes to continue to increase due to the development of our Fayetteville Shale play in Arkansas. Gas and oil prices are difficult to predict and subject to wide price fluctuations. As of April 22, 2008, we have hedged 94.5 Bcf of our remaining 2008 gas production, 123.0 Bcf of 2009 gas production and 42.0 Bcf of 2010 gas production to limit our exposure to price fluctuations.  Revenues for the first three months of 2008 and 2007 also included pre-tax gains of $2.5 million and $5.1 million, respectively, related to the sale of gas in storage inventory.

Operating Income.Operating income from our E&P segment was up 123% to $165.7 million for the first quarter of 2008 from $74.3 million for the same period in 2007.  The increase in operating income was a result of the increase in revenues, partially offset by an increase in operating costs and expenses.

Production. Gas and oil production during the first quarter of 2008 was up 16.2 Bcfe, or approximately 71%, to 39.1 Bcfe, as compared to the prior year period, primarily due to an increase in production from our Fayetteville Shale play as a result of our ongoing development program. Our total gas production was up approximately 75% to 38.2 Bcf for the first quarter of 2008, as compared to the prior period, and represented approximately 98% of our total equivalent production. Net production

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from the Fayetteville Shale was 23.6 Bcf in the first quarter of 2008, up from 8.2 Bcf in the first quarter of 2007.  On April 3, 2008, we announced the sale of 55,631 net acres, or approximately 6% of our total net acres in the Fayetteville Shale play, for $519.6 million. Production from the acreage sold was 10.5 MMcf per day at March 17, 2008. This transaction is scheduled to close in the second quarter of 2008.

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 3 and Notes 6 and 7 to the consolidated financial statements included in this Form 10-Q for additional discussion). The average price realized for our gas production, including the effects of hedges, increased approximately 15% to $7.70 per Mcf for the three months ended March 31, 2008, as compared to the same period last year. The change in the average price realized primarily reflects changes in average spot market prices and the positive effects of our price hedging activities. Our hedging activities increased the average gas price $0.24 per Mcf during the first quarter of 2008, compa red to an increase of $0.52 per Mcf during the first quarter of 2007. We had protected approximately 60% of our production in the first quarter of 2008 from the impact of widening basis differentials and have also protected approximately 70% of our anticipated gas production for the remainder of the year through our hedging activities and sales arrangements.  Disregarding the impact of hedges, the average price received for our gas production during the first three months of 2008 was approximately $0.57 lower than average NYMEX spot prices, which represented the average locational basis differential.

As of April 22, 2008, we have NYMEX commodity price hedges in place for 94.5 Bcf of our remaining 2008 gas production. For our 2009 and 2010 future gas production, we have hedges in place on 123.0 Bcf and 42.0 Bcf, respectively. Additionally, we have basis swaps on 60.6 Bcf for the remainder of 2008, and on 6.3 Bcf for 2009, in order to reduce the effects of changes in market differentials on prices we receive.

Operating Costs and Expenses

Lease operating expenses per Mcfe for our E&P segment were $0.77 for the first quarter of 2008, as compared to $0.74 per Mcfe for the same period in 2007.  The increase was primarily due to increased production from our Fayetteville Shale operations which has higher per unit operating costs than our other focus areas. We continue to expect our per unit operating cost for this segment to range between $0.85 and $0.90 per Mcfe for 2008.

General and administrative expenses per Mcfe for the first quarter of 2008 decreased 11% to $0.42 per Mcfe compared to $0.47 per Mcfe for the same period in 2007 primarily due to the effects of our increased production volumes which more than offset increased compensation and related costs.  In total, general and administrative expenses for our E&P segment were $16.6 million in the first quarter of 2008, compared to $10.8 million in the first quarter of 2007. The increase in total general and administrative costs was due primarily to increased payroll and related costs associated with the expansion of our E&P operations due to the Fayetteville Shale play since the first quarter of 2007.  We expect our cost per unit for general and administrative expenses in 2008 to range between $0.42 and $0.47 per Mcfe.

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Our full cost pool amortization rate averaged $2.30 per Mcfe for the first quarter of 2008, up 3%, compared to the same period in 2007. Our full cost pool amortization rate increased due to increased capital investments and future development costs relative to reserve additions, including revisions, partially offset by an increase in reserve volumes. The amortization rate is impacted by timing and amount of 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, proceeds from the sale of properties that reduce the full cost pool and the levels of costs subject to 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 other factors, including but not limited to the uncertaint y of the amount of future reserves attributed to our Fayetteville Shale play. Unevaluated costs excluded from amortization were $455.7 million at March 31, 2008, compared to $178.3 million at March 31, 2007, and $372.4 million at December 31, 2007. The increase in unevaluated costs since March 31, 2007, resulted primarily from an increase in our undeveloped leasehold acreage and seismic costs related to our Fayetteville Shale play and our increased drilling activity.

Taxes other than income taxes per Mcfe decreased to $0.16 for the first quarter of 2008, compared to $0.27 for the same period in 2007, and vary from period to period due to changes in severance and ad valorem taxes that primarily result from the mix of our production volumes and fluctuations in commodity prices. Additionally, we accrued $1.8 million in the first quarter of 2008 for severance tax refunds related to our East Texas production, compared to $0.1 million in the first quarter of 2007. In April 2008, the Arkansas Legislature passed an initiative to increase the severance tax on natural gas produced within the state to a base rate of 5%, subject to certain periods of reduced rates for high-cost gas wells, new discovery gas wells and gas wells that produce below a specified level. The new tax rates will become effective January 1, 2009, and will negatively impact our results of operations.

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.

We utilize the full cost method of accounting for costs related to the exploration, development, and acquisition of natural gas and oil reserves. Under this method, all such costs (productive and nonproductive) including salaries, benefits and other internal costs directly attributable to these activities are capitalized and amortized on an aggregate basis over the estimated lives of the properties using the units-of-production method. 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 natural 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 subseq uently 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 March 31, 2008, our unamortized costs of natural gas and oil properties did not exceed this ceiling amount.  At March 31, 2008, the ceiling value of our reserves was calculated based upon quoted market prices of $9.37 per Mcf for Henry Hub gas and $98.00 per barrel for West Texas Intermediate oil, adjusted for market differentials. Cash flow hedges of gas production in place at March 31, 2008 decreased the calculated ceiling value by approximately $99.7 million (net of tax). We had approximately 259.5 Bcf of future gas production hedged at March 31, 2008. Decreases in market

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prices from March 31, 2008 levels, as well as changes in production rates, levels of reserves, the evaluation of costs excluded from amortization, future development costs, and service costs could result in future ceiling test impairments.

Midstream Services

	For the three months ended
	March 31,
	2008	2007
	($ in thousands, except volumes)
Revenues - marketing	$385,721	$173,651
Revenues - gathering	$19,604	$4,938
Gas purchases - marketing	$383,060	$171,679
Operating costs and expenses	$12,104	$6,899
Operating income	$10,161	$11
Gas volumes marketed (Bcf)	50.1	27.1
Gas volumes gathered (Bcf)	38.5	10.7

Revenues and Operating Income

Revenues. Revenues from our Midstream Services segment were up 127% in the first quarter of 2008, as compared to the prior year period. The increases in first quarter revenues resulted from increases in volumes marketed and increased gathering revenues, primarily relating to the Fayetteville Shale play. Increases and decreases in marketing revenues due to changes in commodity prices are largely offset by corresponding changes in gas purchase expenses. Midstream Services had gathering revenues of $19.6 million in the first quarter of 2008, compared to $4.9 million for the comparable period of 2007. Gathering volumes, revenues and expenses for this segment are expected to continue to grow as reserves related to our Fayetteville Shale play are developed and production increases.

Operating Income. Operating income from our Midstream Services segment increased significantly in the first quarter of 2008, as compared to the same period of 2007, primarily as a result of the increases in gathering revenues from the Fayetteville Shale play, partially offset by increased operating costs and expenses. The margin generated from natural gas marketing activities was $2.7 million for the first quarter of 2008, up from $2.0 million for the same period of 2007.  Margins may fluctuate depending on the prices paid for commodities and the ultimate disposition of those commodities. The increase in volumes marketed in the first quarter of 2008, as compared to the same period in 2007, resulted from marketing our increased production volumes, primarily related to our Fayetteville Shale play, and volumes for third parties in areas where we have production.  Of the total volumes marketed, production from our E&P subsidiaries accounted for 98% in the first quarter of 2008 and 85% in the first quarter of 2007. We enter into hedging activities from time to time with respect to our gas marketing activities to provide margin protection. We refer you to Item 3, "Quantitative and Qualitative Disclosures about Market Risks" in this Form 10-Q for additional information.

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Natural Gas Distribution

	For the three months
	ended March 31,
	2008	2007
Revenues (in thousands>	$84,191	$76,994
Gas purchases (in thousands)	$58,657	$54,217
Operating costs and expenses (in thousands)	$13,944	$13,396
Operating income (in thousands)	$11,590	$9,381
Sales and end-use transportation deliveries (Bcf)	10.2	9.5
Sales customers at period-end	153,875	152,751
Average sales rate per Mcf	$10.97	$10.68
Heating weather - degree days	2,197	1,941
Percent of normal	100%	89%

In November 2007, we entered a definitive agreement for the sale of all capital stock of our utility subsidiary, AWG, to SourceGas LLC for $224 million plus working capital. The transaction is subject to certain closing conditions and regulatory approvals and is expected to close by mid-year 2008. The assets and liabilities associated with AWG have been reclassified as “held for sale” as of March 31, 2008 and December 31, 2007. Upon the consummation of the sale, we will cease to have any natural gas distribution operations.

Revenues and Operating Income

Revenues increased 9% for the first quarter of 2008, compared to the prior year period. The increase in first quarter revenues resulted primarily from an increase volumes delivered and the rate increase implemented in August 2007.  Weather was normal during the first three months of 2008 and was 11% colder than the same period in 2007.

Operating income for our Natural Gas Distribution segment increased 24% in the first quarter of 2008, compared to the prior year period. The increase in first quarter of 2008 operating income resulted primarily from the increase in revenues.

Deliveries and Rates

Deliveries were up 7% in the first quarter of 2008, as compared to the same period in 2007, due to the colder weather. The average sales rate per Mcf increased slightly during the first quarter of 2008 reflecting the change in natural gas prices and the impact of incremental volumes delivered.

Our utility segment hedged 2.0 Bcf of derivative gas purchases during the first three months of 2008 which had the effect of increasing its total gas supply cost by $1.2 million.  In the first three months of 2007, our utility hedged 3.1 Bcf of its gas supply, which increased its total gas supply cost by $6.6 million. See Notes 6 and 7 to the consolidated financial statements included in, and Item 3 of, this Form 10-Q for additional information regarding our commodity price risk hedging activities.

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Operating Costs and Expenses

For the first three months of 2008, operating costs and expenses (exclusive of purchased gas costs) for this segment were slightly higher than the comparable period of the prior year due primarily to increased payroll and other operating costs.

Other Revenues

Other revenues for the first three months of 2008 and 2007 included pre-tax gains of $2.5 million and $5.1 million, respectively, related to the sale of gas-in-storage inventory.

Interest Expense and Interest Income

Interest costs, net of capitalization, increased to $11.5 million for the first quarter of 2008, compared to $1.5 million for the same period in 2007, due to increased debt levels resulting from our increased level of capital investments. We capitalized $6.2 million of interest in the first three months of 2008, compared to $3.0 million for the same period in 2007, as our costs excluded from amortization in the E&P segment increased to $455.7 million at March 31, 2008, up from $178.3 million at March 31, 2007.

Income Taxes

Our provision for deferred income taxes was an effective rate of 38.0% for both the first three months of 2008 and 2007. Any changes in the provision for deferred income taxes recorded each period result primarily from the level of income before income taxes, adjusted for permanent differences.

Pension Expense

We incurred pension costs of $1.9 million in the first quarter of 2008 for our pension and other postretirement benefit plans, compared to $1.3 million for the same period of 2007. The increase was primarily the result of an increase in our number of employees. The amount of pension expense recorded is determined by actuarial calculations and is also impacted by the funded status of our plans.  We currently expect to contribute $8.5 million to our pension and other postretirement plans in 2008. As of March 31, 2008, no contributions have been made to the pension plans, and $0.1 million has been contributed to the postretirement benefit plans.  For further information regarding our pension plans, we refer you to Note 12 to the consolidated financial statements included in this Form 10-Q.

Stock-Based Compensation

     We recognized expense of $1.7 million and capitalized $0.9 million to the full cost pool for stock-based compensation in the first quarter of 2008, compared to $1.5 million expensed and $0.6 million capitalized to the full cost pool for the first quarter of 2007. We refer you to Note 11 to the consolidated financial statements included in this Form 10-Q for additional discussion of our equity based compensation plans.

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Adoption of Accounting Principles

During the first quarter of 2008, we adopted Statement of Financial Accounting Standards No. 157, “Fair Value Measurements” (FAS 157).  FAS 157 defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. This statement applies to other accounting pronouncements that require or permit fair value measurements, and is effective for financial statements issued for fiscal years beginning after November 15, 2007.  In addition to required disclosures, FAS 157 also requires companies to evaluate current measurement techniques. The adoption of FAS 157 had no material impact on our results of operations and financial condition.  See Note 7 to the consolidated financial statements included in this Form 10-Q for further information.

During the first quarter of 2008, we adopted Statement of Financial Accounting Standards No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities” (FAS 159). FAS 159 permits entities to choose to measure many financial instruments and certain other items at fair value and applies to other accounting pronouncements that require or permit fair value measurements. FAS 159 is effective for financial statements issued for fiscal years beginning after November 15, 2007. The adoption of FAS 159 had no impact on our results of operations and financial condition.

In February 2008, the Financial Accounting Standards Board (FASB) issued FASB Staff Position FAS 157-2, Effective Date of FASB Statement No. 157 (“FSP FAS 157-2”). FSP FAS 157-2 delays the effective date of FAS 157 to fiscal years beginning after November 15, 2008 for all nonfinancial assets and nonfinancial liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually). FSP FAS 157-2 is effective for our fiscal year beginning January 1, 2009. The adoption of FSP FAS 157-2 is not expected to have a material impact on our results of operations and financial condition.

In March 2008, the Financial Accounting Standards Board issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities – an amendment of FASB Statement No. 133” (FAS 161). FAS 161 requires enhanced disclosures for derivative instruments and hedging activities that include how and why an entity uses derivatives, how these instruments and the related hedged items are accounted for under FAS 133 and related interpretations, and how derivative instruments and related hedged items affect the entity’s financial position, results of operations and cash flows. FAS 161 is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008. We are currently reviewing the standard to assess the impact of the adoption of FAS 161.

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 debt and equity markets as our primary sources of liquidity. We may borrow up to $1.0 billion under our revolving credit facility from time to time. The amount available under our revolving credit facility may be increased up to $1.25 billion at any time upon our agreement with our existing or additional lenders. As of March 31, 2008, we had $341.2 million outstanding under our revolving credit facility. At December 31, 2007, we had $842.2 million outstanding under our revolving credit facility.

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On January 16, 2008, we completed a private placement of $600 million of 7.5% Senior Notes due 2018 (discussed below under “Financing Requirements”). Net proceeds of approximately $591 million from the offering were used to pay outstanding indebtedness under our revolving credit facility.

Net cash provided by operating activities increased 131% to $297.1 million in the first three months of 2008, compared to the same period in 2007, due primarily to an increase in net income and adjustments for non-cash expenses. During the first three months of 2008, requirements for our capital investments were funded from cash provided by operating activities and our revolving credit facility, which was partially repaid using the net proceeds from the 7.5% Senior Notes.  

On April 3, 2008, we announced the sale of 55,631 net acres in the Fayetteville Shale play for $519.6 million. This transaction is scheduled to close in the second quarter of 2008. After-tax proceeds from the sale will be used to pay down our revolving credit facility.

At March 31, 2008, our capital structure consisted of 41% debt and 59% equity. We believe that our operating cash flow, borrowings under our revolving credit facility and the expected proceeds from the pending sales of the Fayetteville Shale acreage and our utility, AWG, and any other E&P asset divestitures we might make will be adequate to meet our capital and operating requirements for 2008.

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 Item 3, "Quantitative and Qualitative Disclosures about Market Risks" and Notes 6 and 7 to the consolidated financial statements in this Form 10-Q. 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 available cash flow.

Capital Investments

Our capital investments increased to $409.9 million for the first three months of 2008, compared to $327.3 million for the same period last year. Our E&P segment investments were $376.5 million during the first three months of 2008 and were $301.2 million for the comparable period in 2007.  Our capital investments for 2008 are currently expected to be approximately $1.46 billion, consisting of $1.33 billion for E&P, $101 million for Midstream Services and $25 million for Natural Gas Distribution improvements and general purposes. We expect to allocate approximately $1.0 billion of our 2008 E&P capital to our Fayetteville Shale play. Our 2008 capital investment program is expected to be funded through cash flow from operations, borrowings under our credit facility and the expected after-tax proceeds from the sale of AWG, the sale of the Fayetteville Shale acreage discusse d above and potential sales of certain other E&P assets. We may adjust the level of 2008 capital investments dependent upon our level of cash flow generated from operations and asset sales and our ability to borrow under our credit facility.

Financing Requirements

Our total debt outstanding was $1,077.8 million at March 31, 2008, compared to $978.8 million at December 31, 2007. On October 12, 2007, we amended our unsecured revolving credit facility to, among other things, increase the current borrowing capacity to $1.0 billion. Pursuant to the amendment, the amount available under the revolving credit facility may be increased to $1.25 billion at any time

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upon our agreement with our existing or additional lenders. As of March 31, 2008, we had $341.2 million outstanding under our revolving credit facility compared to $842.2 million outstanding as of December 31, 2007.  As discussed more fully below, in January 2008, we issued $600 million of 7.5% Senior Notes due 2018, the net proceeds of which were used to repay amounts outstanding under our revolving credit facility. The interest rate on the credit facility is calculated based upon our public debt rating and is currently 87.5 basis points over LIBOR. The revolving credit facility is currently guaranteed by our subsidiaries, SEECO, Inc. (SEECO), Southwestern Energy Production Company (SEPCO) and Southwestern Energy Services Company (SES) and 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 outlook from BBB- with a negative outlook. We have a Corporate Family Rating of Ba2 by Moody’s. Any future downgrades in our public debt ratings could increase our cost of funds under the credit facility.

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 March 31, 2008. 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 may have to decrease our capital investment plans.

On January 16, 2008, we issued $600 million of 7.5% Senior Notes due 2018 in a private placement, which are rated BB+ by Standard and Poor’s and Ba2 by Moody’s. The 7.5% Senior Notes are redeemable at our election, in whole or in part, at any time at a redemption price equal to the greater of: (i) 100% of the principal amount of the notes to be redeemed then outstanding; and (ii) the sum of the present values of the remaining scheduled payments of principal and interest on the notes to be redeemed as determined in accordance with the indenture, plus 50 basis points. Any redemption is also subject to payment of accrued and unpaid interest to the date of redemption. In addition, if we undergo a “change of control” as defined in the indenture, holders of the 7.5% Senior Notes will have the option to require us to purchase all or any portion of the notes at a purchase price equal to 101% of the principal amount of the notes to be purchased plus any accrued and unpaid interest to, but excludin g, the change of control date. The 7.5% Senior Notes are currently guaranteed by our subsidiaries SEECO, SEPCO and SES, which guarantees may be unconditionally released in certain circumstances. The indentures governing the 7.5% Senior Notes and our other senior notes contain covenants that, among other things, restrict the ability of us and/or our subsidiaries to incur liens, to engage in sale and leaseback transactions and to merge, consolidate or sell assets.

