10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

x QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934.

For the quarterly period ended June 30, 2008

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934.

Commission file number 1-10447

CABOT OIL & GAS CORPORATION

(Exact name of registrant as specified in its charter)

DELAWARE	04-3072771
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification Number)

1200 Enclave Parkway, Houston, Texas 77077

(Address of principal executive offices including ZIP Code)

(281) 589-4600

(Registrant’s telephone number, including area code)

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 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  ¨
(Do not check if a 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

As of July 24, 2008, there were 103,352,060 shares of Common Stock, Par Value $.10 Per Share, outstanding.

CABOT OIL & GAS CORPORATION

INDEX TO FINANCIAL STATEMENTS

		Page
Part I. Financial Information
Item 1.	Financial Statements
	Condensed Consolidated Statement of Operations for the Three Months and Six Months Ended June 30, 2008 and 2007	3
	Condensed Consolidated Balance Sheet at June 30, 2008 and December 31, 2007	4
	Condensed Consolidated Statement of Cash Flows for the Six Months Ended June 30, 2008 and 2007	5
	Notes to the Condensed Consolidated Financial Statements	6
	Report of Independent Registered Public Accounting Firm on Review of Interim Financial Information	25
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	26
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	44
Item 4.	Controls and Procedures	46
Part II. Other Information
Item 1.	Legal Proceedings	46
Item 1A.	Risk Factors	47
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	47
Item 4.	Submission of Matters to a Vote of Security Holders	47
Item 6.	Exhibits	49
Signatures		50

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PART I. FINANCIAL INFORMATION

ITEM 1. Financial Statements

CABOT OIL & GAS CORPORATION

CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS (Unaudited)

	Three Months Ended June 30,				Six Months Ended June 30,
(In thousands, except per share amounts)	2008		2007		2008		2007
OPERATING REVENUES
Natural Gas Production	$	202,689	$	144,128	$	369,248	$	290,878
Brokered Natural Gas		27,188		18,001		62,808		51,178
Crude Oil and Condensate		18,600		13,263		35,087		24,205
Other		377		440		1,362		1,144
		248,854		175,832		468,505		367,405
OPERATING EXPENSES
Brokered Natural Gas Cost		24,140		16,051		54,430		44,750
Direct Operations—Field and Pipeline		22,636		19,004		40,127		36,135
Exploration		7,290		6,825		12,351		12,477
Depreciation, Depletion and Amortization		42,482		34,262		83,998		67,657
Impairment of Unproved Properties		5,919		6,323		10,670		10,309
General and Administrative		33,477		12,965		61,050		31,245
Taxes Other Than Income		19,225		14,579		36,122		27,744
		155,169		110,009		298,748		230,317
Gain on Sale of Assets		401		4,422		401		12,342
INCOME FROM OPERATIONS		94,086		70,245		170,158		149,430
Interest Expense and Other		6,207		3,619		12,198		7,543
Income Before Income Taxes		87,879		66,626		157,960		141,887
Income Tax Expense		33,254		25,250		57,360		51,964
NET INCOME	$	54,625	$	41,376	$	100,600	$	89,923
Basic Earnings Per Share	$	0.55	$	0.43	$	1.03	$	0.93
Diluted Earnings Per Share	$	0.55	$	0.42	$	1.02	$	0.92
Weighted Average Common Shares Outstanding		98,467		96,929		98,092		96,813
Diluted Common Shares (Note 5)		99,481		98,406		98,964		98,077

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

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CABOT OIL & GAS CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEET (Unaudited)

(In thousands, except share amounts)	June 30, 2008			December 31, 2007
ASSETS
Current Assets
Cash and Cash Equivalents	$	136,331		$	18,498
Accounts Receivable, Net		162,680			109,306
Income Taxes Receivable		629			3,832
Inventories		19,702			27,353
Deferred Income Taxes		104,791			26,456
Derivative Contracts (Note 7)		—			12,655
Other Current Assets		12,625			23,313
Total Current Assets		436,758			221,413
Properties and Equipment, Net (Successful Efforts Method) (Note 2)		2,185,496			1,908,117
Deferred Income Taxes		78,586			47,847
Other Assets		17,592			31,217
	$	2,718,432		$	2,208,594
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Accounts Payable	$	196,150		$	173,497
Current Portion of Long-Term Debt		20,000			20,000
Deferred Income Taxes		1,264			3,930
Income Taxes Payable		503			1,391
Derivative Contracts (Note 7)		213,295			5,383
Accrued Liabilities		44,042			48,065
Total Current Liabilities		475,254			252,266
Long-Term Liability for Pension and Postretirement Benefits (Note 10)		29,711			26,947
Long-Term Debt (Note 4)		245,000			330,000
Derivative Contracts (Note 7)		69,476			—
Deferred Income Taxes		542,214			481,770
Other Liabilities		57,472			47,354
Commitments and Contingencies (Note 6)
Stockholders’ Equity
Common Stock:
Authorized — 120,000,000 Shares of $0.10 Par Value Issued and Outstanding— 103,543,760 Shares and 102,681,468 Shares in 2008 and 2007, respectively		10,354			10,268
Additional Paid-in Capital		657,830			424,229
Retained Earnings		817,072			722,344
Accumulated Other Comprehensive Loss (Note 8)		(182,602	)		(894	)
Less Treasury Stock, at Cost: (Note 12)
202,200 Shares and 5,204,700 Shares in 2008 and 2007, respectively		(3,349	)		(85,690	)
Total Stockholders’ Equity		1,299,305			1,070,257
	$	2,718,432		$	2,208,594

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

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CABOT OIL & GAS CORPORATION

CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS (Unaudited)

	Six Months Ended June 30,
(In thousands)	2008			2007
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income	$	100,600		$	89,923
Adjustments to Reconcile Net Income to Cash Provided by Operating Activities:
Depreciation, Depletion and Amortization		83,998			67,657
Impairment of Unproved Properties		10,670			10,309
Deferred Income Tax Expense		55,515			39,612
Gain on Sale of Assets		(401	)		(12,342	)
Exploration Expense		12,351			12,477
Unrealized Loss on Derivatives		2,909			—
Stock-Based Compensation Expense and Other		19,830			11,617
Changes in Assets and Liabilities:
Accounts Receivable, Net		(57,522	)		15,999
Income Taxes Receivable		3,203			10,229
Inventories		7,651			9,878
Other Current Assets		10,689			(3,645	)
Other Assets		5,697			(20,748	)
Accounts Payable and Accrued Liabilities		20,373			(9,026	)
Income Taxes Payable		(888	)		10,717
Other Liabilities		1,736			15,196
Stock-Based Compensation Tax Benefit		—			(6,046	)
Net Cash Provided by Operating Activities		276,411			241,807
CASH FLOWS FROM INVESTING ACTIVITIES
Capital Expenditures		(312,445	)		(271,931	)
Acquisitions		(60,166	)		—
Proceeds from Sale of Assets		1,150			5,825
Exploration Expense		(12,351	)		(12,477	)
Net Cash Used in Investing Activities		(383,812	)		(278,583	)
CASH FLOWS FROM FINANCING ACTIVITIES
Increase in Debt		180,000			25,000
Decrease in Debt		(265,000	)		(10,000	)
Net Proceeds from Sale of Common Stock		316,107			2,307
Stock-Based Compensation Tax Benefit		—			6,046
Dividends Paid		(5,873	)		(4,840	)
Net Cash Provided by Financing Activities		225,234			18,513
Net Increase / (Decrease) in Cash and Cash Equivalents		117,833			(18,263	)
Cash and Cash Equivalents, Beginning of Period		18,498			41,854
Cash and Cash Equivalents, End of Period	$	136,331		$	23,591

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

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CABOT OIL & GAS CORPORATION

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)

1. FINANCIAL STATEMENT PRESENTATION

During interim periods, Cabot Oil & Gas Corporation (the Company) follows the same accounting policies used in its Annual Report to Stockholders and its Annual Report on Form 10-K for the year ended December 31, 2007 filed with the Securities and Exchange Commission (SEC). The interim financial statements should be read in conjunction with the notes to the financial statements and information presented in the Company’s 2007 Annual Report to Stockholders and its Annual Report on Form 10-K. In management’s opinion, the accompanying interim condensed consolidated financial statements contain all material adjustments, consisting only of normal recurring adjustments, necessary for a fair statement. The results for any interim period are not necessarily indicative of the expected results for the entire year.

Our independent registered public accounting firm has performed a review of these condensed consolidated interim financial statements in accordance with standards established by the Public Company Accounting Oversight Board (United States). Pursuant to Rule 436(c) under the Securities Act of 1933, their report should not be considered a part of a registration statement prepared or certified by PricewaterhouseCoopers LLP within the meanings of Sections 7 and 11 of the Act.

Effective January 1, 2008, the Company adopted those provisions of Statement of Financial Accounting Standards (SFAS) No. 157, “Fair Value Measurements,” that were required to be adopted. There was no financial statement impact upon adoption on January 1, 2008. For further information regarding the adoption of SFAS No. 157, please refer to Note 7 of the Notes to the Condensed Consolidated Financial Statements.

SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities, including an amendment of FASB Statement No. 115,” became effective on January 1, 2008 and permits companies to choose, at specified dates, to measure certain eligible financial instruments at fair value. The provisions of SFAS No. 159 apply only to entities that elect to use the fair value option and to all entities with available-for-sale and trading securities. At the effective date, companies may elect the fair value option for eligible items that exist at that date, and the effect of the first remeasurement to fair value must be reported as a cumulative-effect adjustment to the opening balance of retained earnings. Since the Company has not elected to adopt the fair value option for eligible items, SFAS No. 159 has not had an impact on its financial position or results of operations.