At March 31, 2008, our capital structure consisted of 41% debt and 59% equity. Our capital structure at March 31, 2008 would have been 38% debt and 62% equity without consideration of accumulated other comprehensive losses in shareholders’ equity related to our commodity hedge position and our pension liability. Depending upon the level of cash proceeds received from our planned asset sales and our operating results, our total debt could decline to 25% to 30% of our capital structure by year end. Stockholders’ equity at March 31, 2008, includes an accumulated other comprehensive loss of $167.5 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 $11.1 million related to

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changes in our pension liability. The amount recorded for FAS 133 is based on current market values of our hedges at March 31, 2008, 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 with 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.

As part of our strategy to ensure a certain level of cash flow to fund our operations, we have hedged approximately 80% of our expected 2008 gas production. The amount of long-term debt we incur will be dependent upon commodity prices, our capital investment plans and the actual proceeds from the pending sales of our utility and the Fayetteville Shale acreage as well as any other E&P asset divestitures. If commodity prices remain at or near their current levels throughout 2008, assuming that we do not complete the pending sales or the divestitures of any other E&P assets, our long-term debt would significantly increase in 2008. If commodity prices significantly decrease, we may decrease and/or reallocate our planned capital investments.

Contractual Obligations and Contingent Liabilities and Commitments

We have various contractual obligations in the normal course of our operations and financing activities.  On January 16, 2008, the Company issued $600 million of 7.5% Senior Notes due 2018 in a private placement. In the first quarter of 2008, we exercised the first of our three options to increase the volumes to be transported on each of the two pipeline laterals and related facilities being constructed by Texas Gas Transmission, LLC for which we are the anchor shipper. The options exercised will allow us to transport up to 600,000 MMBtu per day on the Fayetteville Lateral and up to 480,000 MMBtu per day on the Greenville Lateral. Other than the Senior Note issuance and the increase in pipeline volume commitments, there have been no material changes to our contractual obligations from those disclosed in our 2007 Annual Report on Form 10-K.

Contingent Liabilities and Commitments

Substantially all of our employees are covered by defined benefit and postretirement benefit plans. As a result of actuarial data, and assuming the closing of the sale of AWG by mid-year, we expect to record expenses of $7.7 million in 2008 for these plans, of which $1.9 million has been recorded in the first three months of 2008. At March 31, 2008, we recognized a liability of $16.0 million as a result of the underfunded status of our pension and other postretirement benefit plans, compared to a liability of $14.6 million at December 31, 2007. For further information regarding our pension and other postretirement benefit plans, we refer you to Note 12 to the consolidated financial statements in this Form 10-Q.

We are subject to litigation and claims (including with respect to environmental matters) 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.

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Working Capital

We maintain access to funds that may be needed to meet capital requirements through our revolving credit facility described above. We had negative working capital of $254.9 million at March 31, 2008, and $67.6 million at December 31, 2007. Current assets increased at March 31, 2008, compared to current assets at December 31, 2007, primarily due to an increase in our current deferred income tax benefit related to our hedging activities.Current liabilities increased $221.3 million primarily due to an increase in our current hedging liability. Both changes reflect a significant increase in commodity prices for natural gas at March 31, 2008.

Gas in Underground Storage

We record our gas stored in inventory that is owned by the E&P segment at the lower of weighted average cost or market. Gas expected to be cycled within the next 12 months is recorded in current assets with the remaining stored gas reflected as a long-term asset. The quantity and average cost of gas in storage was 7.9 Bcf at $3.48 per Mcf at March 31, 2008, compared to 10.1 Bcf at $4.05 per Mcf at December 31, 2007.

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 AWG, especially during periods of colder weather. As a result, demand fees paid by AWG to our E&P subsidiaries, 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.

ITEM 3. 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 trading. 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 8% of accounts receivable at March 31, 2008. In addition, see the discussion of credit risk associated with commodities trading below.

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Interest Rate Risk

At March 31, 2008, we had $1,077.8 million of total debt with an average interest rate of 6.35%.  Our revolving credit facility has a floating interest rate (3.91% at March 31, 2008). At March 31, 2008, we had $341.2 million of borrowings outstanding under the 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.  We do not have any interest rate swaps in effect currently.

Commodities Risk

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

Exploration and Production

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 production. The table presents the notional amount in Bcf, the weighted average contract prices and the fair value by expected maturity dates. At March 31, 2008, the fair value of our financial instruments related to natural gas production was a $270.6 million liability.

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	Volume	Weighted Average Price to be Swapped ($)	Weighted Average Floor Price ($)	Weighted Average Ceiling Price ($)	Weighted Average Basis Differential ($)	Fair Value at March 31, 2008 ($ in millions)
Natural Gas (Bcf):
Fixed Price Swaps:
2008	64.5	8.37	-	-	-	(117.4)
2009	76.0	8.30	-	-	-	(91.7)
2010	28.0	8.76	-	-	-	(7.2)
Costless Collars:
2008	30.0	-	7.50	10.60	-	(31.0)
2009	47.0	-	8.38	10.85	-	(28.4)
2010	14.0	-	8.29	10.57	-	(1.1)
Basis Swaps:
2008	54.3	-	-	-	(0.42)	4.3
2009	3.6	-	-	-	(0.44)	0.3
Matched-Basis Swaps:
2008	4.5	-	-	-	(0.71)	1.6

At March 31, 2008, we had outstanding fixed-price basis differential swaps on 4.5 Bcf of 2008 gas production that qualified for hedge treatment.  At March 31, 2008, we also had outstanding fixed-price basis differential swaps on 54.3 Bcf of 2008 and 3.6 Bcf of 2009 gas production that did not qualify for hedge accounting treatment.  Changes in the fair value of derivatives that do not qualify as cash flow hedges are recorded in gas and oil sales. For the three months ended March 31, 2008, we recorded an unrealized gain of $5.4 million related to the differential swaps that did not qualify for hedge accounting treatment and a $13.6 million loss related to the change in estimated ineffectiveness of our cash flow hedges. Typically, our hedge ineffectiveness results from changes at the end of a reporting period in the price differentials between the index price of the derivative contract, which is primarily a NYMEX price, and the index price for the point of sale for the cash flow that is being hedged. As of April 22, 2008, we have basis-protected an additional 4.5 Bcf of future gas production subsequent to the end of the quarter.

At December 31, 2007, we had outstanding natural gas price swaps on total notional volumes of 55.7 Bcf in 2008 and 56.0 Bcf in 2009 for which we will receive fixed prices ranging from $7.29 to $9.98 per MMBtu. At December 31, 2007, we had outstanding fixed price basis differential swaps on 8.0 Bcf of 2008 gas production that qualified for hedge treatment and outstanding fixed price basis differential swaps on 66.8 Bcf of 2008 and 2009 gas production that did not qualify for hedge treatment.

At December 31, 2007, we had collars in place on notional volumes of 48.0 Bcf in 2008 and 23.0 Bcf in 2009.  The 48.0 Bcf in 2008 had an average floor and ceiling price of $7.92 and $11.60 per MMBtu, respectively. The 23.0 Bcf in 2009 had an average floor and ceiling price of $8.09 and $10.91 per MMBtu, respectively.

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Midstream Services

At March 31, 2008, our Midstream Services segment had outstanding fair value hedges in place on 2.3 Bcf and 0.5 Bcf of gas for 2008 and 2009, respectively.  These hedges are a mixture of fixed-price swap purchases and sales relating to our gas marketing activities. These hedges have contract months from April 2008 through March 2009 and have a net fair value liability of $2.6 million as of March 31, 2008.

ITEM 4. 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 level of reasonable assurance with respect to financi al 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 March 31, 2008, and provided a level of reasonable assurance with respect to financial statement preparation and presentation. There were no changes in our internal control over financial reporting during the three months ended March 31, 2008 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

35

PART II

OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS.

The Company is subject to litigation and claims that arise 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.

ITEM 1A. RISK FACTORS.

There were no additions or material changes to the Company’s risk factors as disclosed in Item 1A of Part I in the Company’s 2007 Annual Report on Form 10-K.

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS.

Not applicable.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES.

Not applicable.

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

Not applicable.

ITEM 5. OTHER INFORMATION.

Not applicable.

ITEM 6. EXHIBITS.

 (4.1)

Indenture by and among Southwestern Energy Company, SEECO, Inc., Southwestern Energy Production Company, Southwestern Energy Services Company and The Bank of New York Trust Company, N.A., as trustee, dated as of January 16, 2008 (Incorporated by reference to Exhibit 4.1 to the Registrant’s Current Report on Form 8-K filed on January 17, 2008).

(4.2)

Form of the Notes (included as an exhibit to the Indenture incorporated by reference as Exhibit 4.1 to this Form 10-Q).

(4.3)

Registration Rights Agreement between Southwestern Energy Company and the Initial Purchasers thereunder, dated as of January 16, 2008 (Incorporated by reference to Exhibit 4.3 to the Registrant’s Current Report on Form 8-K filed on January 17, 2008).                       

(10.1)

Sales Agreement between SEECO, Inc. and XTO Energy Inc., dated April 3, 2008.

36

(31.1)

Certification of CEO filed pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

(31.2)

Certification of CFO filed pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

(32.1)

Certification of CEO and CFO furnished pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

37

Signatures

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

		SOUTHWESTERN ENERGY COMPANY
		Registrant
Dated:	April 28, 2008	/s/ GREG D. KERLEY
		Greg D. Kerley
		Executive Vice President
		and Chief Financial Officer

38

EX-10

ASSET PURCHASE AGREEMENT

BY AND BETWEEN

SEECO, INC.

AND

XTO ENERGY INC.

As of April 1, 2008

TABLE OF CONTENTS

			Page
ARTICLE I   PURCHASE AND SALE OF ASSETS			1
	1.1	Purchased Assets	1
	1.2	Excluded Assets	3
	1.3	Assumed Liabilities	4
	1.4	Excluded Liabilities	4
	1.5	Purchase Price	4
	1.6	Allocated Values	4
	1.7	Adjustments to Purchase Price	4
	1.8	Termination for Reduction	6
	1.9	Closing Date Adjustment to Purchase Price	6
	1.10	Post-Closing Adjustments to Purchase Price	6
	1.11	Additional Proceeds	8
ARTICLE II   CLOSING			9
	2.1	The Closing	9
	2.2	Deliveries by Seller at the Closing	9
	2.3	Deliveries by Buyer at the Closing	9
	2.4	Proceedings at Closing	10
ARTICLE III   REPRESENTATIONS AND WARRANTIES OF SELLER			10
	3.1	Organization and Qualification	10
	3.2	Authority; Binding Effect	10
	3.3	Governmental Entities	11
	3.4	No Conflicts	11
	3.5	Contracts; Leases	11
	3.6	Title to Equipment	12
	3.7	Oil and Gas Interests	12
	3.8	No Litigation	12
	3.9	Brokers' Fees	12
	3.10	Books and Records	13
	3.11	Disclaimer	13
	3.12	Bankruptcy	13
ARTICLE IV   REPRESENTATIONS AND WARRANTIES OF BUYER			13
	4.1	Organization and Qualification	13
	4.2	Authority; Binding Effect	13
	4.3	Governmental Entities	14
	4.4	No Conflicts	14

i

			Page
	4.5	No Litigation	14
	4.6	Brokers' Fees	15
	4.7	SEC Disclosure	15
	4.8	Independent Evaluation	15
	4.9	Qualified Buyer	15
	4.10	Disclaimer	15
ARTICLE V   COVENANTS			15
	5.1	Closing Efforts	15
	5.2	Governmental and Third-Party Notices and Consents	16
	5.3	Operation of Business of Seller	16
	5.4	Expenses	17
	5.5	Notification	17
	5.6	Bulk Sales Laws	17
	5.7	Access to Purchased Assets and Records	18
	5.8	Further Assurances	20
	5.9	Delivery of Books and Records to Buyer	20
	5.10	Letters in Lieu; Assignments; Operatorship	20
ARTICLE VI   TITLE MATTERS			21
	6.1	Title Information	21
	6.2	Defensible Title	21
	6.3	Defensible Title; Development Acreage	21
	6.4	Allocated Value	21
	6.5	Permitted Encumbrances	21
	6.6	Title Defect	23
	6.7	Title Defect Value	23
	6.8	Title Defect Notice	24
	6.9	Assumed Title Liabilities	24
	6.10	Reasonable Documentation	24
	6.11	Seller's Options	25
	6.12	Adjustment to Purchase Price; Threshold and Deductible	25
	6.13	Exclusions of Wells	25
	6.14	Preference Rights and Transfer Requirements	26
ARTICLE VII   CONDITIONS TO CLOSING			27
	7.1	Conditions to Each Party's Obligations	27
	7.2	Conditions to Obligations of Buyer	27
	7.3	Conditions to Obligations of Seller	28
ARTICLE VIII   INDEMNIFICATION			29
	8.1	Indemnification by Seller	29

ii

			Page
	8.2	Indemnification by Buyer	30
	8.3	Indemnification Claims	30
	8.4	Survival of Representations, Warranties and Covenants	33
	8.5	Limitations	34
	8.6	Treatment of Indemnification Payments	35
ARTICLE IX   TERMINATION			35
	9.1	Termination	35
	9.2	Effect of Termination	36
	9.3	Remedies	36
ARTICLE X   DEFINITIONS			36
ARTICLE XI MISCELLANEOUS			45
	11.1	Press Releases and Announcements	45
	11.2	No Third Party Beneficiaries	46
	11.3	Entire Agreement	46
	11.4	Succession and Assignment	46
	11.5	Counterparts and Facsimile Signature	46
	11.6	Headings	46
	11.7	Notices	46
	11.8	Governing Law	47
	11.9	Amendments and Waivers	47
	11.10	Severability	47
	11.11	Submission to Jurisdiction	47
	11.12	Construction	48

iii

Schedules and Exhibits

Schedule 3.3 -

Governmental Approvals

Schedule 3.4 -

No Conflicts; Exceptions

Schedule 3.5 -

Material Contracts

Schedule 3.8 -

No Litigation; Exceptions

Schedule 3.9 -

Brokers’ Fees; Exceptions

Schedule 4.3 -

Governmental Approvals

Schedule 4.4 -

No Conflicts; Exceptions

Schedule 4.6 -

Brokers’ Fees; Exceptions

Schedule 5.3 -

Pre-Closing Operation of Business

Schedule 6.6 -

Title Defects

Exhibit A -

Leases

Exhibit B -

Subject Lands

Exhibit C -

Wells

Exhibit D -

Allocated Values

Exhibit E -

Imbalances

Exhibit F -

Form of Assignment and Bill of Sale

iv

ASSET PURCHASE AGREEMENT

ASSET PURCHASE AGREEMENT (this “Agreement”) entered into as of April 1, 2008, by and between SEECO, INC., an Arkansas corporation (“Seller”), and XTO ENERGY INC., a Delaware corporation (“Buyer”).

W I T N E S S E T H:

WHEREAS, Seller owns interests in certain oil and gas leases and related assets in the State of Arkansas; and

WHEREAS, the parties hereto desire that Seller sell, assign, transfer, convey and deliver to Buyer, and that Buyer purchase, acquire and receive from Seller, all of Seller’s right, title and interest in and to the oil and gas leases and related assets as set forth herein, and that Buyer assume certain of the liabilities associated therewith, all on the terms and subject to the conditions set forth in this Agreement.

NOW THEREFORE, in consideration of the representations, warranties, covenants, promises and the mutual agreements contained herein and other good and valuable consideration the receipt and sufficiency of which are hereby acknowledged, the Parties, intending to be bound, do hereby agree as follows:

ARTICLE I

PURCHASE AND SALE OF ASSETS

1.1 Purchased Assets.  On the terms and subject to the conditions set forth in this Agreement, at the Closing Seller agrees to sell, transfer, convey, assign and deliver to Buyer, and Buyer shall purchase and receive from Seller, the following (the “Purchased Assets”):

(a)

All of Seller’s right, title and interest in and to:

(i)

Leases.  Those oil and gas leases described in Exhibit A, (each, a “Lease” and sometimes, collectively, the “Leases”);  INSOFAR AND ONLY INSOFAR as the Leases cover both the Subject Interval (as defined herein below) and the Subject Lands (as defined herein below)(collectively, the “Subject Interests”).  For purposes of this Agreement, (i) the term “Subject Interval” means that interval extending from the surface of the earth down to the Base of the Moorefield Shale Formation (as defined herein below); (ii) the term the “Base of the Moorefield Shale Formation” means the correlative stratigraphic equivalent to that point found at 5,778 feet measured depth on the PEX log (Array-Induction/Gamma Ray, Litho-Density, Compensated Neutron) (the “Log”) for the Green Bay Packaging 8-10 #1-4 well (API No. 03-145-100350000) loc ated in Section 4 Township 8-North, Range 10-West, Cleburne County, Arkansas, and (iii) the term “Subject Lands” means that portion of the lands covered by the Leases that is more particularly described in Exhibit B;

1

(ii)

Surface Rights.  All rights and privileges conferred upon the owner of the surface of the Subject Interests with respect to the use and occupancy of the surface and subsurface depths under the Subject Lands which may be necessary or convenient to the possession and enjoyment of the Subject Interests;

(iii)

Integrated Units.  Any pooled, unitized, communitized, consolidated or integrated acreage by virtue of the Subject Interests being included therein;

(iv)

Wells.  All wells situated on the Subject Lands and completed in the Subject Interval, whether producing, operating, shut-in or temporarily abandoned, including, without limitation, those described in Exhibit C (each, a “Well” and sometimes, collectively, the “Wells”) INSOFAR AND ONLY INSOFAR as Seller’s right, title and interest in and to the Wells is attributable to the Subject Interests;

(v)

Equipment.  All equipment, fixtures, machinery, tanks, flow lines, saltwater and other disposal wells, and other appurtenances and all other personal property or fixtures that are located on the Subject Lands and are used in connection with the ownership or operation of the Subject Interests and the production of oil and/or gas therefrom, (collectively, the “Equipment”);

(iv)

Contracts.  All contracts, agreements, leases (other than the Leases), rights-of-way, easements, servitudes, surface leases, permits, licenses and other similar rights, relating to the Subject Interests that are either of record, or are referenced in a document or instrument of record, in the counties where the Leases are located, or are reflected or referenced in the Records (as defined herein below) SAVE AND EXCEPT the Field Services Agreement (as defined herein below), INSOFAR AND ONLY INSOFAR as the same are assignable and are attributable to and affect the Subject Interests including, without limitation, (i) all hydrocarbon sales, purchase,  marketing and processing contracts or agreements, division orders and joint operating agreements and (ii) all surface leases for the construction and operation of water impoundments and water use agreements covering lands in the Subject Lands ( each an “Assigned Contract” and, collectively, the “Assigned Contracts”);

(b)

Seismic and Other Data.  To the extent owned or licensed by Seller and to the extent it can be licensed, sublicensed or transferred without payment of license or transfer fees, or to the extent Buyer agrees to pay a third party for applicable license or transfer fees, a non-exclusive license (in form and substance reasonably acceptable to Seller and Buyer) or sublicense (reasonably acceptable to the owner of the information, Seller and Buyer), as applicable, to use any seismic data, relating to the lands covered by the Leases or pooled therewith, together with any data (other than seismic data) relating to reserves or otherwise pertaining or relating to the Wells and the Subject Interests, to the extent assignable; and

2

(c)

Books and Records.  All books, files, abstracts, title opinions, maps and records of Seller related to the operation or ownership of the Purchased Assets (collectively, the “Records”), but, specifically excluding (i) previous offers and economic analyses associated with the acquisition, sale or exchange of the Purchased Assets, (ii) interpretive information, (iii) personnel information, (iv) corporate, legal, financial and tax information, (v) information covered by a non-disclosure obligation, (vi) information covered by a legal privilege and (vii) any other data or information that Seller does not have the right to assign to Buyer.