Recently Issued Accounting Pronouncements

In June 2008, the Financial Accounting Standards Board (FASB) issued FASB Staff Position (FSP) No. Emerging Issues Task Force (EITF) 03-6-1, “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities.” Under this FSP, unvested share-based payment awards that contain nonforfeitable rights to dividends or dividend equivalents, whether they are paid or unpaid, are considered participating securities and should be included in the computation of earnings per share pursuant to the two-class method. FSP No. EITF 03-6-1 is effective for financial statements issued for fiscal years beginning after December 15, 2008, and interim periods within those years. In addition, all prior period earnings per share data presented should be adjusted retrospectively and early application is not permitted. The Company does not believe that FSP No. EITF 03-6-1 will have a material impact on its financial position, results of operations or cash flows.

In May 2008, the FASB issued SFAS No. 162, “The Hierarchy of Generally Accepted Accounting Principles,” which identifies a consistent framework for selecting accounting principles to be used in preparing financial statements for nongovernmental entities that are presented in conformity with United States generally accepted accounting principles (GAAP). The current GAAP hierarchy was criticized due to its complexity, ranking position of FASB Statements of Financial Accounting Concepts and the fact that it is directed at auditors rather than entities. SFAS No. 162 will be effective 60 days following the SEC’s approval of the Public Company Accounting Oversight Board amendments to AU Section 411, “The Meaning of Present Fairly in Conformity with Generally Accepted Accounting Principles.” The FASB does not expect that SFAS No. 162 will have a change in current practice, and the Company does not believe that SFAS No. 162 will have an impact on its financial position, results of operations or cash flows.

6

In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities,” which amends SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities.” Enhanced disclosures to improve financial reporting transparency are required and include disclosure about the location and amounts of derivative instruments in the financial statements, how derivative instruments are accounted for and how derivatives affect an entity’s financial position, financial performance and cash flows. A tabular format including the fair value of derivative instruments and their gains and losses, disclosure about credit risk-related derivative features and cross-referencing within the footnotes are also new requirements. SFAS No. 161 is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008, with early application and comparative disclosures encouraged, but not required. The Company has not yet adopted SFAS No. 161. The Company does not believe that SFAS No. 161 will have an impact on its financial position, results of operations or cash flows.

In December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interest in Consolidated Financial Statements, an amendment of Accounting Research Bulletin (ARB) No. 51.” SFAS No. 160 clarifies that a noncontrolling interest (previously commonly referred to as a minority interest) in a subsidiary is an ownership interest in the consolidated entity and should be reported as equity in the consolidated financial statements. The presentation of the consolidated income statement has been changed by SFAS No. 160, and consolidated net income attributable to both the parent and the noncontrolling interest is now required to be reported separately. Previously, net income attributable to the noncontrolling interest was typically reported as an expense or other deduction in arriving at consolidated net income and was often combined with other financial statement amounts. In addition, the ownership interests in subsidiaries held by parties other than the parent must be clearly identified, labeled, and presented in equity in the consolidated financial statements separately from the parent’s equity. Subsequent changes in a parent’s ownership interest while the parent retains its controlling financial interest in its subsidiary should be accounted for consistently, and when a subsidiary is deconsolidated, any retained noncontrolling equity interest in the former subsidiary must be initially measured at fair value. Expanded disclosures, including a reconciliation of equity balances of the parent and noncontrolling interest, are also required. SFAS No. 160 is effective for fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2008 and earlier adoption is prohibited. Prospective application is required. At this time, the Company does not have any material noncontrolling interests in consolidated subsidiaries. Therefore, it does not believe that the adoption of SFAS No. 160 will have a material impact on its financial position, results of operations or cash flows.

In December 2007, the FASB issued SFAS No. 141(R), “Business Combinations.” SFAS No. 141(R) was issued in an effort to continue the movement toward the greater use of fair values in financial reporting and increased transparency through expanded disclosures. It changes how business acquisitions are accounted for and will impact financial statements at the acquisition date and in subsequent periods. Certain of these changes will introduce more volatility into earnings. The acquirer must now record all assets and liabilities of the acquired business at fair value, and related transaction and restructuring costs will be expensed rather than the previous method of being capitalized as part of the acquisition. SFAS No. 141(R) also impacts the annual goodwill impairment test associated with acquisitions, including those that close before the effective date of SFAS No. 141(R). The definitions of a “business” and a “business combination” have been expanded, resulting in more transactions qualifying as business combinations. SFAS No. 141(R) is effective for fiscal years, and interim periods within those fiscal years, beginning on or after December 31, 2008 and earlier adoption is prohibited. The Company cannot predict the impact that the adoption of SFAS No. 141(R) will have on its financial position, results of operations or cash flows with respect to any acquisitions completed after December 31, 2008.

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2. PROPERTIES AND EQUIPMENT, NET

Properties and equipment, net are comprised of the following:

(In thousands)	June 30, 2008			December 31, 2007
Unproved Oil and Gas Properties	$	150,336		$	108,868
Proved Oil and Gas Properties		2,927,158			2,627,346
Gathering and Pipeline Systems		243,464			235,127
Land, Building and Other Equipment		61,209			41,602
		3,382,167			3,012,943
Accumulated Depreciation, Depletion and Amortization		(1,196,671	)		(1,104,826	)
	$	2,185,496		$	1,908,117

At June 30, 2008, the Company did not have any projects that had exploratory well costs that were capitalized for a period of greater than one year after drilling.

In April 2008, the Company acquired a services business for total consideration of $21.6 million, comprised of the conversion of a $15.6 million note receivable, the issuance of 70,168 shares of Company common stock, and the payment of $2.5 million in cash. The transaction was accounted for as a business combination, and the Company recorded approximately $4.4 million of goodwill.

Pending East Texas Property Acquisition

On June 3, 2008, the Company entered into a definitive purchase and sale agreement (the “Purchase Agreement”) to acquire for $602.8 million in cash certain producing oil and gas properties located in Panola and Rusk counties, Texas. The properties comprise approximately 25,000 gross leasehold acres with a 97% average working interest near the Company’s existing Minden field. Most of the producing properties are operated by the sellers. In addition, the acquisition includes a natural gas gathering infrastructure of 33 miles of pipeline, 5,400 horsepower of compression and four water disposal wells. The Company estimates that proved reserves included in the acquisition are approximately 176 Bcfe (allocated mainly to the Cotton Valley formation) and that approximately 32 Mmcfe/Day of production will be added to the Company’s current production upon closing. Additional drilling activity is expected to be conducted on the properties prior to closing the acquisition.

The Purchase Agreement contains customary representations and warranties and provides for the acquisition to be effective as of May 1, 2008. The purchase price is subject to adjustment based on production proceeds received and expenses paid as well as any expenses for title or environmental defects related to the properties that exceed certain deductible amounts. The Company anticipates that the closing of this transaction will occur in August 2008, subject to customary closing conditions. Either party may terminate the Purchase Agreement if the closing has not occurred by November 17, 2008, or in the event of a casualty loss, title defect or environmental defect in excess of $60.3 million. During the second quarter of 2008, the Company paid a $60.3 million cash deposit in accordance with the terms of the Purchase Agreement.

The Company expects to fund the acquisition with some combination of (i) the net proceeds from its June 2008 sale of 5.0 million shares of common stock (see Note 12 of the Notes to the Condensed Consolidated Financial Statements); (ii) the net proceeds from its July 2008 private placement of senior unsecured fixed rate notes (see Note 4 of the Notes to the Condensed Consolidated Financial Statements); (iii) borrowings under its revolving credit facility; and (iv) other cash on hand. Additionally, in order to mitigate its exposure to decreases in the price of natural gas and crude oil, in connection with the acquisition, the Company entered into 15 natural gas price and crude oil swaps in the second quarter of 2008 for the remainder of 2008 and extending through 2010 (see Note 7 of the Notes to the Condensed Consolidated Financial Statements).

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3. ADDITIONAL BALANCE SHEET INFORMATION

Certain balance sheet amounts are comprised of the following:

(In thousands)	June 30, 2008			December 31, 2007
ACCOUNTS RECEIVABLE, NET
Trade Accounts	$	142,481		$	94,550
Joint Interest Accounts		23,541			16,443
Other Accounts		166			2,291
		166,188			113,284
Allowance for Doubtful Accounts		(3,508	)		(3,978	)
	$	162,680		$	109,306
INVENTORIES
Natural Gas in Storage	$	12,412		$	20,472
Tubular Goods and Well Equipment		9,159			5,953
Pipeline Imbalances		(1,869	)		928
	$	19,702		$	27,353
OTHER CURRENT ASSETS
Drilling Advances	$	1,027		$	2,475
Prepaid Balances		11,598			8,900
Restricted Cash		—			11,600
Other Accounts		—			338
	$	12,625		$	23,313
OTHER ASSETS
Note Receivable	$	—		$	13,375
Goodwill		4,409			—
Rabbi Trust Deferred Compensation Plan		11,089			9,744
Other Accounts		2,094			8,098
	$	17,592		$	31,217
ACCOUNTS PAYABLE
Trade Accounts	$	26,101		$	27,678
Natural Gas Purchases		14,521			6,465
Royalty and Other Owners		66,386			37,023
Capital Costs		67,461			83,754
Taxes Other Than Income		9,649			6,416
Drilling Advances		1,790			1,528
Wellhead Gas Imbalances		3,262			3,227
Other Accounts		6,980			7,406
	$	196,150		$	173,497
ACCRUED LIABILITIES
Employee Benefits	$	9,879		$	13,699
Current Liability for Pension Benefits		116			116
Current Liability for Postretirement Benefits		642			642
Taxes Other Than Income		23,660			13,216
Interest Payable		6,461			6,518
Litigation		—			11,600
Other Accounts		3,284			2,274
	$	44,042		$	48,065
OTHER LIABILITIES
Rabbi Trust Deferred Compensation Plan	$	26,470		$	16,018
Accrued Plugging and Abandonment Liability		25,983			24,724
Other Accounts		5,019			6,612
	$	57,472		$	47,354

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4. LONG-TERM DEBT

At June 30, 2008, the Company had $55 million of borrowings outstanding under its revolving credit facility at a weighted-average interest rate of 4.3%. The credit facility provides for an available credit line of $350 million. In June 2008, the Company amended its revolving credit facility agreement to increase the commitments of the lenders to $350 million from $250 million pursuant to the accordion feature in the agreement. The term of the credit facility expires in December 2009. The credit facility is unsecured. The available credit line is subject to adjustment from time to time on the basis of the projected present value (as determined by the banks’ petroleum engineer) of estimated future net cash flows from certain proved oil and gas reserves and other assets of the Company. While the Company does not expect a reduction in the available credit line, in the event that it is adjusted below the outstanding level of borrowings, the Company has a period of six months either to reduce its outstanding debt to the adjusted credit line available with a requirement to provide additional borrowing base assets or to pay down one-sixth of the excess during each of the six months.

In addition to borrowings under the credit facility, the Company had the following debt outstanding at June 30, 2008:

• $40 million of 12-year 7.19% Notes due in November 2009, which consisted of $20 million of long-term debt and $20 million of current portion of long-term debt, to be repaid in two remaining annual installments of $20 million in November of each year

• $75 million of 10-year 7.26% Notes due in July 2011

• $75 million of 12-year 7.36% Notes due in July 2013

• $20 million of 15-year 7.46% Notes due in July 2016

The revolving credit facility includes a covenant limiting the Company’s total debt. In conjunction with the June 2008 amendment of the Company’s revolving credit facility, the Company’s total debt limit was increased from $610 million to $1.2 billion.

On July 16, 2008, the Company completed a private placement of $425 million aggregate principal amount of senior unsecured fixed-rate notes pursuant to a note purchase agreement dated July 16, 2008. The notes consist of $245 million aggregate principal amount of the Company’s 6.44% Series D Senior Notes due July 16, 2018, $100 million aggregate principal amount of the Company’s 6.54% Series E Senior Notes due July 16, 2020 and $80 million aggregate principal amount of the Company’s 6.69% Series F Senior Notes due July 16, 2023 (collectively, the “New Notes”).

Interest on the New Notes of each series is payable semi-annually. The Company may prepay all or any portion of the New Notes of each series on any date at a price equal to the principal amount thereof plus accrued and unpaid interest and a make-whole premium. The New Notes contain restrictions on the merger of the Company with a third party other than under certain limited conditions. There are also various other restrictive covenants customarily found in such debt instruments. These covenants include a required asset coverage ratio (present value of proved reserves plus adjusted cash (as defined in the note purchase agreement) to debt and other liabilities) of at least 1.5 to 1.0, and a minimum annual coverage ratio of operating cash flow to interest expense for the trailing four quarters of 2.8 to 1.0. The New Notes also are subject to customary events of default. The Company is required to offer to prepay the New Notes upon specified change in control events or if a credit ratings test is not met.

The Company believes it is in compliance in all material respects with its debt covenants.

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5. EARNINGS PER COMMON SHARE

Basic earnings per common share (EPS) is computed by dividing net income (the numerator) by the weighted-average number of common shares outstanding for the period (the denominator). Diluted EPS is similarly calculated except that the denominator is increased using the treasury stock method to reflect the potential dilution that could occur if stock options and stock awards outstanding at the end of the applicable period were exercised for common stock.

The following is a calculation of basic and diluted weighted-average shares outstanding for the three and six months ended June 30, 2008 and 2007:

	Three Months Ended June 30,		Six Months Ended June 30,
	2008	2007	2008	2007
Weighted-Average Shares—Basic	98,467,311	96,928,842	98,091,641	96,812,801
Dilution Effect of Stock Options and Awards at End of Period	1,014,070	1,477,119	872,358	1,264,003
Weighted-Average Shares—Diluted	99,481,381	98,405,961	98,963,999	98,076,804
Weighted-Average Stock Awards and Shares
Excluded from Diluted Earnings per Share due to the Anti-Dilutive Effect	—	29,400	274,854	369,726

6. COMMITMENTS AND CONTINGENCIES

Contingencies

The Company is a defendant in various legal proceedings arising in the normal course of its business. All known liabilities are accrued based on management’s best estimate of the potential loss. While the outcome and impact of such legal proceedings on the Company cannot be predicted with certainty, management believes that the resolution of these proceedings through settlement or adverse judgment will not have a material adverse effect on the Company’s condensed consolidated financial position or cash flow. Operating results, however, could be significantly impacted in the reporting periods in which such matters are resolved.

West Virginia Royalty Litigation

In December 2001, the Company was sued by two royalty owners in West Virginia state court for an unspecified amount of damages. The plaintiffs requested class certification and alleged that the Company failed to pay royalty based upon the wholesale market value of the gas, that the Company had taken improper deductions from the royalty and that it failed to properly inform royalty owners of the deductions. The plaintiffs also claimed that they are entitled to a 1/8th royalty share of the gas sales contract settlement that the Company reached with Columbia Gas Transmission Corporation in 1995 bankruptcy proceedings. The Court entered an order on June 1, 2005 granting the motion for class certification.

The parties reached a tentative settlement pursuant to which the Company paid a total of $12.0 million into a trust fund for disbursement to the class members upon final approval of the settlement by the Court. The court held the final fairness hearing on February 12, 2008 and approved the settlement, authorized the distribution of the funds to the class members and dismissed all claims against the Company with prejudice. These funds were disbursed in April 2008. Prior to the date of the Court’s final order approving the settlement, these restricted cash funds were held by a financial institution in West Virginia under the joint custody of the plaintiffs and the Company. As of June 30, 2008, these funds have been paid out to the class members or are controlled by the Court. Accordingly, the Company had reduced Other Current Assets in the Condensed Consolidated Balance Sheet. In the settlement, the Company and the class members also

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agreed to a methodology for payment of future royalties and the reporting format such methodology will take. The Company had provided a reserve sufficient to cover the amount agreed upon to settle this litigation.

Commitment and Contingency Reserves

The Company has established reserves for certain legal proceedings. The establishment of a reserve involves an estimation process that includes the advice of legal counsel and subjective judgment of management. While management believes these reserves to be adequate, it is reasonably possible that the Company could incur approximately $1.3 million of additional loss with respect to those matters in which reserves have been established. Future changes in the facts and circumstances could result in the actual liability exceeding the estimated ranges of loss and amounts accrued.

While the outcome and impact on the Company cannot be predicted with certainty, management believes that the resolution of these proceedings through settlement or adverse judgment will not have a material adverse effect on the condensed consolidated financial position or cash flow of the Company. Operating results, however, could be significantly impacted in the reporting periods in which such matters are resolved.

Firm Gas Transportation Agreements

The Company has incurred, and will incur over the next several years, demand charges on firm gas transportation agreements. These agreements provide firm transportation capacity rights on pipeline systems in Canada, the West and East regions. The remaining terms on these agreements range from less than one year to approximately 20 years and require the Company to pay transportation demand charges regardless of the amount of pipeline capacity utilized by the Company. If the Company does not utilize the capacity, it can release it to others, thus reducing its potential liability.

As previously disclosed in the Company’s Annual Report on Form 10-K for the year ended December 31, 2007 (the Form 10-K), obligations under firm gas transportation agreements in effect at December 31, 2007 were $82.2 million. For further information on these future obligations, please refer to Note 7 of the Notes to the Consolidated Financial Statements in the Form 10-K.

Drilling Rig Commitments

In the Form 10-K, the Company disclosed that it had commitments on five drilling rigs under contract in the Gulf Coast. As of June 30, 2008, the total commitment increased by one additional drilling rig for $1.6 million to $72.9 million from the $71.3 million total amount disclosed in the Form 10-K. For further information on these future obligations, please refer to Note 7 of the Notes to the Consolidated Financial Statements in the Form 10-K.

7. FINANCIAL INSTRUMENTS

Adoption of SFAS No. 157

In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements,” which establishes a formal framework for measuring fair values of assets and liabilities in financial statements that are already required by United States generally accepted accounting principles to be measured at fair value. SFAS No. 157 clarifies guidance in FASB Concepts Statement (CON) No. 7 which discusses present value techniques in measuring fair value. Additional disclosures are also required for transactions measured at fair value. SFAS No. 157 is effective for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. In February 2008, the FASB issued FSP No. FAS 157-2, “Effective Date of FASB Statement No. 157,” which granted a one year deferral (to fiscal years beginning after November 15, 2008, and interim periods within those fiscal years) for certain non-financial assets and liabilities to comply with SFAS No. 157. The Company will adopt the provisions of FAS No. 157 covered under FSP No. 157-2 on January 1, 2009. The Company is currently evaluating the impact of implementation with respect to nonfinancial assets and liabilities measured on a nonrecurring basis on its consolidated financial statements, which will primarily be limited to asset impairments including goodwill, other long-lived assets, asset retirement obligations and assets acquired and liabilities assumed in a business combination, if any. Additionally, in February 2008, the FASB issued FSP No. FAS 157-1, “Application of FASB Statement No. 157 to FASB Statement No. 13 and Other Accounting Pronouncements That Address Fair Value

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Measurements for Purposes of Lease Classification or Measurement under Statement 13,” which amends SFAS No. 157 to exclude SFAS No. 13 and related pronouncements that address fair value measurements for purposes of lease classification and measurement. FSP No. FAS 157-1 is effective upon the initial adoption of SFAS No. 157. The Company has adopted SFAS No. 157 and FSP No. FAS 157-1 discussed above, and there was no impact on its financial position or results of operations for the six months ended June 30, 2008.