1.2

Excluded Assets.  The Purchased Assets do not include, and Seller shall not sell, transfer or assign to Buyer, and Buyer shall not purchase, acquire or accept any assets of Seller other than the Purchased Assets (the “Excluded Assets”), including, without limitation,

(a)

the corporate seals, minute books, stock books, Tax Returns, books of account or other records having to do with the corporate, limited liability company or partnership organization of Seller;

(b)

accounts receivable relating to any operation or ownership of the Purchased Assets for periods prior to the Effective Time;

(c)

oil and liquid hydrocarbon inventories in tanks above the pipeline connections as of the Effective Time and any and all revenues attributable thereto;

(d)

gas produced prior to the Effective Time and any and all revenues attributable thereto;

(e)

the shares of capital stock, limited liability company membership interests or partnership interests of Seller, as applicable;

(f)

the rights which accrue or will accrue to Seller under this Agreement, the Seller Related Documents and the Buyer Related Documents;

(g)

all right, title and interest of Seller in and to the Leases insofar as the Leases cover those formations situated below the Base of the Moorefield Shale Formation;

(h)

the right and subsurface easement to drill through and produce through the Subject Interval in order to explore, test, evaluate, complete and produce from horizons and formations below the Base of the Moorefield Shale Formation ;

(i)

all of Seller’s right, title and interest in and to the Leases, insofar and only insofar as the Leases cover lands other than the Subject Lands;

(j)

the right and subsurface easement to shoot seismic, to send seismic, sonic or other energy or waves through the Subject Interval and to receive, record and evaluate such energy or waves, including those reflected from or in any way pertaining to the Subject Interval, and to utilize any and all other exploration technologies that image the subsurface

3

of the Subject Lands including the Subject Interval and to receive, record and evaluate all images resulting therefrom; and

(k)

an overriding royalty interest equal to the positive difference, if any, between (x) twenty percent of eight-eighths (20% of 8/8ths) and  (y) all validly existing royalties, overriding royalties and other burdens affecting the Leases as of the date hereof of all Hydrocarbons produced and saved from or attributable or allocable to the Leases INSOFAR AND ONLY INSOFAR as the Leases cover both the Subject Lands and those formations situated in that interval extending from the surface of the earth down to the top of the Fayetteville Shale Formation being the correlative stratigraphic equivalent to that point found at 5,091 feet measured depth on the Log (the “Shallow Interval”).  For purposes of this Section 1.2(k) only, the term “Leases” shall mean and include (i) the Leases, (ii) each and every modification, renewal and extension of any Lease, and (iii) any new oil, gas and mi neral lease that is taken or acquired in replacement, in whole or in part, of any Lease while such Lease is in force and effect or within six (6) months after the expiration, termination or release thereof.

1.3

Assumed Liabilities.  Upon the terms and subject to the conditions of this Agreement, Buyer shall assume and become responsible for all of the Assumed Liabilities effective as of the Effective Time.

1.4

Excluded Liabilities.  Buyer shall not assume any Excluded Liabilities. “Excluded Liabilities” are any Liabilities of Seller other than the Assumed Liabilities.

1.5

Purchase Price.  As consideration for the sale of the Purchased Assets, the aggregate consideration to be paid by Buyer to Seller shall be (i) Five Hundred Nineteen Million Six Hundred Eleven Thousand One Hundred Eleven Dollars ($519,611,111) subject to adjustment in accordance with Sections 1.7, 1.8 and 1.10 (the “Purchase Price”), payable on the Closing Date by wire transfer of immediately available funds to the account designated by Seller to Buyer no later than May 2, 2008, and (ii) the assumption of Assumed Liabilities.

1.6

Allocated Values.  The Purchase Price shall be allocated to the Purchased Assets in accordance with the values set forth in ExhibitD, subject to reduction and increase of such values pursuant to Article VI. Such values (singularly, the “Allocated Value,” and collectively, the “Allocated Values”) shall be binding for purposes of adjusting the Purchase Price pursuant to Article VI.

1.7

Adjustments to Purchase Price.   (a)

The Purchase Price shall be adjusted as follows:

(i)

The Purchase Price shall be increased by the sum of the following:

(A)

an amount equal to any and all ad valorem, property, production, excise, severance and similar taxes (other than income taxes) and assessments based upon or measured by the ownership of the Purchased Assets paid by or on behalf of Seller that is attributable to periods of time from and after the Effective Time, which

4

amounts shall, to the extent not actually assessed as of the Effective Time, be computed and prorated in accordance with this Section 1.7;

(B)

an amount equal to any and all expenses and expenditures attributable to the Purchased Assets that are being paid by or on behalf of Seller that is attributable to the periods from and after the Effective Time, as calculated in accordance with GAAP and this Section 1.7; and

(C)

the amount of any proceeds received by Buyer attributable to the Purchased Assets, including, but not limited to, proceeds from the sale of Hydrocarbons, that are attributable to any of the periods prior to the Effective Time, as calculated in accordance with GAAP and this Section 1.7.

(ii)

The Purchase Price shall be reduced by the sum of the following:

(A)

an amount equal to any unpaid ad valorem, property, production, excise, severance and similar taxes (other than income taxes) and assessments based upon or measured by the ownership of the Purchased Assets paid by or on behalf of Buyer that are attributable to periods of time prior to the Effective Time, which amounts shall, to the extent not actually assessed as of the Effective Time, be computed and prorated in accordance with this Section 1.7;

(B)

an amount equal to any and all expenses attributable to the Purchased Assets that are paid by or on behalf of Buyer that are attributable to any periods prior to the Effective Time, as calculated in accordance with GAAP and this Section 1.7;

(C)

the amount of any proceeds received by Seller attributable to the Purchased Assets, including but not limited to proceeds from the sale of Hydrocarbons, that are attributable to the periods of time from and after the Effective Time, as calculated in accordance with GAAP and this Section 1.7;

(D)

the value of any Title Defects identified pursuant to and subject to the limitations described in Article VI;

(E)

the value of any Retained Assets as provided in Section 6.14(c);

(F)

the aggregate amounts payable to owners of working interests, royalties and overriding royalties and other interests in the Purchased Assets held in suspense by Seller, as of the Closing Date, to the extent such amounts held in suspense are not transferred to Buyer at Closing (along with interest and penalties, if any, accrued as of the Closing Date in accordance with GAAP resulting from Seller’s failure to escheat any such suspended funds to the applicable state under applicable law); and

5

(iii)

The Purchase Price shall be reduced or increased, as the case may be, by the volumetric difference between the actual aggregate net gas Imbalance as of the Effective Time and 18,592 mcf overproduced (which is Seller’s current estimate of the aggregate net gas Imbalance (cumulative working interests), as more particularly set forth for each of the Purchased Assets in Exhibit E) multiplied by $4.00 per net mcf.

(b)

The net adjustment to the Purchase Price that results from the application of Section 1.7(a) shall be referred to as the “Purchase Price Adjustment”.  If the Purchase Price Adjustment is positive, the Purchase Price shall be increased by the amount of the Purchase Price Adjustment. If the Purchase Price Adjustment is negative, the Purchase Price shall be reduced by the absolute value of the Purchase Price Adjustment.

1.8

Termination for Reduction. If net adjustments to the Purchase Price pursuant to Article VI exceed twenty percent (20%) of the original unadjusted Purchase Price, either Seller or Buyer may terminate this Agreement by giving written notice to the other Party no later than five (5) days prior to the Closing Date.

1.9

Closing Date Adjustment to Purchase Price.  At least three (3), but no more than seven (7), days prior to the expected Closing Date, Seller shall deliver to Buyer a written statement setting forth Seller’s good faith estimate of the Purchase Price Adjustment (the “Closing Date Estimated Purchase Price Adjustment”). The Purchase Price as adjusted by the Closing Date Estimated Purchase Price Adjustment shall be referred to as the “Closing Date Aggregate Purchase Price”.

1.10

Post-Closing Adjustments to Purchase Price.  (a) As promptly as practicable, but in no event earlier than sixty (60) days after the Closing Date nor later than ninety (90) days after the Closing Date, Seller shall deliver to Buyer a statement (the “Initial Post-Closing Purchase Price Adjustment Statement”), setting forth in reasonable detail Seller’s calculation of the Purchase Price Adjustment. Seller shall provide Buyer access to all relevant books and records and supporting documentation in connection with Seller’s preparation of, and shall consult with Buyer in preparing, the Initial Post-Closing Purchase Price Adjustment Statement.

(b)

The Initial Post-Closing Purchase Price Adjustment Statement shall be subject to Buyer’s review. In reviewing the Initial Post-Closing Purchase Price Adjustment Statement, Buyer and its agents and representatives (including, without limitation, accountants and attorneys) shall have the right to communicate with, and to review the work papers, schedules, memoranda and other documents which were prepared by or on behalf of, Seller in its calculation of the Purchase Price Adjustment. Buyer and its agents and representatives (including, without limitation, accountants and attorneys) shall also have access to all relevant books and records reasonably required for Seller to complete its review. The Parties shall have sixty (60) days following delivery of the Initial Post-Closing Purchase Price Adjustment Statement to agree as to its accuracy.

(c)

To the extent the Parties are able to agree on all or a portion of the Purchase Price Adjustment set forth in the Initial Post-Closing Purchase Price Adjustment Statement, such agreed upon amount shall be referred to as the “Initial Post-Closing Estimated Purchase Price Adjustment Amount”.  To the extent the Parties fail to fully agree on the Purchase Price Adjustment as set forth

6

in the Initial Post-Closing Purchase Price Adjustment Statement, any disputes thereon shall be resolved pursuant to Section 1.10(d).

(i)

If the Initial Post-Closing Estimated Purchase Price Adjustment Amount is less than the Closing Date Estimated Purchase Price Adjustment, Seller shall pay Buyer an amount equal to such difference.

(ii)

If the Initial Post-Closing Estimated Purchase Price Adjustment Amount is greater than the Closing Date Estimated Purchase Price Adjustment, Buyer shall pay Seller an amount equal to such difference.

(iii)

The amount payable in accordance with Section 1.10(c)(i) or Section 1.10(c)(ii) above is referred to as the “Initial Post-Closing True-Up Amount”.  The Initial Post-Closing True-Up Amount shall be paid by the applicable Party within seven (7) days of the determination of the Initial Post-Closing Estimated Purchase Price Adjustment Amount by wire transfer of immediately available funds to the account designated by the Party entitled to such payment.

(d)

(i)

As promptly as practicable but in no event earlier than one hundred eighty (180) days after the Effective Time nor later than two hundred ten (210) days after the Effective Time, Buyer shall deliver to Seller a statement (the “Final Post-Closing Purchase Price Adjustment Statement”), setting forth in reasonable detail Buyer’s calculation of the Purchase Price Adjustment.  Buyer shall provide Seller access to all relevant books and records and supporting documentation in connection with Buyer’s preparation of the Final Post-Closing Purchase Price Adjustment Statement, and shall consult with Seller in preparing, the Final Post-Closing Purchase Price Adjustment Statement.

(ii)

The Final Post-Closing Purchase Price Adjustment Statement shall be subject to Seller’s review. In reviewing the Final Post-Closing Purchase Price Adjustment Statement, Seller and its agents and representatives (including, without limitation, accountants and attorneys) shall have the right to communicate with, and to review the work papers, schedules, memoranda and other documents which were prepared by or on behalf of, Buyer in its calculation of the Purchase Price Adjustment. Buyer and its agents and representatives (including, without limitation, accountants and attorneys) shall also have access to all relevant books and records reasonably required for Seller to complete its review.  Within forty-five (45) days of Seller’s receipt of the Final Post-Closing Purchase Price Adjustment Statement, Seller shall by written notice advise Buyer of any exceptions (described in reasonable detail) which Seller may have to the Final Post-Closing Purchase Price Adjustment Statement (“Seller’s Dispute Notice”).

(iii)

For a period of twenty (20) days after Buyer’s receipt of a Seller’s Dispute Notice, the Parties shall use their commercially reasonable efforts to agree on the Purchase Price Adjustment. If the Parties are able to reach agreement on the Purchase Price Adjustment, such resolution shall be final, binding and conclusive.

7

(iv)

If after such twenty (20) day period, Seller and Buyer are unable to reach agreement on the Purchase Price Adjustment, the matter shall be referred to an independent national accounting firm mutually acceptable to the Parties (the “Independent Accounting Firm”). The Parties shall cause the Independent Accounting Firm to submit to them a determination of the Purchase Price Adjustment within thirty (30) days after submission of the matter, and such report and determination shall be final, non-appealable, binding and conclusive on Buyer and Seller. The fees, costs and expenses of the Independent Accounting Firm shall be paid fifty percent (50%) by Seller and fifty percent (50%) by Buyer.

(v)

The Purchase Price Adjustment, as finally determined in accordance with this Section 1.10(d), shall be referred to as the “Final Post-Closing Purchase Price Adjustment Amount”.

(A)

If the Final Post-Closing Purchase Price Adjustment Amount is less than the Initial Post-Closing Estimated Purchase Price Adjustment Amount, Seller shall pay Buyer an amount equal to such difference.

(B)

If the Final Post-Closing Purchase Price Adjustment Amount is greater than the Initial Post-Closing Estimated Purchase Price Adjustment Amount, Buyer shall pay Seller an amount equal to such difference.

(C)

The amount payable in accordance with Section 1.10(d)(v)(A) or 1.10(d)(v)(B) above is referred to as the “Final Post-Closing True-Up Amount.”  The Final Post-Closing True-Up Amount shall be paid by the applicable Party within seven (7) days of the final determination of the Final Post-Closing Purchase Price Adjustment Amount by wire transfer of immediately available funds to the account designated by the Party entitled to such payment.

1.11

Additional Proceeds.  (a) If at any time and from time to time, after the last date for which proceeds have been received and reflected in the Final Post-Closing Purchase Price Adjustment Amount, Buyer receives any proceeds attributable to the Purchased Assets that are attributable to any period prior to the Effective Time, as calculated in accordance with GAAP and Section 1.7, Buyer shall promptly pay to Seller all such proceeds.

(b)

If at any time and from time to time, after the last date for which proceeds have been received and reflected in the Final Post-Closing Purchase Price Adjustment Amount, Seller receives any proceeds attributable to the Purchased Assets that are attributable to any period from and after the Effective Time, as calculated in accordance with GAAP and Section 1.7, Seller shall promptly pay to Buyer all such proceeds.

8

ARTICLE II

CLOSING

2.1

The Closing. The Closing shall take place at the offices of SEECO, Inc., 2350 N. Sam Houston Parkway East, Suite 125, Houston, Texas 77032, commencing at 9:00 a.m. local time on the Closing Date. The “Closing Date” shall be May 5, 2008, or such other date as may be mutually acceptable to the Parties.

2.2

Deliveries by Seller at the Closing.  At the Closing, Seller shall deliver the following:

(a)

Four (4) original counterparts of an Assignment, Bill of Sale and Conveyance in the form of Exhibit F hereto (the “Assignment and Bill of Sale”) duly executed by Seller and acknowledged;

(b)

Four (4) original counterparts of a Partial Release, in recordable form, whereby the Subject Lands shall be released from the terms of the Field Services Agreement effective  as of the Closing Date, which Partial Release shall be duly executed and acknowledged by DGC.

(c)

Four (4) original counterparts of an Assignment and Bill of Sale, in form and substance reasonably acceptable to DGC and Buyer (the “Gathering System Assignment”), assigning to Buyer all of DGC’s right, title and interest in and to the Gathering System (as defined herein below) warranting the same against claims by, through and under DGC but otherwise without any warranty, express or implied.  

(d)

the various certificates, documents and instruments referred to in Section 7.2;

(e)

executed copies of mutually acceptable change of operator forms, transfer orders or letters-in-lieu, government approved assignment forms to be prepared by Seller; and

(f)

such other instruments as are necessary to carry out Seller’s obligations under this Agreement.

2.3

Deliveries by Buyer at the Closing.  At the Closing, Buyer shall deliver to the Seller the following:

(a)

the Closing Date Aggregate Purchase Price by wire transfer of immediately available funds;

(b)

Four (4) original counterparts of the Assignment and Bill of Sale and of the Gathering System Assignment duly executed by Buyer and acknowledged;

(c)

the other certificates, documents and instruments referred to in Section 7.3; and

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(d)

such other instruments as are necessary to carry out Buyer’s obligations under this Agreement.

2.4

Proceedings at Closing.  All proceedings to be taken and all documents to be executed and delivered at the Closing shall be deemed to have been taken and executed simultaneously, and, except as permitted hereunder, no proceedings shall be deemed taken nor any document executed and delivered until all have been taken, executed and delivered.

ARTICLE III

REPRESENTATIONS AND WARRANTIES OF SELLER

As an inducement to Buyer to enter into this Agreement and to consummate the transactions contemplated herein, except as set forth on the schedules to this Article III, Seller represents and warrants the following to Buyer, each of which representations and warranties is material to and is relied upon by Buyer. Any disclosure set forth on any particular schedule shall be treated as disclosed with respect to all other sections of this Article III regardless of whether or not a specific reference is made thereto, provided it is reasonably apparent from a reading of the disclosure that such disclosure is applicable to such other section. The inclusion of any item or fact in the schedules shall not be deemed an admission that such item or fact is material for the purposes of this Agreement.

3.1

Organization and Qualification.  Seller has been duly organized and is validly existing and in good standing under the laws of the State of Arkansas, and has full corporate power and authority to carry on its business as currently being conducted and to own or lease and operate the properties it owns or leases as and in the places now owned, leased or operated, respectively. Seller is not in default under or in violation of any provision of its Certificate of Incorporation or Bylaws. Seller is duly qualified or licensed to do business and is in good standing as a foreign corporation in each jurisdiction in which the character or location of its assets or properties (whether owned, leased or licensed) or the nature of its business make such qualification necessary, except where the failure to be so qualified or in good standing, individually or in the aggregate, has not had and would not reasonably be expected to have a Seller Material Adverse Effect.

3.2

Authority; Binding Effect.  (a) The execution and delivery by Seller of this Agreement and the consummation by Seller of the transactions contemplated hereby have been duly and validly authorized by all necessary corporate action on the part of Seller.

(b)

This Agreement and each agreement, instrument or document being or to be executed and delivered by Seller in connection with the transactions contemplated hereby or thereby (“Seller Related Documents”), upon due execution and delivery by Seller, will constitute, assuming the due execution and delivery by the other parties thereto, the legal, valid, and binding obligation of Seller, enforceable in accordance with its respective terms (except as enforcement may be limited by bankruptcy, insolvency, reorganization, moratorium or similar laws relating to or limiting creditors’ rights generally or by application of equitable principles regardless of whether such enforceability is considered in a proceeding at law or in equity).