As defined in SFAS No. 157, fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). The transaction is based on a hypothetical transaction in the principal or most advantageous market considered from the perspective of the market participant that holds the asset or owes the liability.

The valuation techniques that can be used under SFAS No. 157 are the market approach, income approach or cost approach. The market approach uses prices and other information for market transactions involving identical or comparable assets or liabilities, such as matrix pricing. The income approach uses valuation techniques to convert future amounts to a single discounted present amount based on current market conditions about those future amounts, such as present value techniques, option pricing models (i.e. Black-Scholes model) and binomial models (i.e. Monte-Carlo model). The cost approach is based on current replacement cost to replace an asset.

The Company utilizes market data or assumptions that market participants who are independent, knowledgeable and willing and able to transact would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. The Company attempts to utilize valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. The Company is able to classify fair value balances based on the observability of those inputs. SFAS No. 157 establishes a formal fair value hierarchy based on the inputs used to measure fair value. The hierarchy gives the highest priority level 1 measurements and the lowest priority to level 3 measurements, and accordingly, level 1 measurements should be used whenever possible.

The three levels of the fair value hierarchy as defined by SFAS No. 157 are as follows:

• Level 1: Valuations utilizing quoted, unadjusted prices for identical assets or liabilities in active markets that the Company has the ability to access. This is the most reliable evidence of fair value and does not require a significant degree of judgment. Examples include exchange-traded derivatives and listed equities that are actively traded.

• Level 2: Valuations utilizing quoted prices in markets that are not considered to be active or financial instruments for which all significant inputs are observable, either directly or indirectly for substantially the full term of the asset or liability. Financial instruments that are valued using models or other valuation methodologies are included. Models used should primarily be industry-standard models that consider various assumptions and economic measures, such as interest rates, yield curves, time value, volatilities, contract terms, current market prices, credit risk or other market-corroborated inputs. Examples include most over-the-counter derivatives (non-exchange traded), physical commodities, most structured notes and municipal and corporate bonds.

• Level 3: Valuations utilizing significant, unobservable inputs. This provides the least objective evidence of fair value and requires a significant degree of judgment. Inputs may be used with internally developed methodologies and should reflect an entity’s assumptions using the best information available about the assumptions that market participants would use in pricing an asset or liability. Examples include certain corporate loans, real-estate and private equity investments and long-dated or complex over-the-counter derivatives.

Depending on the particular asset or liability, input availability can vary depending on factors such as product type, longevity of a product in the market and other particular transaction conditions. In some cases, certain inputs used to measure fair value may be categorized into different levels of the fair value hierarchy. For disclosure purposes under SFAS No. 157, the lowest level that contains significant inputs used in valuation should be chosen. Per SFAS No. 157, the Company has classified its assets and liabilities into these levels depending upon the data relied on to determine the fair values. The fair values of the Company’s natural gas and crude oil price collars and swaps are valued based upon quotes obtained from counterparties to the agreements and are designated as Level 3.

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The following fair value hierarchy table presents information about the Company’s assets and liabilities measured at fair value on a recurring basis as of June 30, 2008:

(In thousands)	Quoted Prices in Active Markets for Identical Assets (Level 1)			Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)			Balance as of June 30, 2008
Assets
Rabbi Trust Deferred Compensation Plan	$	11,089		$	—	$	—		$	11,089
Liabilities
Rabbi Trust Deferred Compensation Plan	$	(26,470	)	$	—	$	—		$	(26,470	)
Derivative Contracts		—			—		(282,771	)		(282,771	)
Total Liabilities	$	(26,470	)	$	—	$	(282,771	)	$	(309,241	)

The determination of the fair values above incorporates various factors required under SFAS No. 157. These factors include not only the credit standing of the counterparties involved, but also the impact of the Company’s nonperformance risk on its liabilities.

The following table sets forth a reconciliation of changes in the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy:

(In thousands)	Net Derivatives (1)
Balance as of December 31, 2007	$	7,272
Total Gains or (Losses) (Realized or Unrealized):
Included in Earnings		(29,348	)
Included in Other Comprehensive Income		(287,135	)
Purchases, Issuances and Settlements		26,440
Transfers In and/or Out of Level 3		—
Balance as of June 30, 2008	$	(282,771	)

⁽¹⁾ Net derivatives for Level 3 at December 31, 2007 included derivative assets of $12.7 million and derivative liabilities of $5.4 million.

The derivative contracts were measured based on quotes from the Company’s counterparties. Such quotes have been derived using a Black-Scholes model that considers various inputs including current market and contractual prices for the underlying instruments, quoted forward prices for natural gas and crude oil, volatility factors and interest rates, such as a LIBOR curve for a similar length of time as the derivative contract term. Although the Company utilizes multiple quotes to assess the reasonableness of its values, the Company has not attempted to obtain sufficient corroborating market evidence to support classifying these derivative contracts as Level 2. The nonperformance risk of the Company was evaluated using a market credit spread provided by the Company’s bank.

Rabbi Trust Deferred Compensation Plan

The Company’s investments associated with its Rabbi Trust Deferred Compensation Plan consist of mutual funds that are publicly traded and for which market prices are readily available. In addition, the Rabbi Trust Deferred Compensation Liability includes the value of deferred shares of the Company’s common stock which is publicly traded and for which current market prices are readily available. As of June 30, 2008, 256,400 shares of the Company’s stock representing vested performance share awards were deferred

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into the rabbi trust. For the first half of 2008, $6.6 million, representing the appreciation in the closing price of these shares from December 31, 2007, was recorded as a component of stock-based compensation expense in General and Administrative expense in the Condensed Consolidated Statement of Operations.

Derivative Instruments and Hedging Activity

The Company periodically enters into derivative commodity instruments to hedge its exposure to price fluctuations on natural gas and crude oil production. The Company’s credit agreement restricts the ability of the Company to enter into commodity hedges other than to hedge or mitigate risks to which the Company has actual or projected exposure or as permitted under the Company’s risk management policies and not subjecting the Company to material speculative risks. At June 30, 2008, the Company had 55 cash flow hedges open: 36 natural gas price collar arrangements, 15 natural gas swap arrangements, three crude oil swap arrangements and one crude oil collar arrangement. At June 30, 2008, a $279.9 million ($176.3 million, net of tax) unrealized loss was recorded in Accumulated Other Comprehensive Income / (Loss), along with a $213.3 million short-term derivative liability and a $69.5 million long-term derivative liability.

The change in the fair value of derivatives designated as hedges that is effective is initially recorded to Accumulated Other Comprehensive Income / (Loss). The ineffective portion of the change in the fair value of derivatives designated as hedges, and the change in fair value of all other derivatives, are recorded currently in earnings as a component of Natural Gas Production and Crude Oil and Condensate Revenue, as appropriate.

During the first half of 2008, the Company entered into 24 new natural gas collar contracts covering a portion of its 2008 and 2009 production and 12 new natural gas price swap contracts covering a portion of its 2008, 2009 and 2010 production. As of June 30, 2008, natural gas price collars for the six months ending December 31, 2008 will cover 29,550 Mmcf of production at a weighted-average floor of $8.59 per Mcf and a weighted-average ceiling of $10.83 per Mcf. As of June 30, 2008, natural gas price collars for the twelve months ending December 31, 2009 will cover 47,253 Mmcf of production at a weighted-average floor of $9.40 per Mcf and a weighted-average ceiling of $12.39 per Mcf. Natural gas price swaps for the six months ending December 31, 2008 will cover 7,356 Mmcf of production at a weighted-average price of $11.22 per Mcf. As of June 30, 2008, natural gas price swaps for the twelve months ending December 31, 2009 and 2010 will cover 16,079 Mmcf and 19,295 Mmcf of production, respectively, at a weighted-average price of $12.18 per Mcf and $11.43 per Mcf, respectively.

During the first half of 2008, the Company also entered into three new crude oil price swaps covering a portion of its 2008, 2009 and 2010 production. As of June 30, 2008, a crude oil price swap for the six months ending December 31, 2008 will cover 92 Mbbls at a fixed price of $127.15. Crude oil price swaps for the years ended December 31, 2009 and 2010 will cover 365 Mbbls each at a fixed price of $125.25 and $125.00, respectively.

In anticipation of the pending East Texas acquisition, in the second quarter of 2008 the Company entered into 15 natural gas price and crude oil swaps (included in the amounts discussed above) for the remainder of 2008 and extending through 2010 for the purpose of reducing commodity price risk associated with anticipated production after the transaction closing. Under SFAS No. 133, forecasted transactions associated with an acquisition do not qualify for hedge accounting. Accordingly, the Company designated a portion of certain volumes of the hedge transactions as hedges of current production. As a result, a portion of one hedge transaction did not qualify for hedge accounting. During the six months ended June 30, 2008, a $2.7 million unrealized loss representing this proportional mark to market change was recorded in the Condensed Consolidated Statement of Operations as a component of Natural Gas Production Revenue. The remaining hedge transactions were substantially deemed to be 100% effective, resulting in ineffectiveness totaling $0.2 million which was recorded in the Condensed Consolidated Statement of Operations. The Company uses regression analysis to assess hedge effectiveness and the hypothetical derivative method in measuring the amount of ineffectiveness, if any. During the six months ended June 30, 2007, there was no ineffectiveness recorded in the Condensed Consolidated Statement of Operations.

Based upon estimates at June 30, 2008, the Company would expect to reclassify to the Condensed Consolidated Statement of Operations over the next 12 months $132.5 million in after-tax expense associated with its commodity hedges. This reclassification represents the net short-term liability associated with open positions currently not reflected in earnings at June 30, 2008 related to anticipated 2008 and 2009 production.