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3.3

Governmental Entities.  Except as set forth on Schedule 3.3 or as otherwise expressly set forth herein, Seller is not required to submit any material notice, report or other filing with any Governmental Entity in connection with its execution or delivery of this Agreement or any of the Seller Related Documents or the consummation of the transactions contemplated hereby and no consent, approval or authorization of any Governmental Entity is required to be obtained by Seller in connection with the execution, delivery and performance of this Agreement, except (a) for such filings as may be required under the Hart-Scott-Rodino Act and (b) where such failure to submit such notice, report or other filing or obtain such consent, approval or authorization would not reasonably be expected to have a Seller Material Adverse Effect.   

3.4

No Conflicts.  Except as set forth on Schedule 3.4, the execution, delivery and performance of this Agreement and any of the Seller Related Documents by Seller does not and will not:

(a)

Conflict with or result in any breach of the provisions of, or constitute a default or require the consent of any person or entity under the organizational documents of Seller;

(b)

 (i) Violate any restriction to which Seller is subject or, with or without the giving of notice, the passage of time, or both, (ii) violate (or give rise to any right of termination, cancellation or acceleration under) any mortgage, deed of trust, license, lease, indenture, contract or other material agreement or instrument, whether oral or written, to which Seller is a party, or by which it or any of the assets of Seller is bound (which will not be satisfied, assigned or terminated on or prior to the Closing as a result of the transactions contemplated by this Agreement), (iii) result in the termination of any such instrument or termination of any provisions in such instruments or (iv) result in the creation or imposition of any Security Interest upon the Purchased Assets, in any such case or cases, that would reasonably be expected to have a Seller Material Adverse Effect; or

(c)

Constitute a violation of any applicable rule, regulation, law, statute, ordinance, or any judgment, decree, writ, injunction or order of any Governmental Entity, where such violation has not had or would not reasonably be expected to have a Seller Material Adverse Effect.

3.5

Contracts; Leases.  Schedule 3.5 is a complete list as of the date of this Agreement of the following types of Assigned Contracts (collectively, the “Material Contracts” and each, a “Material Contract”): (i) any agreement(s) with any affiliate(s) of Seller, (ii) any agreement(s) of Seller for the sale, exchange, or other disposition of Hydrocarbons produced from the Purchased Assets that is not cancelable without penalty on not more than sixty (60) days prior written notice, (iii) any agreement(s) of Seller to sell, lease, farmout, or otherwise dispose of any of its interests in any of the Purchased Assets other than conventional rights of reassignment, (iv) any tax partnership(s) of Seller affecting any of the Purchased Assets, (v) any operating agreement(s) to which Seller’s interests in any of the Purchased Assets is subject, (vi) any agreement(s) pursuant to which Seller has forfeited or not consented to, its right to participate in future oil and gas operations, (vii) any agreement(s) pursuant to which Seller has received an advance payment,

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prepayment or similar deposit and has a refund obligation with respect to any natural gas or products purchased, sold, gathered, processed or marketed by or for Seller out of the Purchased Assets, (viii) any contract that requires Seller to expend more than $200,000 in any year in connection with the Purchased Assets, (ix) any option to purchase or call on the Hydrocarbons produced from the Purchased Assets and (x) any lease(s), title retention agreement(s) or security interest(s) affecting any of the Equipment.  Seller is not in material default under the terms of any Lease or Material Contract, and to Seller’s Knowledge there is no material default existing or continuing by any other party under the terms of any Lease or Material Contract and each Lease and Material Contract is in full force and effect in all material respects and is valid and enforceable by Seller in accordance with its terms, assuming the due authorization, e xecution and delivery thereof by each of the other parties thereto (except as enforcement may be limited by bankruptcy, insolvency, reorganization, moratorium or similar laws relating to or limiting creditors’ rights generally or by application of equitable principles).

3.6

Title to Equipment. Seller owns all of its interests in the Equipment free and clear of all Liens, except for Permitted Liens.

3.7

Oil and Gas Interests.  (a) To the Knowledge of Seller, all payments (including all delay rentals, royalties, shut-in royalties and valid calls for payment or prepayment under operating agreements) due and owing by Seller under the Leases and Assigned Contracts have been and are being made (timely, and before the same became delinquent) by Seller in all material respects other than those delinquent payments that are contested by Seller in good faith in the normal course of business.

(b)

Except as otherwise provided in Section 1.7(a)(iii), Seller is not obligated, by virtue of a prepayment arrangement, a “take or pay” arrangement, production payment or any other arrangement, to deliver oil, gas or other Hydrocarbons produced from the Purchased Assets at some future time without then receiving full payment therefor.

3.8

No Litigation.  Except as set forth on Schedule 3.8, there are no actions, suits, dispute resolution proceedings, claims, governmental investigations or other legal or administrative proceedings, or any orders decrees or judgments in progress, pending or in effect, or, to the Knowledge of Seller, threatened against or relating to Seller (which are reasonably likely to impair Buyer’s ability to perform its obligations under this Agreement) or relating to any of the Purchased Assets, or against or relating to the transactions contemplated by this Agreement, and there are none pending in state courts, or in any federal courts, or, to the Knowledge of Seller, pending in other jurisdictions or threatened in writing, at law or in equity, by or before any federal, state or municipal court or other governmental agency, department, commission, board, bureau, instrumentality or other Governmental Entity.

3.9

Brokers’ Fees.  Except as set forth on Schedule 3.9, Seller has no liability or obligation to pay any fees or commissions to any broker, finder or agent with respect to the transactions contemplated by this Agreement. Buyer shall not directly or indirectly have any responsibility, liability or expense, as a result of undertakings or agreements of Seller or their Affiliates, for brokerage fees, finder’s fees, agent’s commissions or other similar forms of

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compensation in connection with this Agreement or any agreement or transaction contemplated hereby.

3.10

Books and Records.  The Records are complete and correct in all material respects and have been maintained in accordance with sound business practices.

3.11

Disclaimer.  Except as expressly set forth in this Agreement or the Seller Related Documents, Seller makes no representation or warranty, express or implied, at law or in equity, in respect of Seller or any of its assets, liabilities or operations, including, without limitation, the Purchased Assets and the Assumed Liabilities, and any such other representations or warranties are hereby expressly disclaimed.

3.12

Bankruptcy.  There are no bankruptcy, reorganization, or receivership proceedings pending against, or, to Seller’s Knowledge, being contemplated by or threatened against Seller.

ARTICLE IV

REPRESENTATIONS AND WARRANTIES OF BUYER

As an inducement to Seller to enter into this Agreement and to consummate the transactions contemplated herein, except as set forth on the schedules to this Article IV, Buyer represents and warrants the following to Seller, each of which representations and warranties is material to and is relied upon by Seller. Any disclosure set forth on any particular schedule shall be treated as disclosed with respect to all other sections of this Article IV regardless of whether or not a specific reference is made thereto, provided it is reasonably apparent from a reading of the disclosure that such disclosure is applicable to such other section. The inclusion of any item or fact in the schedules shall not be deemed an admission that such item or fact is material for the purposes of this Agreement.

4.1

Organization and Qualification.  Buyer is a Delaware corporation duly organized, validly existing and in good standing under the laws of the jurisdiction of its organization, formation or incorporation, as applicable, with full corporate power and authority to carry on its business as currently being conducted and to own or lease and operate the properties it owns or leases as and in the places now owned, leased or operated, respectively. Buyer is not in default under or in violation of any provision of its Certificate of Incorporation or Bylaws. Buyer is duly qualified or licensed to do business and is in good standing as a foreign corporation in Arkansas and in each other jurisdiction in which the character or location of its assets or properties (whether owned, leased or licensed) or the nature of its business make such qualification necessary, except where the failure to be so qualified or in good standing , individually or in the aggregate, has not had and would not reasonably be expected to have a Buyer Material Adverse Effect.

4.2

Authority; Binding Effect.  (a) The execution and delivery by Buyer of this Agreement and the consummation by Buyer of the transactions contemplated hereby have been duly and validly authorized by all necessary corporate action on the part of Buyer.

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(b)

This Agreement and each agreement, instrument or document being or to be executed and delivered by Buyer in connection with the transactions contemplated thereby (“Buyer Related Documents”), upon due execution and delivery by Buyer, will constitute, assuming the due execution and delivery by the other parties thereto, the legal, valid, and binding obligation of Buyer, enforceable in accordance with its respective terms (except as enforcement may be limited by bankruptcy, insolvency, reorganization, moratorium or similar laws relating to or limiting creditors’ rights generally or by application of equitable principles).

4.3

Governmental Entities.  Except as set forth on Schedule 4.3 or as otherwise expressly set forth herein, Buyer is not required to submit any material notice, report or other filing with any Governmental Entity in connection with its execution or delivery of this Agreement or any of Buyer Related Documents or the consummation of the transactions contemplated hereby and no consent, approval or authorization of any Governmental Entity is required to be obtained by Buyer in connection with the execution, delivery and performance of this Agreement, except (a) for such filings as may be required under the Hart-Scott-Rodino Act and (b) where such failure to submit such notice, report or other filing or obtain such consent, approval or authorization would not reasonably be expected to have a Buyer Material Adverse Effect.

4.4

No Conflicts.  Except as set forth on Schedule 4.4, the execution, delivery and performance of this Agreement and any of Buyer Related Documents by Buyer does not and will not:

(a)

Conflict with or result in any breach of the provisions of, or constitute a default or require the consent of any person or entity under the organizational documents of Buyer;

(b)

 (i) Violate any restriction to which Buyer is subject or, with or without the giving of notice, the passage of time, or both, (ii) violate (or give rise to any right of termination, cancellation or acceleration under) any mortgage, deed of trust, license, lease, indenture, contract or other material agreement or instrument, whether oral or written, to which Buyer is a party, or by which it or any of the assets of Buyer are bound (which will not be satisfied, assigned or terminated on or prior to the Closing as a result of the transactions contemplated by this Agreement), (iii) result in the termination of any such instrument or termination of any provisions in such instruments or (iv) result in the creation or imposition of any Security Interest upon the properties or assets of Buyer, in any such case or cases, that will have a Buyer Material Adverse Effect; or

(c)

Constitute a violation of any applicable rule, regulation, law, statute, ordinance, or any judgment, decree, writ, injunction or order of any Governmental Entity, where such violation has not had or would not reasonably be expected to have a Buyer Material Adverse Effect.

4.5

No Litigation.  There are no actions, suits, dispute resolution proceedings, claims, governmental investigations or other legal or administrative proceedings, or any orders decrees or judgments in progress, pending or in effect, or, to the Knowledge of Buyer, threatened against or relating to Buyer which are reasonably likely to impair Buyer’s ability to perform its obligations

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under this Agreement or against or relating to the transactions contemplated by this Agreement, and there are none pending in state courts, or in any federal courts, or, to the Knowledge of Buyer, pending in other jurisdictions or threatened in writing, at law or in equity, by or before any federal, state or municipal court or other governmental agency, department, commission, board, bureau, instrumentality or other Governmental Entity.  

4.6

Brokers’ Fees.  Except as set forth on Schedule 4.6, Buyer has no liability or obligation to pay any fees or commissions to any broker, finder or agent with respect to the transactions contemplated by this Agreement. Seller shall not directly or indirectly have any responsibility, liability or expense, as a result of undertakings or agreements of Buyer or its Affiliates, for brokerage fees, finder’s fees, agent’s commissions or other similar forms of compensation in connection with this Agreement or any agreement or transaction contemplated hereby.

4.7

SEC Disclosure.  Buyer is an experienced and knowledgeable investor and operator in the oil and gas business.  Buyer is acquiring the Purchased Assets for its own account for use in its trade or business, and not with a view toward or for sale in connection with any distribution thereof, nor with any present intention of making a distribution thereof within the meaning of the Securities Act of 1933, as amended.

4.8

Independent Evaluation.  As of Closing, Buyer represents that it is sophisticated in the evaluation, purchase, operation and ownership of oil and gas properties and that in making its decision to enter into this Agreement and to consummate the transaction contemplated herein, and has satisfied itself as to the physical condition and environmental condition of the Purchased Assets.

4.9

Qualified Buyer.  Buyer possesses all required governmental licenses, permits, bonds, certificates, orders and authorizations necessary to own the Purchased Assets, except those customarily obtained after the sale or conveyance of the Purchased Assets.

4.10

Disclaimer.  Except as expressly set forth in this Agreement or Buyer Related Documents, Buyer makes no representations or warranties, express or implied, at law or in equity, in respect of Buyer or any of its assets, liabilities or operations, including, without limitation, with respect to merchantability or fitness for any particular purpose, and any such other representations or warranties are hereby expressly disclaimed.

ARTICLE V

COVENANTS

5.1

Closing Efforts.  Each of the Parties shall use its Reasonable Best Efforts to take all actions and to do all things necessary, proper or advisable to consummate the transactions contemplated by this Agreement, including using its Reasonable Best Efforts to ensure that (a) its representations and warranties are true and correct in all material respects at the Closing Date and (b) the conditions to the obligations of the other Party to consummate the Closing are satisfied on or before April 28, 2008.

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5.2

Governmental and Third-Party Notices and Consents.  (a) Each Party shall use its Reasonable Best Efforts to obtain, at its expense, all waivers, permits, consents, approvals or other authorizations from Governmental Entities and to effect all registrations, filings and notices with or to Governmental Entities, as may be required for such Party to consummate the transactions contemplated by this Agreement and to otherwise comply with all applicable laws and regulations in connection with the consummation of the transactions contemplated by this Agreement. Without limiting the generality of the foregoing, each of the Parties shall promptly file any Notification and Report Forms and related material that it may be required to file with the Federal Trade Commission and the Antitrust Division of the United States Department of Justice under the Hart-Scott-Rodino Act, shall use its Reasonable Best Efforts to obtain an early termination of the applicable waiting period, and shall make any further filings or information submissions pursuant thereto that may be necessary, proper or advisable; provided that in no event shall Buyer or any of its Affiliates be required to agree or commit to divest, hold separate, offer for sale, abandon, limit its operation of or take similar action with respect to any assets (tangible or intangible) or any business interest of it or any of its Affiliates in connection with or as a condition to receiving the consent or approval of any Governmental Entity (including, without limitation, under the Hart-Scott-Rodino Act).

(b)

Seller shall use its Reasonable Best Efforts (without the obligation to expend money except reasonable out-of-pocket costs) to obtain, at its expense, all such waivers, consents or approvals from third parties, and to give all such notices to third parties, as are required to be listed on the schedules hereto or as may be required for Seller to consummate the transactions contemplated by this Agreement and to otherwise comply with all applicable laws and regulations in connection with the consummation of the transactions contemplated by this Agreement, including, without limitation, any waivers, consents or approvals from third parties arising or delivered after the Closing.

5.3

Operation of Business of Seller.  (a) Except as contemplated by this Agreement, during the period from the date of this Agreement to the earlier of the Closing or the termination of this Agreement, Seller shall conduct its operations of the Purchased Assets in the ordinary course of business, consistent with past practice, and in compliance in all material respects with all applicable laws and regulations.  Without limiting the generality of the foregoing, except as set forth on Schedule 5.3, during this period, Seller shall not, without the written consent of Buyer, which consent shall not be unreasonably withheld or delayed:

(i)

abandon any part of the Purchased Assets;

(ii)

approve any operations relating to the Purchased Assets anticipated in any instance to cost the owner of the Purchased Assets more than $50,000 per authority for expenditure net to Seller’s interest (except emergency operations, operations in the ordinary course of business which include, without limitation, participation in any and all integrations submitted to the Arkansas Oil and Gas Commission, all operations proposed under presently existing contractual obligations including, but not limited to, all joint operating agreements, ongoing commitments and operations undertaken to avoid a monetary penalty or forfeiture provision of any applicable agreement or order);

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(iii)

convey or dispose of any of the Purchased Assets or any interest therein (other than replacement of equipment, the sale of oil, gas and other liquid products produced from the Purchased Assets in the ordinary and regular course of business or as may be required in connection with any Preference Right) or enter into any farmout, farmin or other similar contract affecting the Purchased Assets;

(iv)

let lapse any insurance now in force with respect to the Purchased Assets;

(v)

encumber or mortgage the Purchased Assets or allow any lien or other encumbrance to become a burden on the Purchased Assets; or

(vi)

materially modify or terminate any of the operating agreements or other significant Assigned Contract or Lease.

If Buyer fails to respond within ten (10) calendar days following delivery by Seller of a written request for approval or consent with respect to any such proposed action or expenditure, then Buyer shall be deemed to have agreed with Seller’s election or other determination with respect thereto. Buyer shall not unreasonably withhold its approval or consent with respect to any such proposed action or expenditure.

(b)

Nothing contained in this Agreement shall give to Buyer, directly or indirectly, rights to control or direct the operations of Seller prior to the Closing Date. Prior to the Closing Date, Seller shall exercise, consistent with the terms and conditions of this Agreement, complete control and supervision of their operations.

5.4

Expenses.  Except as otherwise provided in this Agreement, each of the Parties shall bear its own costs and expenses (including legal and accounting fees and expenses) incurred in connection with this Agreement and the transactions contemplated hereby.

5.5

Notification.  Seller, on one hand, and Buyer, on the other, shall notify the other Party in writing of the existence or happening of any fact, event or occurrence which should be included on the schedules to Article III or Article IV, as applicable, in order to make the representations and warranties set forth in Article III or Article IV, as applicable, true and correct in all material respects as of the Closing Date, it being understood and agreed that the delivery of such information shall not in any manner constitute a waiver by Buyer or Seller, as applicable, of any of the conditions precedent to the Closing hereunder; provided, however, that in determining whether there is a breach of any representation or warranty contained in Article III or Article IV, as applicable, for purposes of the indemnification to be provided by Indemnifying Party pursuant to Articl e VIII, such representation or warranty shall be qualified by any information provided pursuant to this Section 5.5.

5.6

Bulk Sales Laws.  Buyer acknowledges that Seller will not comply with the provisions of any bulk sales laws in any jurisdiction in connection with the transactions contemplated by this Agreement.

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5.7

Access to Purchased Assets and Records.  (a) Subject to the terms and conditions of the Confidentiality Agreement dated February 19, 2008 (the “Confidentiality Agreement”), by and between Buyer and Seller, from the date of this Agreement until the Closing, Seller shall cooperate with Buyer and provide Buyer and its representatives, consultants, and current and prospective lenders and advisors, and each of their authorized representatives reasonable access to the Purchased Assets and reasonable access to the Records, but only to the extent that Seller may do so without violating any obligations to any third party and to the extent that Seller has authority to grant such access without breaching any restriction legally binding on Seller. Buyer shall conduct all such inspections and other information gathering described above only (i) (x) during regular business hours and (y) during any weekends and aft er hours requested by Buyer that can be reasonably accommodated by Seller, and (ii) in a manner which will not unduly interfere with Seller’s operation of the Purchased Assets.

(b)

Subject to the Confidentiality Agreement from the date of this Agreement until the Closing, Seller shall afford to Buyer and its officers, employees, agents and current and prospective lenders and each of their authorized representatives reasonable access to the Purchased Assets, including the Records in accordance with Section 5.7(a). During such period, Seller shall also make available to Buyer, upon reasonable notice during normal business hours, Seller’s personnel knowledgeable with respect to the Purchased Assets in order that Buyer may make such diligent investigation as Buyer considers desirable. For those Purchased Assets that are not operated by Seller, Seller shall use commercially reasonable efforts to obtain permission from the operator for Buyer to conduct such inspections but, provided Seller has exercised such commercially reasonable efforts, Seller shall have no liability to Buyer for failure t o obtain any such operator’s permission. Upon reasonable notice to Seller, Buyer shall have the right to conduct an environmental assessment of all or any portion of the Purchased Assets (the “Assessment”), to be conducted by Buyer’s personnel or a reputable environmental consulting or engineering firm approved in advance in writing by Seller (such approval not to be unreasonably withheld), but only to the extent that Seller may grant such right without violating any obligations to any third party (provided that Seller shall use its Reasonable Best Efforts to obtain any necessary third party consents to any Assessment to be conducted by Buyer).  The Assessment shall be conducted at the sole cost and expense of Buyer. After completing any Assessment of the Purchased Assets, Buyer shall, at its sole cost and expense, restore the Purchased Assets to their condition prior to the commencement of such Assessment, unless Seller requests otherwise, and shall promptly dispose of all drill cut tings, corings, or other investigative-derived wastes generated in the course of the Assessment. Upon Seller’s written request, Buyer shall provide Seller with a copy of the final version of all environmental reports prepared by, or on behalf of, Buyer with respect to any Assessment conducted on the Purchased Assets. In the event that any necessary disclosures under applicable laws are required with respect to matters discovered by any Assessment conducted by, for or on behalf of Buyer, Buyer agrees that Seller shall be the responsible party for disclosing such matters to the appropriate Governmental Entities; provided that, if Seller fails to promptly make such disclosure and Buyer or any of its Affiliates is legally obligated to make such disclosure, Buyer or any of its Affiliates, as applicable, shall have the right to fully comply with such legal obligation. If, by the Objection Date, as a result of its investigation pursuant to this Section 5.7(b), Buyer determines that with respect to the P urchased Assets, there exists a violation of any Environmental Law (an “Environmental Defect”), the Parties agree to negotiate in good faith a resolution satisfactory to both Parties.  If such a resolution is not reached prior to Closing with respect to any

18

such Environmental Defect, the affected Purchased Asset(s) shall be held back from the Purchased Assets to be transferred and conveyed to Buyer at Closing and the Purchase Price to be paid at Closing shall be reduced by the Allocated Value of the Purchased Asset(s) held back, and the parties shall have the rights and remedies set forth in Section 5.7(c) below with respect thereto.

(c)

With respect to any Purchased Asset(s) held back from the initial Closing pursuant to Section 5.7(b) above, the Parties shall have the following rights and remedies:

(i)

Seller shall have the right, but not the obligation, to cure the Environmental Defect to the reasonable satisfaction of Buyer, so long as such cure is accomplished on or before 180 days following the initial Closing (the “Environmental Cure Period”).  Within ten (10) days following the date that Seller provides Buyer with reasonably satisfactory evidence that an Environmental Defect has been cured, Seller shall sell, assign and convey to Buyer, and Buyer shall purchase and accept from Seller, the affected Purchased Asset, in accordance with and subject to the terms and conditions of this Agreement, and Buyer shall pay to Seller the amount by which the Purchase Price was reduced at the initial Closing with respect to such affected Purchased Asset.  Contemporaneously with the assignment of the affected Purchased Asset to Buyer, Seller shall be released from all further liability or obl igation to Buyer with respect to such affected Purchased Asset.  

(ii)

Seller may notify Buyer in writing that it has elected to indemnify Buyer from all liabilities and obligations arising out of the Environmental Defect, but only if Buyer agrees the indemnity, in such circumstance, is an appropriate remedy, and if the Parties can mutually agree on the form of the indemnity.  Within ten (10) days following the date that Seller notifies Buyer that Seller has elected to indemnify Buyer under this 5.7(c)(ii), Seller shall sell, assign and convey to Buyer, and Buyer shall purchase and accept from Seller, the affected Purchased Asset, in accordance with and subject to the terms and conditions of this Agreement, and Buyer shall pay to Seller the amount by which the Purchase Price was reduced at the initial Closing with respect to such affected Purchased Asset.  If Seller later cures the Environmental Defect to Buyer’s reasonable satisfaction, the indemnity and al l further liability or obligation to Buyer with respect to the affected Purchase Asset shall terminate.

(iii)

If an Environmental Defect has not been resolved under Section 5.7(c)(i) or (ii) above by the end of the Environmental Cure Period, either Party may refer the matter to arbitration (pursuant to the procedures set forth in Section 8.3(d)) for determination of the existence of and/or the value of such Environmental Defect at the time of the arbitration (the “Environmental Defect Value”).  The determination of the arbitrator shall be binding on the Parties.  Within ten (10) days following the date of the arbitrator’s decision, Seller shall sell, assign and convey to Buyer, and Buyer shall purchase and accept from Seller, the affected Purchased Asset, in accordance with and subject to the terms and conditions of this Agreement, and Buyer shall pay to Seller the amount by which the Purchase Price was reduced at the initial Closing with respect to such affected Purchased Asset less an y Environmental Defect Value.  Contemporaneously with the assignment of the affected Purchased Asset to Buyer, Seller shall be released from all further liability or obligation to Buyer with respect to the affected Purchased Asset.

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(d)

Seller and Buyer shall preserve until the fifth (5th) anniversary of the Closing Date all records possessed or to be possessed by such Party relating to any of the Purchased Assets prior to the Closing Date. After the Closing Date, where there is a legitimate purpose, such Party shall provide the other Party with access, upon prior reasonable written request specifying the need therefor, during regular business hours, to (a) the officers and employees of such Party and (b) the books of account and records of such Party, but, in each case, only to the extent relating to the Purchased Assets prior to the Closing Date, and the other Party and its representatives shall have the right to make copies of such books and records; provided, however, that the foregoing right of access shall not be exercisable in such a manner as to interfere unreasonably with the normal operations and business of such Party. Such records may neverth eless be destroyed by a Party if such Party sends to the other Party written notice of its intent to destroy records, specifying with particularity the contents of the records to be destroyed. Such records may then be destroyed after the thirtieth (30th) day after such notice is given unless another Party objects to the destruction in which case the Party seeking to destroy the records shall deliver such records to the objecting Party.

5.8

Further Assurances.  Upon the terms and subject to the conditions hereof, the Parties hereto shall execute such documents and other instruments and take such further actions as may be reasonably required to carry out the provisions hereof and consummate the transactions contemplated by this Agreement.

5.9

Delivery of Books and Records to Buyer.  Seller shall, within thirty (30) days after Closing, deliver the Records to Buyer.

5.10

Letters in Lieu; Assignments; Operatorship.  (a) Seller will execute on the Closing Date letters in lieu of division and transfer orders relating to the Purchased Assets, on forms prepared by Seller and reasonably satisfactory to Buyer, to reflect the transaction contemplated hereby.

(b)

Seller will prepare and execute, and Buyer will execute, on the Closing Date, all assignments necessary to convey to Buyer all federal and state Leases, if any, in the form as prescribed by the applicable Governmental Entity and otherwise acceptable to Buyer and Seller.

(c)

Seller makes no representations or warranties to Buyer as to transferability or assignability of operatorship of any Purchased Assets.  Seller is not aware of any effort by any third party to have Seller removed as operator of any property for which it is currently operator.  Rights and obligations associated with operatorship of such Purchased Assets are governed by operating and similar agreements covering the Purchased Assets and will be determined in accordance with the terms of such agreements.  However, Seller will assist Buyer in Buyer’s efforts to succeed Seller as operator of any Wells and units included in the Purchased Assets where Seller currently serves as operator.  Buyer shall, promptly following Closing, file all appropriate forms and declarations or bonds with federal and state agencies relative to its assumption of operatorship.  For all operated Purchased Assets, Seller sha ll execute and deliver to Buyer on the Closing Date, and Buyer shall promptly file the appropriate forms with the applicable regulatory agency transferring operatorship of such Assets to Buyer.

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ARTICLE VI

TITLE MATTERS

6.1

Title Information. Seller shall make all information in Seller’s or its agents’ possession regarding title to the Purchased Assets available to Buyer in Seller’s offices at reasonable times during Seller’s normal business hours.

6.2

Defensible Title.  “Defensible Title” means the title of Seller in and to each Lease, Well or Well Location that, subject to and except for the Permitted Encumbrances:

(a)

entitles Seller to receive not less than the Net Revenue Interests for the hydrocarbons and proceeds thereof produced in respect of each Lease, Well or Well Location as set forth on Exhibit A, C or D, as applicable,

(b)

obligates Seller to bear costs and expenses relating to the ownership, maintenance, repair, development, operation and production of hydrocarbons in respect of each Lease, Well or Well Location, in an amount not greater than the Working Interest in respect of each Lease as set forth on Exhibit A, C or D, as applicable, except to the extent modified by integration or non-consent adjustments in the ordinary course of business after the date of this Agreement or to the extent there is a corresponding proportionate increase in the Net Revenue Interests, and

(c)

is free and clear of encumbrances, liens and defects that impair the use and enjoyment of or that constitute a loss of interest in such Lease that a reasonable and prudent person engaged in the business of ownership, development and operation of oil and gas properties with knowledge of all applicable facts and circumstances and the understanding of their legal significance would not be willing to accept.

6.3

Defensible Title; Development Acreage.  For purposes of the Title Defect Notice set forth in Section 6.8 only, Seller’s title to any non-producing acreage (“Development Acreage”) included in the Leases shall be presumed to be Defensible Title unless Buyer can show through actual evidence submitted with a Title Defect Notice that Seller’s title to such Development Acreage (or any portion thereof) has failed or that the Development Acreage is subject to a lien or encumbrance (except for Permitted Encumbrances) that would constitute a material loss of interest in such Development Acreage, or the Net Mineral Acres making up such Development Acreage is less than the Net Mineral Acres set forth in Exhibit A.  Development Acreage does not include eWell Locations that have been given a specific Allocated Value on Exhibit D.

6.4

Allocated Value.  If an Allocated Value has not been given for a Lease or Well or Well Location or if the Allocated Value for any Lease or Well or Well Location is zero, Seller shall be conclusively presumed to have Defensible Title to such Lease or Well or Well Location.

6.5

Permitted Encumbrances.  “Permitted Encumbrances” shall include the following (but only to the extent they exist and constitute a burden on the Purchased Assets as of the Effective Time):

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(a)

any royalties, overriding royalties, net profits interests, production payments, reversionary interests and similar burdens if the net cumulative effect of such burdens does not reduce the Net Revenue Interests in respect of a Lease, a Well or a Well Location from the Net Revenue Interest specified on Exhibit A, C or D, as applicable;

(b)

liens for taxes or assessments not yet delinquent, or, if delinquent, being contested in good faith;

(c)

rights to consent by, notices to, filings with or actions by federal, state, local or tribal authorities in connection with the conveyance of the Purchased Assets if customarily obtained after a conveyance is made;

(d)

obligations to reassign upon the surrender or expiration of any Lease;

(e)

easements, rights of way, servitudes, permits, surface leases and other rights with respect to the surface or any restrictions on access to the surface or subsurface that do not materially interfere with the operation of the Purchased Asset;

(f)

any material encumbrance, defect in or objection to real property title including, without limitation, any Assumed Title Liabilities that is waived or assumed by Buyer;

(g)

division orders, transfer orders, letters in lieu of transfer orders and pooling or unitization orders, declarations or agreements if the net cumulative effect of such does not reduce the Net Revenue Interest from those specified on Exhibit A, C or D, as applicable;

(h)

materialmen’s, mechanics’, repairmen’s, contractors’, or other similar liens or charges (i) if the amount owed is not yet due and payable, (ii) if such lien or charge has not been filed pursuant to law and the time for filing has expired, (iii) if filed, such lien or charge has not yet become due and payable or payment is being withheld as provided by law, or (iv) if the validity of such lien or charge is being contested in good faith;

(i)

rights reserved to or vested in any governmental authority to control or regulate any of the Purchased Assets in any manner and all applicable laws, rules, regulations and orders of general applicability in the area;

(j)

liens arising under operating agreements, unitization and pooling agreements and production sales contracts securing amounts not yet due and payable or, if due, being contested in good faith; and

(k)

calls on or preferential rights to purchase production held by third parties to purchase production for a price at or above market price.

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6.6

Title Defect.  “Title Defect” means any material encumbrance, defect in or objection to real property title, excluding Permitted Encumbrances, that renders Seller’s title less than Defensible Title.  Notwithstanding the foregoing, the following shall not constitute Title Defects:

(a)

defects based on lack of information in Seller’s files;

(b)

defects in the chain of title consisting of the failure to recite marital status or omissions of successors or heirship proceedings, unless Buyer provides affirmative evidence that such failure or omission has resulted in a third party’s actual and superior claim of title to the Asset;

(c)

defects arising out of the lack of a survey if Seller has been paid proceeds from production in accordance with its Net Revenue Interest set forth on Exhibit A, C or D, as applicable for such Lease, Well or Well Location without suspense of such proceeds;

(d)

defects based on the failure to record leases issued by the United States or any state, local or tribal authority;

(e)

defects asserting a change in Net Revenue Interests or Working Interests based on an after-payout decrease in Net Revenue Interests or increase in Working Interests pursuant to a farm-in, farm-out or other agreement that is listed on Schedule 6.6, if the effect of such change is reflected in the Net Revenue Interests and Working Interests set forth in Exhibit A, C or D, as applicable;

(f)

defects related to suspension of revenues due and owing to Seller, if such suspension is not supported by facts and circumstances that would otherwise be a Title Defect; and

(g)

defects that have been cured or that are not material in light of the entire chain of title or subsequent agreements.

6.7

Title Defect Value.  “Title Defect Value” means the value of the Title Defect determined in accordance with the following:

(a)

If the Title Defect is a reduction in the Net Revenue Interests in respect of the Lease, the Title Defect Value thereof shall be equal to the Allocated Value of the Lease multiplied by a fraction the numerator of which is the positive difference between the actual Net Revenue Interest of Seller in the Lease and the Net Revenue Interest set forth for such Lease on Exhibit A and the denominator of which is the Net Revenue Interest set forth for such Lease on Exhibit A;

(b)

If the Title Defect is a lien or encumbrance other than a Permitted Encumbrance, the cost of removing the lien or encumbrance;

(c)

If the Title Defect is the increase in the Working Interests in respect of the Lease to the extent such increase is not accompanied by a corresponding increase in the Net

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Revenue Interests, the Title Defect Value thereof shall be determined by Buyer in good faith in its reasonable discretion; and

(d)

If the Title Defect represents only a possibility of title failure, the probability that such failure will occur will be taken into account in determining the Title Defect Value thereof.  In every instance the legal and practical effect of the Title Defect shall be taken into account in the determination of the Title Defect Value thereof.

Only that portion of the Lease that is materially and adversely affected by a Title Defect shall be considered for purposes of determining the Title Defect Value.

6.8

Title Defect Notice.  Buyer shall give Seller notice of any Title Defects (“Title Defect Notice”) as soon as possible but no later than April 28, 2008 (such date being referred to herein as the “Objection Date”).  The Title Defect Notice must include all of the following:

(a)

a description of the Title Defect;

(b)

a description of the reasonable basis for the Title Defect;

(c)

Reasonable Documentation supporting the basis for the Title Defect;

(d)

evidence supporting Buyer’s belief that the Title Defect has not been released or cured and is still enforceable; and

(e)

the identity and the Allocated Value of the Lease.

6.9

Assumed Title Liabilities.  Any notice that is not timely and properly given or that does not satisfy all of the foregoing shall not be a valid Title Defect Notice, and any Title Defects not included in a valid Title Defect Notice shall be deemed to be “Assumed Title Liabilities” and to have been waived or assumed by Buyer. Notwithstanding anything to the contrary contained in this Agreement, except as to any Title Defects subject to Section 6.11(b) or Section 6.13(b), after Closing, Seller’s only warranty of title to the Purchased Assets shall be that, as to claims arising by, through or under Seller, Seller has Defensible Title to the Oil and Gas Interests.

6.10

Reasonable Documentation.  “Reasonable Documentation” means a copy of any available title opinion or other explanations describing the Title Defect and

(a)

a copy of the relevant document, if the basis is a document;

(b)

the deed preceding and following a gap in the chain of title or a title opinion describing the gap in reasonable detail, if the basis is a gap in Seller’s chain of title;

(c)

a copy of the document creating the lien or encumbrance, if the basis is a lien or encumbrance, together with evidence supporting Buyer’s determination that the lien or encumbrance has not been released and is still enforceable; or

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(d)

any other reasonable documentation or explanation supporting the Title Defect.

6.11

Seller’s Options.  Seller shall have the right to cure any Title Defect but shall have no obligation to do so. If Buyer gives a Title Defect Notice, Seller shall have the option of:

(a)

curing the Title Defect before Closing, and, if such Title Defect is not cured before Closing, Seller shall further elect (b), (c) or (d);

(b)

indemnifying Buyer for all liabilities and obligations associated with the Title Defect, which indemnity shall terminate if Seller later cures the Title Defect, but only if Buyer agrees the indemnity, in such circumstance, is an appropriate remedy, and if the Parties can mutually agree on the form of the indemnity;

(c)

reducing the Purchase Price by the Title Defect Value, subject to the Title Defect Threshold and Title Defect Deductible described in Section 6.12, in which event Seller shall be released from and of all further liability or obligation to Buyer with respect to the Title Defect, and the Title Defect shall be a Permitted Encumbrance; or

(d)

if the Title Defect Value exceeds twenty percent (20%) of the Allocated Value of the Well or Well Location, excluding the Well or Well Location from the Purchased Assets conveyed to Buyer at the Closing, subject to Section 6.13, in which event the Purchase Price shall be reduced by the Allocated Value of the Well or Well Location, as applicable.

6.12

Adjustment to Purchase Price; Threshold and Deductible.  At Closing, the Purchase Price may be adjusted for Title Defect Values as set forth in Section 6.11(c); provided, however, notwithstanding anything to the contrary herein, there shall be no cure, remedy, deletion or adjustment to the Purchase Price whatsoever in respect of any Title Defects unless the aggregate value of all Title Defects equals or exceeds one percent (1%) of the Purchase Price (the “Title Defect Threshold Amount”). Once the Title Defect Threshold Amount has been reached, the amount of reduction in Purchase Price shall be the amount of Title Defect Values that exceed one-half of one percent (0.5%) of the Purchase Price (the “Title Defect Deductible”).  For avoidance of doubt, there shall be no adjustment to the Purchase Price for Title Defects cured or remedied in accordance with Section 6.11(a) or < U>6.11(b) and the Title Defect Threshold Amount and the Title Defect Deductible Amount shall not apply to any Title Defect arising by, through or under Seller.