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8. COMPREHENSIVE INCOME / (LOSS)

Comprehensive Income / (Loss) includes Net Income and certain items recorded directly to Stockholders’ Equity and classified as Accumulated Other Comprehensive Income / (Loss). The following tables illustrate the calculation of Comprehensive Income / (Loss) for the three and six month periods ended June 30, 2008 and 2007:

	Three Months Ended June 30,
(In thousands)	2008								2007
Accumulated Other Comprehensive Income / (Loss) - Beginning of Period						$	(60,872	)						$	4,683
Net Income			$	54,625							$	41,376
Other Comprehensive Income / (Loss), net of taxes:
Reclassification Adjustment for Settled Contracts, net of taxes of $(9,404) and $4,962, respectively				16,014								(8,164	)
Changes in Fair Value of Hedge Positions, net of taxes of $81,249 and $(7,795), respectively				(138,645	)							12,829
Defined Benefit Pension and Postretirement Plans:
Amortization of Net Obligation at Transition, net of taxes of $(58) and $(119), respectively	$	100							$	197
Amortization of Prior Service Cost, net of taxes of $(93) and $(207), respectively		157								340
Amortization of Net Loss, net of taxes of $(172) and $(242), respectively		294		551						398		935
Foreign Currency Translation Adjustment, net of taxes of $(189) and $(2,291), respectively				350								3,768
Total Other Comprehensive Income / (Loss)				(121,730	)		(121,730	)				9,368			9,368
Comprehensive Income / (Loss)			$	(67,105	)						$	50,744
Accumulated Other Comprehensive
Income / (Loss) - End of Period						$	(182,602	)						$	14,051

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	Six Months Ended June 30,
(In thousands)	2008								2007
Accumulated Other Comprehensive Income / (Loss) - Beginning of Period						$	(894	)						$	37,160
Net Income			$	100,600							$	89,923
Other Comprehensive Income / (Loss), net of taxes:
Reclassification Adjustment for Settled Contracts, net of taxes of $(9,783) and $11,681, respectively				16,657								(19,220	)
Changes in Fair Value of Hedge Positions, net of taxes of $116,027 and $5,109, respectively				(197,548	)							(9,057	)
Defined Benefit Pension and Postretirement Plans:
Amortization of Net Obligation at Transition, net of taxes of $(117) and $(119), respectively	$	199							$	197
Amortization of Prior Service Cost, net of taxes of $(186) and $(207), respectively		315								340
Amortization of Net Loss, net of taxes of $(300) and $(242), respectively		512		1,026						398		935
Foreign Currency Translation Adjustment, net of taxes of $1,169 and $(2,573), respectively				(1,843	)							4,233
Total Other Comprehensive Income / (Loss)				(181,708	)		(181,708	)				(23,109	)		(23,109	)
Comprehensive Income / (Loss)			$	(81,108	)						$	66,814
Accumulated Other Comprehensive
Income / (Loss) - End of Period						$	(182,602	)						$	14,051

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Changes in the components of accumulated other comprehensive loss, net of taxes, for the six months ended June 30, 2008 were as follows:

Accumulated Other Comprehensive Income / (Loss), net of taxes (In thousands)	Net Gains / (Losses) on Cash Flow Hedges			Defined Benefit Pension and Postretirement Plans			Foreign Currency Translation Adjustment			Total
Balance at December 31, 2007	$	4,553		$	(14,027	)	$	8,580		$	(894	)
Net change in unrealized loss on cash flow hedges, net of taxes of $106,244		(180,891	)		—			—			(180,891	)
Net change in defined benefit pension and postretirement plans, net of taxes of $(603)		—			1,026			—			1,026
Change in foreign currency translation adjustment, net of taxes of $1,169		—			—			(1,843	)		(1,843	)
Balance at June 30, 2008	$	(176,338	)	$	(13,001	)	$	6,737		$	(182,602	)

9. ASSET RETIREMENT OBLIGATIONS

The following table reflects the changes in the asset retirement obligations during the six months ended June 30, 2008:

(In thousands)
Carrying amount of asset retirement obligations at December 31, 2007	$	24,724
Liabilities added during the current period		714
Liabilities settled and divested during the current period		(29	)
Current period accretion expense		574
Carrying amount of asset retirement obligations at June 30, 2008	$	25,983

Accretion expense was $0.6 million and $0.5 million, respectively, for the six months ended June 30, 2008 and 2007 and is included within Depreciation, Depletion and Amortization expense on the Company’s Condensed Consolidated Statement of Operations.

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10. PENSION AND OTHER POSTRETIREMENT BENEFITS

The components of net periodic benefit costs for the three and six months ended June 30, 2008 and 2007 were as follows:

	Three Months Ended June 30,						Six Months Ended June 30,
(In thousands)	2008			2007			2008			2007
Qualified and Non-Qualified Pension Plans
Current Period Service Cost	$	828		$	733		$	1,657		$	1,466
Interest Cost		818			692			1,636			1,384
Expected Return on Plan Assets		(884	)		(754	)		(1,767	)		(1,508	)
Amortization of Prior Service Cost		13			36			25			72
Amortization of Net Loss		294			272			587			544
Net Periodic Pension Cost	$	1,069		$	979		$	2,138		$	1,958
Postretirement Benefits Other than Pension Plans
Current Period Service Cost	$	307		$	211		$	541		$	435
Interest Cost		382			273			690			539
Amortization of Prior Service Cost		238			238			476			476
Amortization of Net Loss		171			55			224			97
Amortization of Net Obligation at Transition		158			158			316			316
Total Postretirement Benefit Cost	$	1,256		$	935		$	2,247		$	1,863

Employer Contributions

The funding levels of the pension and postretirement plans are in compliance with standards set by applicable law or regulation. The Company previously disclosed in its financial statements for the year ended December 31, 2007 that it expected to contribute $0.1 million to its non-qualified pension plan and approximately $0.7 million to the postretirement benefit plan during 2008. It is anticipated that these contributions will be made prior to December 31, 2008. The Company does not have any required minimum funding obligations for its qualified pension plan in 2008.

11. STOCK-BASED COMPENSATION

Incentive Plans

Under the Company’s 2004 Incentive Plan, incentive and non-statutory stock options, stock appreciation rights (SARs), stock awards, cash awards and performance awards may be granted to key employees, consultants and officers of the Company. Non-employee directors of the Company may be granted discretionary awards under the 2004 Incentive Plan consisting of stock options or stock awards. In the first quarter of 2007, the Board of Directors eliminated the automatic award of an option to purchase 30,000 shares of common stock on the date the non-employee directors first join the Board of Directors. In its place, the Board of Directors will consider an annual fixed dollar stock award which is competitive with the Company’s peer group. A total of 5,100,000 shares of common stock may be issued under the 2004 Incentive Plan. Under the 2004 Incentive Plan, no more than 1,800,000 shares may be used for stock awards that are not subject to the achievement of performance based goals, and no more than 3,000,000 shares may be issued pursuant to incentive stock options.

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Stock-Based Compensation Expense

Compensation expense charged against income for stock-based awards (including the supplemental employee incentive plan) during the first half of 2008 and 2007 was $39.3 million and $10.7 million, pre-tax, respectively, and is included in General and Administrative Expense in the Condensed Consolidated Statement of Operations. Stock-based compensation expense in the second quarter of 2008 was $10.4 million compared to $4.1 million in the second quarter of 2007.

For further information regarding Stock-Based Compensation, please refer to Note 10 of the Notes to the Consolidated Financial Statements in the Form 10-K.

Restricted Stock Awards

Restricted stock awards vest either at the end of a three year service period, or on a graded-vesting basis of one-third at each anniversary date over a three year service period. Under the graded-vesting approach, the Company recognizes compensation cost over the three year requisite service period for each separately vesting tranche as though the awards are, in substance, multiple awards. For awards that vest at the end of the three year service period, expense is recognized ratably using a straight-line expensing approach over three years. For all restricted stock awards, vesting is dependant upon the employees’ continued service with the Company, with the exception of employment termination due to death, disability or retirement.

The fair value of restricted stock grants is based on the average of the high and low stock price on the grant date. The maximum contractual term is three years. In accordance with SFAS No. 123(R), the Company accelerated the vesting period for retirement-eligible employees for purposes of recognizing compensation expense in accordance with the vesting provisions of the Company’s stock-based compensation programs for awards issued after the adoption of SFAS No. 123(R). The Company used an annual forfeiture rate ranging from 0% to 7.2% based on approximately ten years of the Company’s history for this type of award to various employee groups.

There were no restricted stock awards granted during the first six months of 2008. During the first six months of 2008, 400,254 restricted stock awards vested with a weighted-average grant date per share value of $16.23. Compensation expense recorded for all unvested restricted stock awards for the first six months of 2008 and 2007 was $1.0 million and $1.8 million, respectively.

Restricted Stock Units

Restricted stock units are granted from time to time to non-employee directors of the Company. The fair value of these units is measured at the average of the high and low stock price on grant date and compensation expense is recorded immediately. These units immediately vest and are paid out when the director ceases to be a director of the Company.

During the first half of 2008, 15,360 restricted stock units were granted with a grant date per share value of $48.96, and 19,602 restricted stock units were issued to a retiring director with a grant date per share value of $26.02. The compensation cost, which reflects the total fair value of these units, recorded in the first half of 2008 was $0.8 million. During the first half of 2007, the Company recorded $0.9 million of expense related to restricted stock units.

Stock Options

Stock option awards are granted with an exercise price equal to the fair market price (defined as the average of the high and low trading prices of the Company’s stock at the date of grant) of the Company’s stock on the date of grant. The grant date fair value of a stock option is calculated by using a Black-Scholes model. Compensation cost is recorded based on a graded-vesting schedule as the options vest over a service period of three years, with one-third of the award becoming exercisable each year on the anniversary date of the grant. Stock options have a maximum contractual term of five years. No forfeiture rate is assumed for stock options granted to directors due to the forfeiture rate history for these types of awards for this group of individuals.

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During the first six months of 2008 and 2007, there were no stock options granted. Compensation expense recorded during the first six months of 2008 and 2007 for amortization of stock options was less than $0.1 million and $0.1 million, respectively.

Stock Appreciation Rights

During the first six months of 2008, the Compensation Committee granted 119,130 SARs to employees. These awards allow the employee to receive any intrinsic value over the $48.48 grant date fair market value that may result from the price appreciation on a set number of common shares during the contractual term of seven years. All of these awards have graded-vesting features and will vest over a service period of three years, with one-third of the award becoming exercisable each year on the anniversary date of the grant. As these SARs are paid out in stock, rather than in cash, the Company calculates the fair value in the same manner as stock options, by using a Black-Scholes model.

The assumptions used in the Black-Scholes fair value calculation for SARs are as follows:

	Six Months Ended June 30, 2008
Weighted-Average Value per Stock Appreciation Right Granted During the Period (1)	$	15.18
Assumptions
Stock Price Volatility		34.4	%
Risk Free Rate of Return		2.8	%
Expected Dividend		0.2	%
Expected Term (in years)		4.25

⁽¹⁾ Calculated using the Black-Scholes fair value based method.

Compensation expense recorded during the first half of 2008 and 2007 for SARs was $1.2 million and $1.0 million, respectively. Included in these amounts were $0.5 million in each period related to the immediate expensing of shares granted in 2008 and 2007 to retirement-eligible employees.

Performance Share Awards

During 2008, the Compensation Committee granted three types of performance share awards to employees for a total of 383,065 performance shares. The performance period for two of these awards commenced on January 1, 2008 and ends December 31, 2010. Both of these awards vest at the end of the three year performance period.

Awards totaling 101,830 performance shares are earned, or not earned, based on the comparative performance of the Company’s common stock measured against sixteen other companies in the Company’s peer group over a three year performance period. The grant date per share value of the equity portion of this award was $41.53. Depending on the Company’s performance, employees may receive an aggregate of up to 100% of the fair market value of a share of common stock payable in common stock plus up to 100% of the fair market value of a share of common stock payable in cash.

Awards totaling 191,400 performance shares are earned, or not earned, based on the Company’s internal performance metrics rather than performance compared to a peer group. The grant date per share value of this award was $48.48. These awards represent the right to receive up to 100% of the award in shares of common stock. The actual number of shares issued at the end of the performance period will be determined based on the Company’s performance against three performance criteria set by the Company’s Compensation Committee. An employee will earn one-third of the award granted for each internal performance metric that the Company meets at the end of the performance period. These performance criteria measure the Company’s average production, average finding costs and average reserve replacement over three years. Based on the Company’s probability assessment at June 30, 2008, it is currently considered probable that these three criteria will be met.

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The third performance share award, totaling 89,835 performance shares, with a grant date per share value of $48.48, has a three-year graded vesting schedule, vesting one-third on each anniversary date following the date of grant, provided that the Company has positive operating income for the year preceding the vesting date. If the Company does not have positive operating income for the year preceding a vesting date, then the portion of the performance shares that would have vested on that date will be forfeited. As of June 30, 2008, it is currently considered probable that this performance metric will be met.

For all performance share awards granted to employees in 2008 and 2007, an annual forfeiture rate ranging from 0% to 4.5% has been assumed based on the Company’s history for this type of award to various employee groups.

For awards that are based on the internal metrics (performance condition) of the Company and for awards that were granted prior to the adoption of SFAS No. 123(R) on January 1, 2006, fair value is measured based on the average of the high and low stock price of the Company on grant date and expense is amortized over the three year vesting period. To determine the fair value for awards that were granted after January 1, 2006 that are based on the Company’s comparative performance against a peer group (market condition), the equity and liability components are bifurcated. On the grant date, the equity component was valued using a Monte Carlo binomial model and is amortized on a straight-line basis over three years. The liability component is valued at each reporting period by using a Monte Carlo binomial model.

The three primary inputs for the Monte Carlo model are the risk-free rate, volatility of returns and correlation in movement of total shareholder return. The risk-free rate was generated from the Federal Reserve website for constant maturity treasuries for six-month, one, two and three year bonds and is set equal to the yield, for the period over the remaining duration of the performance period, on treasury securities as of the reporting date. Volatility was set equal to the annualized daily volatility measured over a historic four year period ending on the reporting date. Correlation in movement of total shareholder return was determined based on a correlation matrix that was created which identifies total shareholder return correlations for each pair of companies in the peer group, including the Company. The paired returns in the correlation matrix ranged from approximately 43% to approximately 76% for the Company and its peer group. Based on these inputs discussed above, a ranking was projected identifying the Company’s rank relative to the peer group for each award period.

The following assumptions were used as of June 30, 2008 for the Monte Carlo model to value the liability components of the peer group measured performance share awards. The equity portion of the award was valued on the date of grant using the Monte Carlo model and this portion is not marked to market.

	June 30, 2008
Risk Free Rate of Return	2.2% - 2.8%
Stock Price Volatility	37.4% - 41.1%
Expected Dividend	0.2%

The Monte Carlo value per share for the liability component for all outstanding market condition performance share awards ranged from $19.61 to $44.60 at June 30, 2008. The long-term liability for all market condition performance share awards, included in Other Liabilities in the Condensed Consolidated Balance Sheet, at June 30, 2008 and December 31, 2007 was $1.3 million and $0.2 million, respectively. The short-term liability, included in Accrued Liabilities in the Condensed Consolidated Balance Sheet, at June 30, 2008 and December 31, 2007, for certain market condition performance share awards was $3.9 million and $5.5 million, respectively.

During the first half of 2008, 238,590 performance shares vested. Of these vested shares, 207,800 shares were granted in 2005 and were market condition awards which provided that employees may receive an

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aggregate of up to 100% of a share of common stock payable in common stock plus up to 100% of the fair market value of a share of common stock payable in cash. As a result of the Company’s ranking on the vesting date, 100% of the shares were paid in common stock and an additional 67% of the fair market value of each share of common stock, or $7.9 million, was paid in cash during the second quarter of 2008. The remaining 30,790 shares that vested in the first half of 2008 represent one-third of the three-year graded vesting schedule performance share awards granted in 2007 with a grant date per share value of $35.22. These awards met the performance criteria that the Company had positive operating income for the 2007 year.

Total compensation cost recognized for both the equity and liability components of all performance share awards as well as expense related to the shares deferred into the rabbi trust (discussed above in Note 7 of the Notes to the Condensed Consolidated Financial Statements) during the six months ended June 30, 2008 and 2007 was $20.5 million and $6.9 million, respectively.

Supplemental Employee Incentive Plan

On January 16, 2008, the Company’s Board of Directors adopted a Supplemental Employee Incentive Plan. The plan is intended to provide a compensation tool tied to stock market value creation to serve as an incentive and retention vehicle for full-time non-officer employees by providing for cash payments in the event the Company’s common stock reaches a specified trading price.

The bonus payout is triggered if, for any 20 trading days (which need not be consecutive) that fall within a period of 60 consecutive trading days occurring on or before November 1, 2011, the closing price per share of the Company’s common stock equals or exceeds the price goal of $60 per share. In such event, the 20th trading day on which such price condition is attained is the “Final Trigger Date.” The price goal is subject to adjustment by the Compensation Committee to reflect any stock splits, stock dividends or extraordinary cash distributions to stockholders. Under the plan, each eligible employee will receive a minimum distribution of 50% of his or her base salary as of the Final Trigger Date, as adjusted for persons hired after December 31, 2007 to reflect calendar quarters of service, reduced by any interim distribution previously paid to such employee upon the achievement of the interim price goal discussed below. The Committee may, in its discretion, allocate to eligible employees additional distributions, subject to limitations of the plan.

The plan also provides that an interim distribution will be paid to eligible employees upon achieving the interim price goal of $50 per share prior to December 31, 2009. Interim distributions are determined as described above except that interim distributions will be based on 10%, rather than 50%, of salary.

On the January 16, 2008 adoption date of the plan, the Company’s closing stock price was $40.71. On April 8, 2008, the Company achieved the interim target goal of $50 per share for 20 out of 60 consecutive trading days and a distribution totaling $3.1 million was paid to employees on April 17, 2008. On June 2, 2008, the Company achieved the final target goal of $60 per share for 20 out of 60 consecutive trading days and a distribution totaling $12.6 million was paid to employees on June 19, 2008. During the second quarter of 2008, the Company recorded $11.2 million in expense primarily associated with this final distribution. No further distributions will be made under this plan.

These awards have been accounted for as liability awards under SFAS No. 123(R), and the total expense for the first half of 2008 was $15.7 million.

On July 24, 2008, the Company’s Board of Directors adopted a second Supplemental Employee Incentive Plan (“Plan II”). Plan II is also intended to provide a compensation tool tied to stock market value creation to serve as an incentive and retention vehicle for full-time non-officer employees by providing for cash payments in the event the Company’s common stock reaches a specified trading price. These awards will be accounted for as liability awards under SFAS No. 123(R).

Plan II provides for a final payout if, for any 20 trading days (which need not be consecutive) that fall within a period of 60 consecutive trading days ending on or before June 20, 2012, the closing price per

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share of the Company’s common stock equals or exceeds the price goal of $105 per share. In such event, the 20th trading day on which such price condition is attained is the “Final Trigger Date.” The price goal is subject to adjustment by the Compensation Committee to reflect any stock splits, stock dividends or extraordinary cash distributions to stockholders. Under Plan II, each eligible employee may receive (upon approval by the Compensation Committee) a distribution of 50% of his or her base salary as of the Final Trigger Date (or 30% of base salary if the Company paid interim distributions upon the achievement of the interim price goal discussed below).