6.13

Exclusions of Wells.  Pursuant to Section 6.11(d), if the Title Defect Value exceeds twenty percent (20%) of the Allocated Value of a Well or Well Location, Seller shall have the option to exclude such Well or Well Location from the Purchased Assets conveyed to Buyer at the Closing by notifying Buyer on or before the Closing, in which event the Purchase Price shall be reduced by the Allocated Value of such Well or Well Location. If the Title Defect Value exceeds twenty percent (20%) of the Allocated Value of the Well or Well Location and the Well or Well Location is excluded from the Purchased Assets conveyed to Buyer at the Closing, Seller may elect any one or more of the following:

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(a)

if Seller cures the Title Defect to Buyer’s reasonable satisfaction before the date that is one hundred eighty (180) days after the Effective Time, Seller may convey the Well or Well Location affected by the Title Defect to Buyer on the date that is one hundred eighty (180) days after the Effective Time, subject to all of the terms and conditions of this Agreement, and Buyer shall pay to Seller the amount by which the Purchase Price was reduced with respect to the Well Location; or

(b)

if Seller does not cure the Title Defect to Buyer’s reasonable satisfaction before the date that is one hundred eighty (180) days after the Effective Time but agrees to indemnify Buyer from all liabilities and obligations arising out of the Title Defect (which indemnity shall terminate if Seller later cures the Title Defect), Seller may convey the Well or Well Location affected by the Title Defect to Buyer on the date that is one hundred eighty (180) days after the Effective Time, subject to all of the terms and conditions of this Agreement, in which event Buyer shall pay to Seller the amount by which the Purchase Price was reduced with respect to the Well or Well Location, and Seller shall be released from all further liability or obligation to Buyer with respect to the Title Defect, and, subject to the indemnity provided above in this paragraph, the Title Defect shall be a Permitted Encumbrance.

6.14

Preference Rights and Transfer Requirements.  (a) The transactions contemplated by this Agreement are expressly subject to all validly existing and applicable Preference Rights and Transfer Requirements.  Prior to the Closing Date, Seller shall initiate all procedures which are reasonably required to comply with or obtain the waiver of all Preference Rights and Transfer Requirements with respect to the transactions contemplated by this Agreement. Seller shall use its Reasonable Best Efforts to obtain all applicable consents and to obtain waivers of applicable Preference Rights; provided, however, Seller shall not be obligated to pay any consideration to (or incur any cost or expense for the benefit of) the holder of any Preference Right or Transfer Requirement in order to obtain the waiver thereof or compliance therewith.

(b)

If the holder of a Preference Right elects prior to Closing to purchase the Purchased Asset subject to a Preference Right (a “Preference Property”) in accordance with the terms of such Preference Right, and Seller receives written notice of such election prior to the Closing, such Preference Property will be eliminated from the Purchased Assets and the Purchase Price shall be reduced by the Allocated Value of the Preference Property.

(c)

If

(i)

a third party brings any suit, action or other proceeding prior to the Closing seeking to restrain, enjoin or otherwise prohibit the consummation of the transactions contemplated hereby in connection with a claim to enforce a Preference Right;

(ii)

a Purchased Asset is subject to a Transfer Requirement that provides that transfer of such Purchased Asset without compliance with such Transfer Requirement will result in termination or other material impairment of any rights in relation to such Purchased Asset, and such Transfer Requirement is not waived, complied with or otherwise satisfied prior to the Closing Date; or

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(iii)

the holder of a Preference Right does not elect to purchase such Preference Property or waive such Preference Right with respect to the transactions contemplated by this Agreement prior to the Closing Date and the time in which the Preference Right may be exercised has not expired;

then, unless otherwise agreed by Seller and Buyer, the Purchased Asset or portion thereof affected by such Preference Right or Transfer Requirement (a “Retained Asset”) shall be held back from the Purchased Assets to be transferred and conveyed to Buyer at Closing and the Purchase Price to be paid at Closing shall be reduced by the Allocated Value of such Retained Asset without application of the Title Defect Threshold Amount or the Title Defect Deductible Amount. Any Retained Asset so held back at the initial Closing will be conveyed to Buyer at a delayed Closing (which shall become the new Closing Date with respect to such Retained Asset), within ten (10) days following the date on which the suit, action or other proceeding, if any, referenced in clause (i) above is settled or a judgment is rendered (and no longer subject to appeal) permitting transfer of the Retained Asset to Buyer pursuant to this Agreement and Seller obtains , complies with, obtains a waiver of or notice of election not to exercise or otherwise satisfies all remaining Preference Rights and Transfer Requirements with respect to such Retained Asset as contemplated by this Section (or if multiple Purchased Assets are Retained Assets, on a date mutually agreed to by the Parties in order to consolidate, to the extent reasonably possible, the number of Closings). At the delayed Closing, Buyer shall pay Seller a purchase price equal to the amount by which the Purchase Price was reduced on account of the holding back of such Retained Asset (as adjusted pursuant to Section 1.7 through the new Closing Date therefor); provided, however, if all such Preference Rights and Transfer Requirements with respect to any Retained Asset so held back at the initial Closing are not obtained, complied with, waived or otherwise satisfied as contemplated by this Section within one hundred eighty (180) days after the initial Closing has occurred with respect to any Purchased Asset, then such Retained Asset shall be eliminated from the Purchased Assets and shall become an Excluded Asset, unless Seller and Buyer agree to proceed with a closing on such Retained Asset, in which case Buyer shall be deemed to have waived any objection (and shall be obligated to indemnify the Seller Indemnitees for all Losses) with respect to non-compliance with such Preference Rights and Transfer Requirements with respect to such Retained Asset(s).

ARTICLE VII

CONDITIONS TO CLOSING

7.1

Conditions to Each Party’s Obligations.  The respective obligations of each Party to consummate the Closing are subject to (a) all applicable waiting periods (and any extensions thereof), if any, under the Hart-Scott-Rodino Act having expired or otherwise been terminated and (b) no Party exercises its right to terminate due to reductions in the Purchase Price pursuant to Section 1.8.

7.2

Conditions to Obligations of Buyer.  Each and every obligation of Buyer under this Agreement (except for the obligations of Buyer to be fulfilled prior to the Closing and obligations that survive termination of this Agreement), including the obligation of Buyer to consummate the

27

Closing, shall be subject to the satisfaction, on or before the Closing, of each of the conditions set forth in this Section 7.2, unless waived in writing by Buyer.

(a)

Seller shall have obtained at its own expense (and shall have provided copies thereof to Buyer) all of the waivers, permits, consents, approvals or other authorizations, and effected all of the registrations, filings and notices, as contemplated by Section 5.2, with respect to Governmental Entities, which are required on the part of Seller, except for (i) any waivers, permits, consents, approvals, licenses or other authorizations which may be delivered or issued subsequent to the Closing Date pursuant to applicable law, rule or regulation relating to such waiver, permit, consent, approval, license or other authorization; and (ii) any failure to provide the appropriate notice or obtain the appropriate permit, authorization, consent or approval, or where any such conflict, breach, default, acceleration, termination, modification or cancellation, or any such imposition of any Security Interest, has not had or would not reasonably be expected to have, individually or in the aggregate, a Seller Material Adverse Effect or a material adverse effect on the ability of the Parties to consummate the transactions contemplated by this Agreement.

(b)

The representations and warranties of Seller set forth in this Agreement that are qualified as to materiality shall be true and correct and the representations and warranties of Seller that are not qualified as to materiality shall be true and correct in all material respects, in each case, as of the Closing as though made as of the Closing, provided that, to the extent that any such representation or warranty speaks as of a specified date, it need only be true and correct as of such specified date.

(c)

Seller shall have performed or complied with in all material respects their agreements and covenants required to be performed or complied with under this Agreement as of or prior to the Closing.

(d)

No Legal Proceeding shall be pending wherein an unfavorable judgment, order, decree, stipulation or injunction would (i) prevent consummation of the transactions contemplated by this Agreement, or (ii) cause the transactions contemplated by this Agreement to be rescinded following consummation.

(e)

Seller shall have delivered to Buyer the Seller Certificate.

(f)

Buyer shall have received such other certificates and instruments (including a certificate of good standing of Seller in its jurisdiction of incorporation, certified charter documents, certificates as to the incumbency of officers and the adoption of authorizing resolutions) as it shall reasonably request in connection with the Closing.

7.3

Conditions to Obligations of Seller.  Each and every obligation of Seller under this Agreement (except for the obligations of Seller to be fulfilled prior to the Closing and obligations that survive termination of this Agreement), including the obligation of Seller to consummate the Closing, shall be subject to the satisfaction, on or before the Closing, of each of the conditions set forth in this Section 7.3, unless waived in writing by Seller.

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(a)

Buyer shall have obtained at its own expense (and shall have provided copies thereof to Seller) all of the waivers, permits, consents, approvals or other authorizations, and effected all of the registrations, filings and notices, as contemplated by Section 5.2, with respect to Governmental Entities, which are required on the part of Buyer, except for (i) any waivers, permits, consents, approvals, licenses or other authorizations which may be delivered or issued subsequent to the Closing Date pursuant to applicable law, rule or regulation relating to such waiver, permit, consent, approval, license or other authorization; and (ii) any failure to provide the appropriate notice or obtain the appropriate permit, authorization, consent or approval, or where any such conflict, breach, default, acceleration, termination, modification or cancellation, or any such imposition of any Security Interest, has n ot had or would not reasonably be expected to have, individually or in the aggregate, a Buyer Material Adverse Effect or a material adverse effect on the ability of the Parties to consummate the transactions contemplated by this Agreement.

(b)

The representations and warranties of Buyer set forth in this Agreement that are qualified as to materiality shall be true and correct and the representations and warranties of Buyer that are not qualified as to materiality shall be true and correct in all material respects, in each case, as of the Closing as though made as of the Closing, provided that, to the extent that any such representation or warranty speaks as of a specified date.

(c)

Buyer shall have performed or complied with in all material respects its agreements and covenants required to be performed or complied with under this Agreement as of or prior to the Closing.

(d)

No Legal Proceeding shall be pending or threatened wherein an unfavorable judgment, order, decree, stipulation or injunction would (i) prevent consummation of the transactions contemplated by this Agreement, or (ii) cause the transactions contemplated by this Agreement to be rescinded following consummation.

(e)

Buyer shall have delivered to Seller the Buyer Certificate.

(f)

Seller shall have received such other certificates and instruments (including certificates of good standing of Buyer in its jurisdiction of organization, certified charter documents, certificates as to the incumbency of officers and the adoption of authorizing resolutions) as they shall reasonably request in connection with the Closing.

(g)

Buyer is ready to deliver the Closing Date Aggregate Purchase Price by wire transfer to Seller in immediately available funds.

ARTICLE VIII

INDEMNIFICATION

8.1

Indemnification by Seller.  Subject to the limitations set forth in Section 8.5, and provided that Buyer makes a written claim for indemnification against Seller pursuant to Section 8.3, to the extent applicable, and Section 11.7, within the survival period (if there is an applicable

29

survival period pursuant to Section 8.4, below), then Seller shall be obligated to indemnify Buyer, Buyer’s permitted assigns and Affiliates and their respective partners, directors, members, shareholders, officers, employees and agents (collectively, “Buyer Indemnitees”) from and against the entirety of any Damages the Buyer Indemnitees may suffer resulting from, arising out of, relating to, in the nature of, or caused by the following:

(a)

any breach by Seller of any of its representations, warranties and covenants contained in this Agreement and the Seller Related Documents;

(b)

any Title Defects subject to Section 6.11(c);

(c)

any Excluded Liabilities; or

(d)

the litigation set forth on Schedule 3.8.

8.2

Indemnification by Buyer.  Subject to the limitations set forth in Section 8.5, and provided that a Seller makes a written claim for indemnification against Buyer pursuant to Section 8.3, to the extent applicable, and Section 11.8, within the survival period (if there is an applicable survival period pursuant to Section 8.4, below), then Buyer shall indemnify Seller, Seller’s permitted assigns and Affiliates and their respective partners, directors, members, shareholders, officers, employees and agents (the “Seller Indemnitees”) from and against the entirety of any Damages the Seller Indemnitees may suffer resulting from, arising out of, relating to, in the nature of, or caused by the following:

(a)

any breach by Buyer of its representations, warranties, and covenants contained in this Agreement and the Buyer Related Documents;

(b)

non-compliance with any bulk-sale statutes; or

(c)

any Assumed Liability.

8.3

Indemnification Claims.  

(a)

(i)

If any third party notifies any Indemnified Party with respect to any matter (a “Third Party Claim “) that may give rise to a claim for indemnification against an Indemnifying Party under Article VIII, then the Indemnified Party shall promptly give written notification to the Indemnifying Party thereof. Such notification shall be given within ten (10) days after receipt by the Indemnified Party of notice of such Third Party Claim, and shall describe in reasonable detail (to the extent known by the Indemnified Party) the facts constituting the basis for such Third Party Claim and the amount of the claimed damages (if available); provided, however, that no delay or failure on the part of the Indemnified Party in so notifying the Indemnifying Party shall relieve the Indemnifying Party of any liability or obligation hereunder except to the extent of any damage or liability caused by or aris ing out of such failure.

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(ii)

The Indemnifying Party may, upon written notice thereof to the Indemnified Party, assume control of the defense of such Third Party Claim with counsel reasonably satisfactory to the Indemnified Party; provided that (i) the Indemnifying Party notifies the Indemnified Party in writing within thirty (30) days after the Indemnified Party has given notice of the Third Party Claim that the Indemnifying Party will indemnify the Indemnified Party from and against the Damages the Indemnified Party may suffer resulting from, arising out of, relating to, in the nature of, or caused by the Third Party Claim (subject to the provisions of this Article VIII); (ii) the ad damnum, if any, is less than or equal to the amount of Damages for which the Indemnifying Party is liable under this Article VIII; (iii) the Indemnifying Party provides the Indemnified Party with evidence acceptable to the Indemnified Party that the I ndemnifying Party will have the financial resources to defend against the Third Party Claim and fulfill its indemnification obligations hereunder; (iv) the Third Party Claim does not involve criminal liability and seeks only money damages and not equitable relief against the Indemnified Party; (v) settlement of, or an adverse judgment with respect to, the Third Party Claim is not, in the good faith judgment of the Indemnified Party, likely to establish a precedential custom or practice adverse to the continuing business interests or the reputation of the Indemnified Party, and (vi) the Indemnifying Party conducts the defense of the Third Party Claim actively and diligently.

(iii)

If the Indemnifying Party does not, or is not permitted under the terms hereof to, so assume control of the defense of a Third Party Claim, the Indemnified Party shall control such defense.

(iv)

The Non-controlling Party may participate in such defense at its own expense. The Controlling Party shall keep the Non-controlling Party advised of the status of such Third Party Claim and the defense thereof and shall consider in good faith recommendations made by the Non-controlling Party with respect thereto. The Non-controlling Party shall furnish the Controlling Party with such information as it may have with respect to such Third Party Claim (including copies of any summons, complaint or other pleading which may have been served on such party and any written claim, demand, invoice, billing or other document evidencing or asserting the same) and shall otherwise cooperate with and assist the Controlling Party in the defense of such Third Party Claim. The reasonable fees and expenses of counsel to the Indemnified Party with respect to a Third Party Claim shall be considered Damages for purposes of th is Agreement if (x) the Indemnified Party controls the defense of such Third Party Claim pursuant to the terms of this Section 8.3(a) or (y) the Indemnifying Party assumes control of such defense and the Indemnified Party reasonably concludes that the Indemnifying Party and the Indemnified Party have conflicting interests or different defenses available with respect to such Third Party Claim.

(v)

The Indemnifying Party shall not agree to any settlement of, or the entry of any judgment arising from, any Third Party Claim without the prior written consent of the Indemnified Party, which shall not be unreasonably withheld or delayed; provided that the consent of the Indemnified Party shall not be required if the Indemnifying Party agrees in writing to pay any amounts payable pursuant to such settlement or judgment and such settlement or judgment includes a complete release of the Indemnified Party from further

31

liability and has no other adverse effect on the Indemnified Party. The Indemnified Party shall not agree to any settlement of, or the entry of any judgment arising from, any such Third Party Claim without the prior written consent of the Indemnifying Party, which shall not be unreasonably withheld or delayed.

(b)

Within twenty (20) days after delivery of the notification of a Third Party Claim as provided in Section 8.3(a)(i) (a “Claim Notice”), the Indemnifying Party shall deliver to the Indemnified Party a response, in which the Indemnifying Party shall: (i) agree that the Indemnified Party is entitled to receive all of the Claimed Amount (in which case the Response shall be accompanied by a payment by the Indemnifying Party to the Indemnified Party of the Claimed Amount to the extent the Claimed Amount may be finally determined at that time, by check or by wire transfer (provided that to the extent the Claimed Amount may not be finally determined at that time, the Indemnifying Party shall pay the Indemnified Party such additional amounts as to constitute the full Claimed Amount at such time as the full Claimed Amount can be finally determined)), (ii) agree that the Indemnified Party is entitled to receive the A greed Amount (in which case the Response shall be accompanied by a payment by the Indemnifying Party to the Indemnified Party of the Agreed Amount, by check or by wire transfer), or (iii) dispute that the Indemnified Party is entitled to receive any of the Claimed Amount.

(c)

During the thirty (30) day period following the delivery of a Response that reflects a Dispute, the Indemnifying Party and the Indemnified Party shall use good faith efforts to resolve the Dispute. If the Dispute is not resolved within such thirty (30)-day period, the Indemnifying Party and the Indemnified Party shall discuss in good faith the submission of the Dispute to binding arbitration, and if the Indemnifying Party and the Indemnified Party agree in writing to submit the Dispute to such arbitration, then the provisions of Section 8.3(d) shall become effective with respect to such Dispute. The provisions of this Section 8.3(c) shall not obligate the Indemnifying Party and the Indemnified Party to submit to arbitration or any other alternative dispute resolution procedure with respect to any Dispute, and in the absence of an agreement by the Indemnifying Party and the Indemnified Party to arbitrate a Di spute, such Dispute shall be resolved in a state or federal court sitting in Houston, Texas, in accordance with Section 11.11.

(d)

If, as set forth in Section 8.3(c), the Indemnified Party and the Indemnifying Party agree to submit any Dispute to binding arbitration, the arbitration shall be conducted by a single arbitrator (the “Arbitrator”) in accordance with the Commercial Rules in effect from time to time and the following provisions:

(i)

In the event of any conflict between the Commercial Rules in effect from time to time and the provisions of this Agreement, the provisions of this Agreement shall prevail and be controlling.

(ii)

The parties shall commence the arbitration by jointly filing a written submission with the Houston, Texas office of the AAA in accordance with Commercial Rule 5 (or any successor provision).

(iii)

No depositions or other discovery shall be conducted in connection with the arbitration.

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(iv)

Not later than thirty (30) days after the conclusion of the arbitration hearing, the Arbitrator shall prepare and distribute to the parties a writing setting forth the arbitral award and the Arbitrator’s reasons therefor. Any award rendered by the Arbitrator shall be final, conclusive and binding upon the parties, and judgment thereon may be entered and enforced in any court of competent jurisdiction (subject to Section 11.11), provided that the Arbitrator shall have no power or authority to (x) award damages in excess of the portion of the Claimed Amount that is subject to such Dispute, (y) award multiple, consequential, punitive or exemplary damages, or (z) grant injunctive relief, specific performance or other equitable relief.

(v)

The Arbitrator shall have no power or authority, under the Commercial Rules or otherwise, to (x) modify or disregard any provision of this Agreement, including the provisions of this Section 8.3(d), or (y) address or resolve any issue not submitted by the parties.

(vi)

In connection with any arbitration proceeding pursuant to this Agreement, each party shall bear its own costs and expenses, except that the fees and costs of the AAA and the Arbitrator, the costs and expenses of obtaining the facility where the arbitration hearing is held, and such other costs and expenses as the Arbitrator may determine to be directly related to the conduct of the arbitration and appropriately borne jointly by the parties (which shall not include any party’s attorneys’ fees or costs, witness fees (if any), costs of investigation and similar expenses) shall be shared equally by the Indemnified Party and the Indemnifying Party.