Plan II provides that a distribution of 20% of an eligible employee’s base salary as of the Interim Trigger Date will be made (upon approval by the Compensation Committee) upon achieving the interim price goal of $85 per share on or before June 30, 2010. Interim distributions are determined as described above except that interim distributions will be based on 20%, rather than 50%, of salary.

The Compensation Committee can increase the 50% or 20% payment as it applies to any employee.

Payments under either the interim or final distribution will occur as follows:

• 25% of the total distribution paid on the 15^th business day following the interim or final trigger date, as applicable, and

• 75% of the total distribution paid based on the following deferred payment dates in the table below:

Period During which the Trigger Date Occurs	Deferred Payment Date
July 1, 2008 to June 30, 2009	The business day on or next following the 18 month anniversary of the applicable Trigger Date
July 1, 2009 to June 30, 2010	The business day on or next following the 12 month anniversary of the applicable Trigger Date
July 1, 2010 to December 31, 2010	The business day on or next following the 6 month anniversary of the applicable Trigger Date
January 1, 2011 to June 30, 2012	No deferral; entire payment is made on the 15th business day following the applicable Trigger Date

Any deferred portion will only be paid if the participant is employed by the Company, or has terminated employment by reason of retirement, death or disability (as provided in Plan II). Payments are subject to certain other restrictions contained in Plan II.

12. CAPITAL STOCK

On June 20, 2008, the Company entered into an underwriting agreement, pursuant to which the Company sold an aggregate of 5,002,500 shares of common stock at a price to the Company of $62.66 per share. This aggregate share amount included 652,500 shares of common stock that were issued as a result of the exercise of the underwriters’ option to purchase additional shares. On June 25, 2008, the Company closed the public offering and received $313.5 million in net proceeds, after deducting underwriting discounts and commissions. These net proceeds were used temporarily to reduce outstanding borrowings under the Company’s revolving credit facility pending the anticipated application to fund a portion of the purchase price of the Company’s East Texas acquisition.

Immediately prior to (and in connection with) this issuance, the Company retired 5,002,500 shares of its treasury stock, which had a weighted-average purchase price of $16.46, representing $82.3 million. In accordance with the Company’s policy, the excess of cost of the treasury stock over its par value was charged entirely to additional paid-in capital.

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Report of Independent Registered Public Accounting Firm

To the Board of Directors and Stockholders of

Cabot Oil & Gas Corporation:

We have reviewed the accompanying condensed consolidated balance sheet of Cabot Oil & Gas Corporation and its subsidiaries (the Company) as of June 30, 2008, the related condensed consolidated statements of operations for the three-month and six-month periods ended June 30, 2008 and 2007, and the condensed consolidated statements of cash flows for the six-month periods ended June 30, 2008 and 2007. These interim financial statements are the responsibility of the Company’s management.

We conducted our review in accordance with the standards of the Public Company Accounting Oversight Board (United States). A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the Public Company Accounting Oversight Board (United States), the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.

Based on our review, we are not aware of any material modifications that should be made to the accompanying condensed consolidated interim financial statements for them to be in conformity with accounting principles generally accepted in the United States of America.

We previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) the consolidated balance sheet as of December 31, 2007, and the related consolidated statements of operations, of comprehensive income, of stockholders’ equity, and of cash flows for the year then ended (not presented herein), and in our report dated February 27, 2008, which included an explanatory paragraph related to the adoptions of FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes, an interpretation of FASB Statement No. 109,” Statement of Financial Accounting Standards No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106, and 132(R),” and Statement of Financial Accounting Standards No. 123R, “Share Based Payment (revised 2004),” we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying condensed consolidated balance sheet information as of December 31, 2007, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.

/s/ PricewaterhouseCoopers LLP

Houston, Texas

July 29, 2008

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ITEM 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following review of operations for the three and six month periods ended June 30, 2008 and 2007 should be read in conjunction with our Condensed Consolidated Financial Statements and the Notes included in this Form 10-Q and with the Consolidated Financial Statements, Notes and Management’s Discussion and Analysis included in the Cabot Oil & Gas Annual Report on Form 10-K for the year ended December 31, 2007.

Overview

Operating revenues for the six months ended June 30, 2008 increased by $101.1 million, or 28%, from the six months ended June 30, 2007. Natural gas production revenues increased by $78.3 million, or 27%, for the six months ended June 30, 2008 as compared to the six months ended June 30, 2007 due to an increase in realized natural gas prices in all regions and an overall increase in natural gas production. Crude oil and condensate revenues increased by $10.9 million, or 45%, for the first six months of 2008 as compared to the first six months of 2007 due to an increase in realized crude oil prices in all regions, slightly offset by a decrease in crude oil production, primarily in the Gulf Coast and, to a lesser extent, in the West. Brokered natural gas revenues increased by $11.6 million due to an increase in sales price as well as an increase in brokered volumes.

Our average realized natural gas price for the first half of 2008 was $8.63 per Mcf, 18% higher than the $7.33 per Mcf price realized in the same period of the prior year. Our average realized crude oil price was $92.58 per Bbl, 60% higher than the $57.76 per Bbl price realized in the same period of the prior year. These realized prices include realized gains and losses resulting from commodity derivatives (zero-cost collars or swaps). For information about the impact of these derivatives on realized prices, refer to the “Results of Operations” section. Commodity prices are determined by many factors that are outside of our control. Historically, commodity prices have been volatile and we expect them to remain volatile. Commodity prices are affected by changes in market supply and demand, which are impacted by overall economic activity, weather, pipeline capacity constraints, inventory storage levels, basis differentials and other factors. As a result, we cannot accurately predict future natural gas, NGL and crude oil prices and, therefore, we cannot accurately predict revenues.

On an equivalent basis, our production level for the first six months of 2008 increased by eight percent from the first six months of 2007. For the six months ended June 30, 2008, we produced 45.4 Bcfe compared to production of 42.2 Bcfe for the comparable period of the prior year. Natural gas production was 43.1 Bcf and oil production was 379 Mbbls for the first half of 2008. Natural gas production increased by nine percent when compared to the comparable period of the prior year, which had production of 39.7 Bcf. This increase was primarily a result of increased natural gas production in the Gulf Coast region due to increased drilling in the County Line and Minden fields, as well as increased production in the West region associated with an increase in the drilling program and an increase in Canada due to increased drilling activity in the Hinton field. Oil production decreased by 40 Mbbls, or 10%, from 419 Mbbls in the first half of 2007 to 379 Mbbls produced in the first half of 2008. This was primarily the result of a decrease of 29 Mbbls in the Gulf Coast region as well as 11 Mbbls in the West region due to natural decline.

We had net income of $100.6 million, or $1.03 per share, for the six months ended June 30, 2008 compared to net income of $89.9 million, or $0.93 per share, for the comparable period of the prior year. The increase in net income is primarily due to the increase in natural gas and, to a lesser extent, crude oil revenues, partially offset by higher operating expenses and an $11.9 million lower gain on sale of assets in 2008. Operating revenues increased by $101.1 million as discussed above. Operating expenses increased by $68.4 million in the first half of 2008 as compared to the first half of 2007, primarily due to increased general and administrative expenses resulting from higher stock compensation expense, higher depreciation, depletion and amortization (DD&A) and, to a lesser extent, higher taxes other than income and brokered natural gas costs. These impacts, along with a $4.7 million increase in interest and other expenses, increased income before taxes by $16.1 million and consequently increased income tax expense by $5.4 million.

In addition to production volumes and commodity prices, finding and developing sufficient amounts of crude oil and natural gas reserves at economical costs are critical to our long-term success. In 2008, we expect to spend approximately $750 million in capital and exploration expenditures, up $260 million from $490 million which was disclosed in our Annual Report on Form 10-K for the year ended December 31, 2007 (Form 10-K). This

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incremental increase includes additional planned drilling activity and lease acquisition investments. We believe our cash on hand (including proceeds from our private placement of debt completed in July 2008 not used to fund the East Texas acquisition described below) and operating cash flow in 2008 will be sufficient to fund a substantial portion of our budgeted capital and exploration spending. Any additional needs will be funded by borrowings from our credit facility. For the six months ended June 30, 2008, approximately $385.7 million has been invested in our exploration and development efforts.

During the first half of 2008, we drilled 201 gross wells (196 development, three exploratory and two extension wells) with a success rate of 99% compared to 222 gross wells (215 development, four exploratory and three extension wells) with a success rate of 98% for the comparable period of the prior year. For the full year of 2008, we plan to drill over 500 gross wells.

We remain focused on our strategies of pursuing lower risk drilling opportunities that provide more predictable results on our accumulated acreage position. Additionally, we will continue to add to our acreage position in certain areas for future drilling opportunities. We believe these strategies are appropriate for our portfolio of projects and the current industry environment and that this activity will continue to add shareholder value over the long term.

In June 2008, we entered into a purchase and sale agreement to acquire producing properties, leasehold acreage and a natural gas gathering infrastructure in East Texas for approximately $602.8 million. In order to finance the East Texas acquisition and repay borrowings under our revolving credit facility, we completed a public offering of our common stock in June 2008 and received net proceeds of $313.5 million.

In July 2008, we closed a private placement of $425 million principal amount of senior unsecured fixed rate notes (see Note 4 of the Notes to the Condensed Consolidated Financial Statements for further details).

The preceding paragraphs, discussing our strategic pursuits and goals, contain forward-looking information. Please read “Forward-Looking Information” for further details.

Financial Condition

Capital Resources and Liquidity

Our primary sources of cash for the six months ended June 30, 2008 were from funds generated from the sale of common stock and the sale of natural gas and crude oil production. Cash flows provided by operating activities and the sale of common stock were primarily used to fund our development and, to a lesser extent, exploratory expenditures, to repay debt under our revolving credit facility and to pay dividends. See below for additional discussion and analysis of cash flow.