(e)

Notwithstanding the other provisions of this Section 8.3, if a third party asserts (other than by means of a lawsuit) that an Indemnified Party is liable to such third party for a monetary or other obligation which may constitute or result in Damages for which such Indemnified Party may be entitled to indemnification pursuant to this Article VIII, and such Indemnified Party reasonably determines that it has a valid business reason to fulfill such obligation, then (i) such Indemnified Party shall be entitled to satisfy such obligation, without prior notice to or consent from the Indemnifying Party, (ii) such Indemnified Party may subsequently make a claim for indemnification in accordance with the provisions of this Article VIII and (iii) such Indemnified Party shall be reimbursed, in accordance with the provisions of this Article VIII, for any such Damages for which it is ent itled to indemnification pursuant to this Article VIII (subject to the right of the Indemnifying Party to dispute the Indemnified Party’s entitlement to indemnification, or the amount for which it is entitled to indemnification, under the terms of this Article VIII).

8.4

Survival of Representations, Warranties and Covenants.  (a) The representations and warranties made by Seller in this Agreement or any certificate required to be delivered at Closing to Buyer, and the representations and warranties of Buyer in this Agreement or any certificate required to be delivered at Closing to Seller, and the covenants and agreements of Seller and Buyer which by their terms do not contemplate performance after the Closing, shall survive the Closing and remain in full force and effect for one (1) year following the Closing Date. The foregoing notwithstanding, the representations and warranties in Sections 3.1, 3.2 and 3.9 shall survive until

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the expiration of the applicable limitations period and the indemnification set forth in Section 8.1(d) shall survive until the final, non-appealable judgment of a court of competent jurisdiction relating to the litigation set forth on Schedule 3.8.

(b)

The rights to indemnification set forth in this Article VIII shall not be affected by (i) any investigation conducted by or on behalf of an Indemnified Party or any knowledge acquired (or capable of being acquired) by an Indemnified Party, whether before or after the Closing Date, with respect to the inaccuracy or noncompliance with any representation, warranty, covenant or obligation which is the subject of indemnification hereunder or (ii) any waiver by an Indemnified Party of any closing condition relating to the accuracy of representations and warranties or the performance of or compliance with agreements and covenants.

8.5

Limitations.  (a) Seller shall not have any obligation to indemnify the Buyer Indemnitees from and against any Damages under Section 8.1(a), other than Damages resulting by reason of any fraud or intentional misrepresentation, until the Buyer Indemnitees have suffered Damages by reason of all such breaches in excess of one percent (1%) of the Purchase Price (after which point Seller will be obligated to indemnify the Buyer Indemnitees from and against all such Damages in excess of the first one percent (1%) of the Purchase Price) and such indemnification obligation shall not exceed five percent (5%) of the Purchase Price except in the case of fraud or intentional misrepresentation; provided, however, that the foregoing thresholds, deductibles and limitations shall not apply to any indemnification provided by Seller arising out of any Title Defects subject to Section 6.11(c) or Section 6.13(b)< /U> or the representations and warranties in Sections 3.1, 3.2 and 3.9.

(b)

Buyer shall not have any obligation to indemnify the Seller Indemnitees from and against Damages under Section 8.2(a), other than Damages resulting by reason of any fraud or intentional misrepresentation, until the Seller Indemnitees have suffered Damages by reason of all such breaches in excess of one percent (1%) of the Purchase Price (after which point Buyer will be obligated to indemnify the Seller Indemnitees from and against all such Damages in excess of the first one percent (1%) of the Purchase Price) and such indemnification obligation shall not exceed five percent (5%) of the Purchase Price except in the case of fraud or intentional misrepresentation.

(c)

The rights of the Indemnified Parties under this Article VIII shall be the exclusive remedy of the Indemnified Parties with respect to any and all matters arising out of, relating to, or connected with this Agreement, Seller and its assets and liabilities, including, without limitation, the Purchased Assets and the Assumed Liabilities; provided, however, that notwithstanding any other provision of this Agreement, nothing herein shall limit any claim of any Party for remedies at law or in equity for fraud or intentional misrepresentations.

(d)

The amount of Damages recoverable by an Indemnified Party under this Article VIII shall be reduced by any proceeds received by such Indemnified Party or an Affiliate, with respect to the Damages to which such indemnity claim relates, from an insurance carrier or any third party. Each Indemnified Party shall use its Reasonable Best Efforts to seek payment or reimbursement for any Damages from its insurance carrier or other collateral sources. In the event that an Indemnified Party shall receive funds from any insurance carrier or collateral source with respect to any Damages, any such amounts so received shall be payable to the Indemnifying Party, regardless of

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when received by the Indemnified Party, up to such amount previously paid by the Indemnifying Party or their Affiliates with respect to such Damages.

(e)

Notwithstanding anything to the contrary contained in this Agreement, following a determination that the Indemnifying Party is obligated to indemnify the Indemnified Party pursuant to Sections 8.1(a) or 8.2(a), and subject to the deductible amounts set forth in Sections 8.5(a) or 8.5(b), and solely for purposes of determining the amount of any Damages that are the subject matter of a claim for indemnification hereunder, each representation and warranty in this Agreement and each certificate or document delivered pursuant hereto shall be read without regard and without giving effect to the term(s) “material” or “Material Adverse Effect” in each instance where the effect of including such term(s) would be to make such representation and warranty less restrictive (as if such words and surrounding related words (e.g., “reasonably be expected to,” “could have” and similar restrictions and qualifiers) were deleted from such representations and warranty).

8.6

Treatment of Indemnification Payments.  The Parties hereto agree to treat all indemnification payments made pursuant to this Article VIII (including, without limitation, payments pursuant to Sections 8.1 and 8.2) as adjustments to the Purchase Price for all income Tax purposes and to take no position contrary thereto in any Tax Return or audit or examination by, or proceeding before, any taxing authority, except as required by a change in law or a “determination” as defined in Section 1313 of the Code and the Treasury Regulations thereunder.

ARTICLE IX

TERMINATION

9.1

Termination.  (a) This Agreement may be terminated and the transactions contemplated hereby abandoned at any time prior to the Closing:

(i)

by mutual written consent of Buyer and Seller;

(ii)

by Buyer or Seller if a court of competent jurisdiction or other Governmental Entity shall have issued a nonappealable final order, decree or ruling or taken any other action, in each case having the effect of permanently restraining, enjoining or otherwise prohibiting the Closing, unless the Party relying on such order, decree or ruling or other action has not complied in all material respects with its obligations under this Agreement;

(iii)

by Buyer if:

(A)

the Closing shall not have occurred on or before June 30, 2008 by reason of the failure of any condition precedent under Section 7.1 or Section 7.2 (unless the failure results primarily from a breach by Buyer of any representation, warranty or covenant contained in this Agreement); or

(B)

Seller is in breach of any representation, warranty or covenant contained in this Agreement, and such breach would reasonably be expected to

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result in aggregated Damages to the Buyer in excess of ten percent (10%) of the Purchase Price.

(iv)

by Seller if:

(A)

the Closing shall not have occurred on or before June 30, 2008 by reason of the failure of any condition precedent under Section 7.1 or Section 7.3 (unless the failure results primarily from a breach by Seller of any representation, warranty or covenant contained in this Agreement); or

(B)

Buyer is in breach of any representation, warranty or covenant contained in this Agreement, and such breach would reasonably be expected to result in aggregated Damages to Seller in excess of ten percent (10%) of the Purchase Price.

(b)

The Party desiring to terminate this Agreement pursuant to Section 9.1(a) shall give written notice of such termination to the other Party prior to the Closing Date.

9.2

Effect of Termination.  In the event of termination of this Agreement as provided in Section 9.1, this Agreement shall immediately become void and there shall be no liability or obligation on the part of Seller or Buyer or their respective officers, directors, stockholders or Affiliates, except as set forth in Section 9.3; provided, however, that the provisions of Section 5.4, Section 9.3 and Article XI of this Agreement shall remain in full force and effect and survive any termination of this Agreement.

9.3

Remedies.  Any party terminating this Agreement pursuant to Section 9.1 shall have the right to recover damages sustained by such party as a result of any breach by the other party of any representation, warranty, covenant or agreement contained in this Agreement or fraud or willful misrepresentation; provided, however, that the party seeking relief is not in breach of any representation, warranty, covenant or agreement contained in this Agreement under circumstances which would have permitted the other party to terminate the Agreement under Section 9.1.

ARTICLE X

DEFINITIONS

For purposes of this Agreement, each of the following terms shall have the meaning set forth below.

“AAA” shall mean the American Arbitration Association.

“Affiliate” shall mean any affiliate, as defined in Rule 12b-2 under the Securities Exchange Act of 1934, as amended.

“Agreed Amount” shall mean part, but not all, of the Claimed Amount.

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“Agreement” shall have the meaning ascribed to it in the first paragraph of this Agreement.

“Allocated Value” or “Allocated Values” shall have the meaning ascribed to it in Section 1.6 hereof.

“Arbitrator” shall have the meaning ascribed to it in Section 8.3(d) hereof.

“Assessment” shall have the meaning ascribed to it in Section 5.7(b) hereof.

“Assigned Contract” or “Assigned Contracts” shall have the meaning ascribed to it in Section 1.1(h) hereof.

“Assignment and Bill of Sale” shall have the meaning ascribed to it in Section 2.2(a) hereof.

“Assumed Liabilities” means (a) all Liabilities of Seller under or associated with or appurtenant to the Assigned Contracts, the Leases and the other arrangements included in the Purchased Assets, including, without limitation, all product liability, warranty, guarantee and similar claims for damages or injury to person or property, arising or based upon any events occurring or actions taken or omitted to be taken after the Effective Time, (b) all Liabilities under, associated with or appurtenant to the Purchased Assets with respect to Environmental, Health or Safety Matters whether arising on or before the Effective Time, (c) all Liabilities arising out of Buyer’s operations and/or ownership of the Purchased Assets from and after the Effective Time, (d) all Liabilities of Seller for transfer, sales, use and other non-income Taxes arising in connection with the consummation of the transactions contemplated hereby, and (e) all Assumed Title Liabilities.

“Assumed Title Liabilities” shall have the meaning ascribed to it in Section 6.9 hereof.

“Buyer” shall have the meaning ascribed to it in the first paragraph of this Agreement.

“Buyer Certificate” shall mean a certificate of an officer of Buyer to the effect that each of the conditions specified in Section 7.3(a) through (d) (insofar as clause (d) relates to Legal Proceedings involving Buyer) of Section 7.3 is satisfied in all respects or deemed waived as provided in Section 7.3.

“Buyer Indemnitees” shall have the meaning ascribed to it in Section 8.1 hereof.

 “Buyer Material Adverse Effect” shall mean any material adverse change, event, circumstance or development that is reasonably likely to impair materially Buyer’s ability to perform its obligations under this Agreement. For the avoidance of doubt, the Parties agree that the terms “material”, “materially” or “materiality” as used in this Agreement with an initial lower case “m” shall have their respective customary and ordinary meanings, without regard to the meaning ascribed to Buyer Material Adverse Effect.

“Buyer Related Documents” shall have the meaning ascribed to it in Section 4.2(b) hereof.

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“Claim Notice” shall have the meaning ascribed to it in Section 8.3(b) hereof.

“Claimed Amount” shall mean the amount of any Damages incurred or reasonably expected to be incurred by the Indemnified Party.

“Closing” shall mean the closing of the transactions contemplated by this Agreement.

“Closing Date” shall have the meaning ascribed to it in Section 2.1 hereof.

“Closing Date Aggregate Purchase Price” shall have the meaning ascribed to it in Section 1.9 hereof.

“Closing Date Estimated Purchase Price Adjustment” shall have the meaning ascribed to it in Section 1.9 hereof.

“Code” shall mean the Internal Revenue Code of 1986, as amended, and any successor law.

“Commercial Rules” shall mean the Commercial Arbitration Rules of the AAA.

“Confidentiality Agreement” shall have the meaning ascribed to it in Section 5.7 hereof.

“Controlling Party” shall mean the party controlling the defense of any Third Party Claim.

“Damages” shall mean all actions, suits, proceedings, hearings, investigations, charges, complaints, claims, demands, injunctions, judgments, orders, decrees, rulings, damages, dues, penalties, fines, costs, amounts paid in settlement, Liabilities, obligations, Taxes, liens, losses, expenses, and fees, including court costs and reasonable legal fees and expenses.

“Defensible Title” shall have the meaning ascribed to it in Section 6.2 hereof.

“Development Acreage” shall have the meaning ascribed to it in Section 6.3 hereof.

“DGC” shall mean DeSoto Gathering Company, LLC.

“Dispute” shall mean the dispute resulting if the Indemnifying Party in a Response disputes its liability for all or part of the Claimed Amount.

“Effective Time” means 12:01 a.m. Central time on March 1, 2008.

“Environmental Laws” means, as the same may have been amended, any federal, state or local statute, law, regulation, ordinance, rule, order or decree including any rule of common law, relating to (i) the control of any potential pollutant or protection of the environment, including air, water or land, (ii) the generation, handling, treatment, storage, disposal or transportation of waste materials, or (iii) the regulation of or exposure to hazardous, toxic or other substances alleged to be harmful, including, but not limited to, the Comprehensive Environmental Response, Compensation and Liability Act, 42 U.S.C. § 9601 et seq. (“CERCLA”); the Resource Conservation and Recovery

38

Act, 42 U.S.C. § 6901 et seq. (“RCRA”); the Federal Water Pollution Control Act, 33 U.S.C. § 1251 et seq.; the Clean Air Act, 42 U.S.C. § 7401 et seq. the Hazardous Materials Transportation Act, 49 U.S.C. § 1471 et seq.; the Toxic Substances Control Act, 15 U.S.C. §§ 2601 through 2629; the Oil Pollution Act, 33 U.S.C. § 2701 et seq.; the Emergency Planning and Community Right-to-Know Act, 42 U.S.C. § 11001 et seq.; the Safe Drinking Water Act, 42 U.S.C. §§ 300f through 300j; the Federal Insecticide, Fungicide and Rodenticide Act, 7 U.S.C. § 136 et seq.; the Occupational Safety and Health Act, 29 U.S.C. § 651 et seq.; the Atomic Energy Act, 42 U.S.C. § 2011 et seq. ; and all applicable related law, whether local, state, territorial, or national, of any Governmental Entity having jurisdiction over the property in question addressing pollution or protection of human he alth, safety, natural resources or the environment and all regulations implementing the foregoing. The term “Environmental Laws” includes all judicial and administrative decisions, orders, directives, and decrees issued by a Governmental Entity pursuant to the foregoing.

“Environmental Matters” means any and all claims, demands, suits, causes of action, investigations, administrative proceedings, or other legal proceedings, losses, damages, liabilities, judgments, assessments, settlements, fines, notices of violation, penalties, interest, obligations and costs (including attorneys’ fees and costs of litigation) of any kind or character for pollution or environmental damages of any kind, including without limitation, those relating to breach of Environmental Laws, common law causes of action such as negligence, gross negligence, strict liability, nuisance or trespass, or fault imposed by statute, rule, regulation or otherwise, and including all costs associated with remediation and clean up, and fines and penalties associated with any of the foregoing.

“Equipment” shall have the meaning ascribed to it in Section 1.1(f) hereof.

“Excluded Assets” shall have the meaning ascribed to it in Section 1.2 hereof.

“Excluded Liabilities” shall have the meaning ascribed to it in Section 1.4 hereof.

“Field Services Agreement” means that certain Amended and Restated Dedicated Field Services Agreement dated effective October 1, 2006, by and between DGC and Seller, as amended by that  letter agreement dated effective October 1, 2007, by and between DGC and Seller.

“Final Post-Closing Purchase Price Adjustment Amount” shall have the meaning ascribed to it in Section 1.10(d)(v) hereof.

“Final Post-Closing Purchase Price Adjustment Statement” shall have the meaning ascribed to it in Section 1.10(d)(i) hereof.

“Final Post-Closing True-Up Amount” shall have the meaning ascribed to it in Section 1.10(d)(v)(C) hereof.

“GAAP” shall mean United States generally accepted accounting principles.

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“Gathering System” shall mean (i) that certain natural gas gathering system located on the Subject Lands, including all above-ground facilities or structures, together with all pipe, valves, machinery, equipment, gauges, meters, fixtures, fittings and improvements related thereto save and except a 190 foot communication tower located on a separate 3 acre tract (“the “Tower Tract”) in the East Cutthroat Area (collectively, the “Gathering Facilities”); (ii) all easements, rights-of-way, fee interests, leaseholds and other surface rights held by DGC in connection with the use, ownership and operation of the Gathering Facilities save and except DGC’s interests in the Tower Tract; (iii) to the extent assignable, all permits, licenses, approvals, waivers, authorizations and registrations issued to or held by DGC in connection with DGC's construction, installation, use, ownership or operation of the Gathering Facilities;  (iv) copies of or access to all books and records in possession of DGC and relating to the Gathering System (redacted as necessary to the extent not related to the Gathering System, or to the extent proprietary or privileged), including any and all drawings, as-builts, blueprints, designs, pipeline construction and testing records, pipe certifications and weld x-rays, reports and filings to and with any federal or state regulatory commission or agency, reports, records, logs, data or information of any type related to or involving the construction, installation, use, ownership and operation of all or any portion of the Gathering System; (v) to the extent assignable, the benefit of and right to enforce any and all other rights and benefits, intangible or tangible, pertaining to the Gathering System, including any covenants, warranties, guarantees and suretyship agreements in favor of DGC relating to the Gathering System, and (vi) to the extent assignable, those ce rtain Compression Proposal and Agreements dated July 22, 2005 and October 24, 2005, by and between USA Compression Partners, LP and DGC.

“Governmental Entity” shall mean any court, arbitrational tribunal, administrative agency or commission or other governmental or regulatory authority or agency.

“Hart-Scott-Rodino Act” shall mean the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended.

“Hydrocarbons” means oil, gas and/or other liquid or gaseous hydrocarbons or any combination thereof.

“Imbalance” or “Imbalances” means any over-production, under-production, over-delivery, under-delivery or similar imbalance of Hydrocarbons produced from or allocated to the Purchased Assets, regardless of whether such over-production, under-production, over-delivery under-delivery or similar imbalance arises at the platform, wellhead, pipeline, gathering system, transportation system, processing plant or other location.

“Indemnified Party” shall mean a party entitled, or seeking to assert rights, to indemnification under Article VIII.

“Indemnifying Party” shall mean the party from whom indemnification is sought by the Indemnified Party.

“Independent Accounting Firm” shall have the meaning ascribed to it in Section 1.10(d)(iv) hereof.

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“Initial Post-Closing Estimated Purchase Price Adjustment Amount” shall have the meaning ascribed to it in Section 1.10(c) hereof.

“Initial Post-Closing Purchase Price Adjustment Statement” shall have the meaning ascribed to it in Section 1.10(a) hereof.

“Initial Post-Closing True-Up Amount” shall have the meaning ascribed to it in Section 1.10(c)(iii) hereof.

“Interest Rate” means eight percent (8%) per annum, compounded quarterly, computed on the basis of a three hundred sixty (360) day year for actual days elapsed.

“Knowledge” with respect to a Party, means the current actual knowledge of the executive officers of such Party.

“Lease” or “Leases” shall have the meaning ascribed to it in Section 1.1(a) hereof.

“Legal Proceeding” shall mean any action, suit, proceeding, claim, arbitration or investigation before any Governmental Entity or before any arbitrator.

“Liabilities” means, with respect to any Person, such Person’s liabilities, obligations and commitments.

“Lien” means, with respect to any property or asset, any mortgage, lien, pledge, charge, security interest or other similar encumbrance in respect of such property or asset.

“Losses” means any and all debts, obligations and other liabilities (whether absolute, accrued, contingent, fixed or otherwise, or whether known or unknown, or due or to become due or otherwise), diminution in value, monetary damages, fines, fees, Taxes, penalties, interest obligations, deficiencies, losses and expenses (including amounts paid in settlement, interest, court costs, costs of investigators, reasonable fees and expenses of attorneys, accountants, financial advisors and other experts, and other actual out of pocket expenses incurred in investigating and preparing for or in connection with any Proceeding; however, excluding special, punitive, exemplary, consequential or indirect damages, except to the extent a party is required to pay such damages to a third party in connection with a matter for which such Party is entitled to indemnification under Article VIII).

“Net Mineral Acres”, with respect to the mineral estate in lands covered by a particular Lease, shall mean the product of (a) the percentage mineral interest ownership of the lessor under such Lease and (b) the total number of mineral acres covered by such Lease.

“Net Revenue Interest” mean the percentage share in all oil, gas and other Hydrocarbons produced from a well, lease, unit or other Oil and Gas Interest after satisfaction of applicable lessor royalties, overriding royalties, oil payments and other payments out of or measured by the

41

production of oil, gas and other Hydrocarbons from such well, lease, unit or other Oil and Gas Interest.

“Non-controlling Party” shall mean the party not controlling the defense of any Third Party Claim.

“Objection Date” shall have the meaning ascribed to it in Section 6.8 hereof.

“Oil and Gas Interest(s)” means (a) all interests in and rights with respect to oil, gas, mineral and related properties and assets of any kind and nature, direct or indirect, including working, royalty interests, production payments, operating rights, net profits interests, fee minerals, fee royalties, other non-working interests and non-operating interests; (b) interests in and rights with respect to Hydrocarbons and other minerals or revenues therefrom and contracts in connection therewith and claims and rights thereto (including oil and gas leases, operating agreements, unitization and pooling agreements and orders, division order, transfer orders, mineral deeds, royalty deeds, oil and gas sales, exchange and processing contracts and agreements and, in each case, interests thereunder), surface interests, fee interests, reservations and concessions; (c) easements, rights of way, licenses, permits, leases, and other interests associated with, appurtenant to, or necessary for the operation of any of the foregoing; and (d) interests in equipment and machinery (including well equipment and machinery), oil and gas production, gathering, transmission, compression, treating, processing and storage facilities (including tanks, tank batteries, pipelines and gathering systems), pumps, water plants, electric plants, gasoline and gas processing plants, refineries and other tangible personal property and fixtures associated with, appurtenant to, or necessary for the operation of any of the foregoing, in each case to the extent such interests comprise a part of the Purchased Assets.

“Parties” shall mean Buyer and Seller.

“Permitted Encumbrances” shall have the meaning ascribed to it in Section 6.5 hereof.

“Permitted Liens” means with respect to each Seller (a) liens for current real or personal property taxes not yet due and payable or not yet delinquent or, if delinquent, that are being contested by Seller in good faith in the normal course of business and with respect to which Seller maintains adequate reserves, (b) workers’, carriers’ and mechanics’ or other like liens incurred in the ordinary course of Seller’s business with respect to which payment is not due or not yet delinquent or, if delinquent, that are being contested by Seller in good faith in the normal course of business and that do not impair the present use of the affected property, (c) liens of operators relating to obligations not yet due or not yet delinquent or, if delinquent, that are being contested by Seller in good faith in the normal course of business and (d) liens that are immaterial in character, amount, and extent and which do not detract from the value or interfere with the present or proposed use of the properties they affect.

“Person” means an individual, a corporation, a partnership, a limited liability company, a trust, an unincorporated association, a Governmental Entity or any agency, instrumentality or political subdivision of a Governmental Entity, or any other entity or body.

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“Preference Property” shall have the meaning ascribed to it in Section 6.14(b) hereof.

“Preference Right” means any right or agreement that enables any Person to purchase or acquire any Purchased Asset or any interest therein or portion thereof as a result of or in connection with (i) the sale, assignment or other transfer of any Purchased Asset or any interest therein or portion thereof or (ii) the execution or delivery of this Agreement or the consummation or performance of the terms and conditions contemplated by this Agreement.

“Proceeding” means any proceeding, arbitration, action, suit, pending settlement, or other legal proceeding of any kind or nature before or by any Governmental Entity.

“Purchase Price” shall have the meaning ascribed to it in Section 1.5 hereof.

“Purchase Price Adjustment” shall have the meaning ascribed to it in Section 1.7(b) hereof.

“Purchased Assets” shall have the meaning ascribed to it in Section 1.1 hereof.

“Reasonable Best Efforts” shall mean best efforts, to the extent commercially reasonable.

“Reasonable Documentation” shall have the meaning ascribed to it in Section 6.10 hereof.

“Response” shall mean a written response containing the information provided for in Section 8.3(b).

“Retained Asset” shall have the meaning ascribed to it in Section 6.14(c) hereof.

“Security Interest” shall mean any mortgage, pledge, security interest, encumbrance, charge or other lien (whether arising by contract or by operation of law), other than (a) mechanic’s, materialmen’s, and similar liens arising in the ordinary course of business and securing obligations that are not yet due and payable, (b) liens arising under worker’s compensation, unemployment insurance, social security, retirement, and similar legislation, (c) liens for Taxes and assessments not yet due and payable, (d) liens for Taxes, assessments and other charges, if any, the validity of which is being contested in good faith and (e) minor imperfections of title, none of which is material in amount or materially affects the present use of such assets or properties.

“Seller” shall have the meaning ascribed to it in the first paragraph of this Agreement.

“Seller Certificate” shall mean certificates to the effect that each of the conditions specified in Section 7.2(a) through (d) is satisfied in all respects or is deemed waived as provided in Section 7.2.

“Seller Indemnitees” shall have the meaning ascribed to it in Section 8.2 hereof.

“Seller Material Adverse Effect” shall mean any material adverse change, event, circumstance or development with respect to, or material adverse effect on, (a) the business, assets, liabilities, capitalization, condition of the Purchased Assets (financial or otherwise), or results of

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operations of Seller as such relate to the Purchased Assets, or (b) on the ability of Seller to consummate the Closing and the transactions contemplated by this Agreement in accordance with the terms of this Agreement, excluding any effect of changes resulting from or relating to (i) to the extent that they do not have an ongoing materially disproportionate effect on Seller, conditions in the United States or global economy or financial or capital markets generally, including changes in interest rates, (ii) to the extent that they do not have an ongoing materially disproportionate effect on Seller, changes in conditions (including changes in legal, regulatory or business conditions) in or otherwise affecting the industries or businesses in which Seller operate, (iii) changes in law, GAAP or any authoritative interpretations thereof, (iv) to the extent that they do not have an ongoing materially disproportionate effect on Seller, acts of wa r, armed hostilities, sabotage or terrorism, or any escalation or worsening of any such acts of war, armed hostilities, sabotage or terrorism threatened or underway as of the date of this Agreement, (v) earthquakes, hurricanes, floods, rain, droughts or other natural acts, (vi) any action taken or omitted to be taken by Seller at the written request or with the written consent of Buyer and (vii) any action taken by a Buyer Party. For the avoidance of doubt, the Parties agree that the terms “material”, “materially” or “materiality” as used in this Agreement with an initial lower case “m” shall have their respective customary and ordinary meanings, without regard to the meaning ascribed to Seller Material Adverse Effect.

“Seller Related Documents” shall have the meaning ascribed to it in Section 3.2(b) hereof.

“Seller’s Dispute Notice” shall have the meaning ascribed to it in Section 1.10(d)(ii) hereof.

“Tax Returns” shall mean all forms, reports, returns (including information returns), declarations, statements or other information (including any related or supporting schedules or attachments to any of the foregoing, and any amendments to any of the foregoing) supplied or required to be supplied to any Governmental Entity in connection with Taxes.

“Taxes” shall mean all taxes, charges, fees, levies or other similar assessments or liabilities, including income, capital gains, estimated, gross receipts, ad valorem, premium, value-added, excise, alternative minimum, real property, personal property, sales, use, transfer, escheat, withholding, employment, unemployment, insurance, social security, business license, business organization, environmental, workers compensation, payroll, profits, license, lease, service, service use, capital stock severance, stamp, occupation, windfall profits, customs, duties, franchise, withholding and other taxes imposed by the United States of America or any state, local or foreign government, or any agency thereof, or other political subdivision of the United States or any such government, and any interest, fines, penalties, assessments or additions to tax resulting from, attributable to or incurred in connection with any tax or any contest or dispute thereof.

“Third Party Claim” shall have the meaning ascribed to it in Section 8.3(a)(i) hereof.

“Title Defect” shall have the meaning ascribed to it in Section 6.6 hereof.

“Title Defect Deductible” shall have the meaning ascribed to it in Section 6.12 hereof.

“Title Defect Notice” shall have the meaning ascribed to it in Section 6.8 hereof.

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“Title Defect Threshold Amount” shall have the meaning ascribed to it in Section 6.12 hereof.

“Title Defect Value” shall have the meaning ascribed to it in Section 6.7 hereof.

“Transfer Requirement” means any consent, approval, authorization or permit of, or filing with or notification to, any Person which is required to be obtained, made or complied with for or in connection with any sale, assignment or transfer of any Purchased Asset or any interest therein; provided, however, that “Transfer Requirement” shall not include any consent of, notice to, filing with, or other action by any Governmental Entity in connection with the sale or conveyance of oil and/or gas leases or interests therein or Contracts or interests therein, if they are not required prior to the assignment of such oil and/or gas leases, Contracts or interests or they are customarily obtained subsequent to the sale or conveyance (including consents from state agencies).

“Treasury Regulations” and “Treasury Regulation” means the final and temporary (but not proposed) income tax regulations promulgated under the Code, as such regulations may be amended from time to time.

“Well” or “Wells” shall have the meaning ascribed to it in Section 1.1 hereof.

“Well Location” or “Well Locations” shall mean those drilling locations identified and described on Exhibit D.

“Working Interest” means the percentage of costs and expenses attributable to the maintenance, development and operation of an Oil and Gas Interest.

ARTICLE XI

MISCELLANEOUS

11.1

Press Releases and Announcements. The initial press releases relating to this Agreement shall be press releases the text of which have been agreed to by Buyer and Seller.  Thereafter, neither Buyer nor any of the Seller shall issue any press release or otherwise make any public statements with respect to this Agreement or any of the other transactions contemplated by this Agreement without the prior consent of the other Party (such consent not to be unreasonably withheld or delayed); provided that a Party may, without such consent (but after prior consultation to the extent practicable in the circumstances), issue such press releases and make such public statements that it believes are required by applicable law.  Notwithstanding the foregoing, a Party may make public statements to the press, analysts, investors and make internal announcements to employees, so long as such statements and announcements are consistent with previous press releases or public statements made with the consent of the other Party and do not violate the terms of the Confidentiality Agreement.  Notwithstanding anything contained herein to the contrary the consent requirements of this Section 11.1 shall expire upon the earlier to occur of the Closing or the termination of this Agreement.   

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11.2

No Third Party Beneficiaries.  This Agreement shall not confer any rights or remedies upon any Person or entity other than the Parties and their respective successors and permitted assigns; provided, however, that the provisions of Article VIII concerning indemnification are intended for the benefit of the persons or entities entitled to indemnification thereunder.

11.3

Entire Agreement.  This Agreement (including the documents referred to herein) constitutes the entire agreement among the Parties and supersedes any prior understandings, agreements or representations by or among the Parties, written or oral, with respect to the subject matter hereof; provided that the Confidentiality Agreement shall remain in effect in accordance with its terms.

11.4

Succession and Assignment.  This Agreement shall be binding upon and inure to the benefit of the Parties named herein and their respective successors and permitted assigns. Except with respect to an acquirer of all or substantially all of a Party’s business or assets, no Party may assign any of its rights or delegate any of its performance obligations hereunder without the prior written approval of the other Party; provided, however, Seller approves the assignment of Buyer’s rights (but not the delegation of its performance obligation) to one or more of its wholly-owned subsidiaries. Any purported assignment of rights or delegation of performance obligations in violation of this Section 11.4 is void.

11.5

Counterparts and Facsimile Signature.  This Agreement may be executed in two or more counterparts, each of which shall be deemed an original but all of which together shall constitute one and the same instrument. This Agreement may be executed by facsimile signature.

11.6

Headings. The section headings contained in this Agreement are inserted for convenience only and shall not affect in any way the meaning or interpretation of this Agreement.

11.7

Notices. All notices, requests, demands, claims, waivers and other communications required or permitted under this Agreement will be in writing and will be deemed to have been delivered (a) the next business day when sent overnight by a recognized courier service, (b) upon delivery when personally delivered to the recipient, or (c) when receipt is electronically confirmed, if sent by facsimile; provided, however, that if electronic receipt is confirmed after normal business hours of the recipient, notice shall be deemed to have been given on the next business day. All such notices and communications will be mailed, sent or delivered as set forth below or to such other person(s), facsimile number(s) or address(es) as the applicable recipient may have designated by written notice to the other signatories to this Agreement:

If to Seller:

SEECO, INC.

2350 N. Sam Houston Parkway E., Suite 125

Houston, Texas  77032

Attn:  John C. Gargani

Fax:  281-618-4820

Tel:  281-618-4762

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If to Buyer:

XTO Energy Inc.

810 Houston Street

Fort Worth, Texas 76102

Attn:  Vaughn O. Vennerberg II

Fax:  817- 870-0379

Tel:  818-885-2341

11.8

Governing Law. All matters arising out of or relating to this Agreement and the transactions contemplated hereby (including without limitation its interpretation, construction, performance and enforcement) shall be governed by and construed in accordance with the internal laws of the State of Texas without giving effect to any choice or conflict of law provision or rule (whether of the State of Texas or any other jurisdiction) that would cause the application of laws of any jurisdictions other than those of the State of Texas.

11.9

Amendments and Waivers.  The Parties may mutually amend any provision of this Agreement at any time prior to the Closing. No amendment of any provision of this Agreement shall be valid unless the same shall be in writing and signed by both Parties. No waiver of any right or remedy hereunder shall be valid unless the same shall be in writing and signed by the Party giving such waiver. No waiver by any Party with respect to any default, misrepresentation or breach of warranty or covenant hereunder shall be valid unless the same shall be in writing and signed by the Party making such waiver nor shall such waiver be deemed to extend to any prior or subsequent default, misrepresentation or breach of warranty or covenant hereunder or affect in any way any rights arising by virtue of any prior or subsequent such occurrence.

11.10

Severability. Any term or provision of this Agreement that is invalid or unenforceable in any situation in any jurisdiction shall not affect the validity or enforceability of the remaining terms and provisions hereof or the validity or enforceability of the offending term or provision in any other situation or in any other jurisdiction. If the final judgment of a court of competent jurisdiction declares that any term or provision hereof is invalid or unenforceable, the Parties agree that the court making the determination of invalidity or unenforceability shall have the power to limit the term or provision, to delete specific words or phrases, or to replace any invalid or unenforceable term or provision with a term or provision that is valid and enforceable and that comes closest to expressing the intention of the invalid or unenforceable term or provision, and this Agreement shall be enforceable as so modified.

11.11

Submission to Jurisdiction.  Each Party (a) submits to the jurisdiction of any state or federal court sitting in Houston, Texas in any action or proceeding arising out of or relating to this Agreement (including any action or proceeding for the enforcement of any arbitral award made in connection with any arbitration of a Dispute hereunder), (b) agrees that all claims in respect of such action or proceeding may be heard and determined in any such court, (c) waives any claim of inconvenient forum or other challenge to venue in such court, (d) agrees not to bring any action or proceeding arising out of or relating to this Agreement in any other court and (e) waives any right it may have to a trial by jury with respect to any action or proceeding arising out of or relating to this Agreement; provided in each case that, solely with respect to any arbitration of a Dispute, the Arbitrator shall resolve all threshold issues relating to the validity and applicability of the

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arbitration provisions of this Agreement, contract validity, applicability of statutes of limitations and issue preclusion, and such threshold issues shall not be heard or determined by such court. Each Party agrees to accept service of any summons, complaint or other initial pleading made in the manner provided for the giving of notices in Section 11.7, provided that nothing in this Section 11.11 shall affect the right of any Party to serve such summons, complaint or other initial pleading in any other manner permitted by law.

11.12

Construction.  (a) The language used in this Agreement shall be deemed to be the language chosen by the Parties to express their mutual intent, and no rule of strict construction shall be applied against any Party.

(b)

Any reference to any federal, state, local or foreign statute or law shall be deemed also to refer to all rules and regulations promulgated thereunder, unless the context requires otherwise.

(c)

Any reference herein to “including” shall be interpreted as “including without limitation”.

(d)

Any reference to any Article, Section or paragraph shall be deemed to refer to an Article, Section or paragraph of this Agreement, unless the context clearly indicates otherwise.  All references to Exhibits and Schedules refer to the Exhibits and Schedules attached to this Agreement, unless the context clearly indicates otherwise.  The Exhibits and Schedules which are attached hereto are incorporated herein and made a part of this Agreement for all purposes.

(e)

The Parties have participated jointly in the negotiation and drafting of this Agreement. In the event an ambiguity or question of intent or interpretation arises, this Agreement shall be construed as if drafted jointly by the Parties and no presumption or burden of proof shall arise favoring or disfavoring any Party by virtue of the authorship of any of the provisions of this Agreement.

(REMAINDER OF PAGE INTENTIONALLY LEFT BLANK)

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IN WITNESS WHEREOF, the Parties have executed this Agreement as of the date first above written.

SEECO, INC.

By:      /s/ RICHARD F. LANE            

          Richard. F. Lane, President

XTO ENERGY INC.

By:      /s/ VAUGHN O. VENNERBERG II            

          Vaughn O. Vennerberg II

          Sr. Executive Vice President &

          Chief of Staff

Signature Page to Asset Purchase Agreement

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EX-31

Exhibit 31.1

CERTIFICATION

I, Harold M. Korell, certify that:
	1. I have reviewed this quarterly report on Form 10-Q of Southwestern Energy Company;
	2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
	3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
	4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) 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 internal 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 the registrant's board of directors (or persons performing the equivalent functions):
		(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
		(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.
Date:	April 28, 2008		/s/ HAROLD M. KORELL
				Harold M. Korell
				Chief Executive Officer

EX-31

Exhibit 31.2

CERTIFICATION

I, Greg D. Kerley, certify that:
	1. I have reviewed this quarterly report on Form 10-Q of Southwestern Energy Company;
	2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
	3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
	4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) 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 internal 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 the registrant's board of directors (or persons performing the equivalent functions):
		(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
		(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.
Date:	April 28, 2008		/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, a Delaware corporation (the "Company"), does hereby certify that:

          The Quarterly Report on Form 10-Q for the quarter ended March 31, 2008 (the "Form 10-Q") of the Company fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934 and information contained in the Form 10-Q fairly presents, in all material respects, the financial condition and results of operations of the Company.

Dated:      April 28, 2008	/s/ HAROLD M. KORELL
	Harold M. Korell
	Chief Executive Officer
Dated:      April 28, 2008	/s/ GREG D. KERLEY
	Greg D. Kerley
	Chief Financial Officer