We generate cash from the sale of natural gas and crude oil. Operating cash flow fluctuations are substantially driven by commodity prices and changes in our production volumes. Prices for crude oil and natural gas have historically been volatile, including seasonal influences characterized by peak demand and higher prices in the winter heating season; however, the impact of other risks and uncertainties, as described in our Form 10-K, have also influenced prices throughout the recent years. In addition, fluctuations in cash flow may result in an increase or decrease in our capital and exploration expenditures. See “Results of Operations” for a review of the impact of prices and volumes on sales.

Our working capital is also substantially influenced by these variables discussed above. From time to time, our working capital will reflect a surplus, while at other times it will reflect a deficit. This fluctuation is not unusual. We believe we have adequate liquidity available to meet our working capital requirements.

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	Six Months Ended June 30,
(In thousands)	2008			2007
Cash Flows Provided by Operating Activities	$	276,411		$	241,807
Cash Flows Used in Investing Activities		(383,812	)		(278,583	)
Cash Flows Provided by Financing Activities		225,234			18,513
Net Increase / (Decrease) in Cash and Cash Equivalents	$	117,833		$	(18,263	)

Operating Activities. Net cash provided by operating activities in the first half of 2008 increased by $34.6 million over the comparable period in 2007. This increase is primarily due to the increase in net income as well as working capital changes. Key components impacting net operating cash flows are commodity prices, production volumes and operating costs. Average realized crude oil prices increased by 60% for the first half of 2008 versus the 2007 period and average realized natural gas prices increased by 18% over the same period. Equivalent production volumes increased by approximately eight percent in the first six months of 2008 compared to the first six months of 2007 as a result of higher natural gas production. We are unable to predict future commodity prices and, as a result, cannot provide any assurance about future levels of net cash provided by operating activities.

Investing Activities. The primary uses of cash in investing activities were capital spending and exploration expenses. We established the budget for these amounts based on our current estimate of future commodity prices. Due to the volatility of commodity prices and new opportunities which may arise, our capital expenditures may be periodically adjusted during any given year. Cash flows used in investing activities increased by $105.2 million from the first six months of 2007 compared to the first six months of 2008. The increase from 2007 to 2008 is due to an increase of $100.7 million in capital expenditures, including approximately $60 million related to acquisition activities. Additionally, there were $4.6 million of lower proceeds from the sale of assets, partially offset by reduced exploration expenditures of $0.1 million.

Financing Activities. Cash flows provided by financing activities were $225.2 million for the first half of 2008, and included net proceeds from the sale of common stock issued in our public offering and proceeds from the exercise of stock options, partially offset by a net decrease in borrowings under our revolving credit facility and dividend payments. Cash flows provided by financing activities were $18.5 million for the first half of 2007, and were comprised of a net increase in borrowings under our revolving credit facility, proceeds from the exercise of stock options and the tax benefit received from stock-based compensation, partially offset by dividend payments.

At June 30, 2008, we had $55 million of borrowings outstanding under our credit facility at a weighted-average interest rate of 4.3%. The credit facility provides for an available credit line of $350 million. In June 2008, we amended our revolving credit facility agreement to increase the commitments of the lenders to $350 million from $250 million pursuant to the accordion feature in the agreement. The available credit line is subject to adjustment on the basis of the present value of estimated future net cash flows from proved oil and gas reserves (as determined by the banks’ petroleum engineer) and other assets. The revolving term of the credit facility ends in December 2009 and is unsecured. We strive to manage our debt at a level below the available credit line in order to maintain excess borrowing capacity. Our revolving credit facility includes a covenant limiting our total debt. In conjunction with the June 2008 amendment of our revolving credit facility, our total debt limit was increased from $610 million to $1.2 billion. Management believes that we have the ability to finance through new debt or equity offerings, if necessary, our capital requirements, including potential acquisitions.

In June 2008, we entered into an underwriting agreement pursuant to which we sold an aggregate of 5,002,500 shares of common stock at a price to the Company of $62.66 per share. This aggregate share amount included 652,500 shares of common stock that were issued as a result of the exercise of the underwriters’ option to purchase additional shares. We received $313.5 million in net proceeds, after deducting underwriting discounts and commissions. These net proceeds were used temporarily to reduce outstanding borrowings under our revolving credit facility pending the anticipated application to fund a portion of the purchase price of our East Texas acquisition.

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Immediately prior to (an in connection with) this issuance, we retired 5,002,500 shares of treasury stock, which had a weighted-average purchase price of $16.46.

Our Board of Directors has authorized a share repurchase program under which we may purchase shares of our common stock in the open market or in negotiated transactions. There is no expiration date associated with the authorization. During the six months ended June 30, 2008, we did not repurchase any shares of our common stock. All purchases executed to date have been through open market transactions. The maximum number of shares that may yet be purchased under the plan as of June 30, 2008 was 4,795,300. See “Unregistered Sales of Equity Securities and Use of Proceeds – Issuer Purchases of Equity Securities” in Item 2 of Part II of this quarterly report.

Capitalization

Information about our capitalization is as follows:

(Dollars in millions)	June 30, 2008			December 31, 2007
Debt (1)	$	265.0		$	350.0
Stockholders’ Equity		1,299.3			1,070.3
Total Capitalization	$	1,564.3		$	1,420.3
Debt to Capitalization		17	%		25	%
Cash and Cash Equivalents	$	136.3		$	18.5

⁽¹⁾ Includes $20.0 million of current portion of long-term debt at both June 30, 2008 and December 31, 2007. Includes $55 million and $140 million of borrowings outstanding under our revolving credit facility at June 30, 2008 and December 31, 2007, respectively. Excludes $425 million principal amount of debt incurred in July 2008.

During the six months ended June 30, 2008, we paid dividends of $5.9 million ($0.03 per share) on our common stock. A regular dividend has been declared for each quarter since we became a public company in 1990.

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Capital and Exploration Expenditures

On an annual basis, we generally fund most of our capital and exploration activities, excluding any significant oil and gas property acquisitions, with cash generated from operations and, when necessary, our revolving credit facility. We budget these capital expenditures based on our projected cash flows for the year.

The following table presents major components of capital and exploration expenditures for the six months ended June 30, 2008 and 2007:

	Six Months Ended June 30,
(In millions)	2008		2007
Capital Expenditures
Drilling and Facilities	$	232.1	$	256.5
Leasehold Acquisitions		50.2		11.5
Acquisitions		79.3		—
Pipeline and Gathering		8.2		10.4
Other		3.5		9.2
		373.3		287.6
Exploration Expense		12.4		12.5
Total	$	385.7	$	300.1

For the full year of 2008, we plan to drill over 500 gross wells. This drilling program includes approximately $750 million in total capital and exploration expenditures, up from $636.2 million in 2007. See the “Overview” discussion for additional information regarding the current year drilling program. We will continue to assess the natural gas and crude oil price environment and may increase or decrease the capital and exploration expenditures accordingly.

Contractual Obligations

At June 30, 2008, we were obligated to make future payments under drilling rig commitments and firm gas transportation agreements as disclosed in our Annual Report on Form 10-K for the year ended December 31, 2007. For further information, please refer to “Firm Gas Transportation Agreements” and “Drilling Rig Commitments” under Note 6 in the Notes to the Condensed Consolidated Financial Statements.

Critical Accounting Policies and Estimates

Our discussion and analysis of our financial condition and results of operations are based upon condensed consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted and adopted in the United States. The preparation of these financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses. See our Annual Report on Form 10-K for the year ended December 31, 2007, for further discussion of our critical accounting policies.

Statement of Financial Accounting Standards (SFAS) No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities, including an amendment of FASB Statement No. 115,” became effective on January 1, 2008 and permits companies to choose, at specified dates, to measure certain eligible financial instruments at fair value. The provisions of SFAS No. 159 apply only to entities that elect to use the fair value option and to all entities with available-for-sale and trading securities. At the effective date, companies may elect the fair value option for eligible items that exist at that date, and the effect of the first remeasurement to fair value must be reported as a cumulative-effect adjustment to the opening balance of retained earnings. Since we did not elect to adopt the fair value option for eligible items, SFAS No. 159 has not had an impact on our financial position or results of operations.

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Effective January 1, 2008, we adopted those provisions of SFAS No. 157, “Fair Value Measurements,” that were required to be adopted. This adoption did not have a material impact on any of our financial statements. Additional disclosures are required for transactions measured at fair value and we have included these disclosures in Note 7 of the Notes to the Condensed Consolidated Financial Statements.

As defined in SFAS No. 157, fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). The transaction is based on a hypothetical transaction in the principal or most advantageous market considered from the perspective of the market participant that holds the asset or owes the liability.

We utilize market data or assumptions that market participants who are independent, knowledgeable and willing and able to transact would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. We attempt to utilize valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. We are able to classify fair value balances based on the observability of those inputs. SFAS No. 157 establishes a formal fair value hierarchy based on the inputs used to measure fair value. The hierarchy gives the highest priority level 1 measurements and the lowest priority to level 3 measurements, and accordingly, level 1 measurements should be used whenever possible.

The three levels of the fair value hierarchy as defined by SFAS No. 157 are as follows:

• Level 1: Valuations utilizing quoted, unadjusted prices for identical assets or liabilities in active markets that we have the ability to access. This is the most reliable evidence of fair value and does not require a significant degree of judgment. Examples include exchange-traded derivatives and listed equities that are actively traded.

• Level 2: Valuations utilizing quoted prices in markets that are not considered to be active or financial instruments for which all significant inputs are observable, either directly or indirectly for substantially the full term of the asset or liability. Financial instruments that are valued using models or other valuation methodologies are included. Models used should primarily be industry-standard models that consider various assumptions and economic measures, such as interest rates, yield curves, time value, volatilities, contract terms, current market prices, credit risk or other market-corroborated inputs. Examples include most over-the-counter derivatives (non-exchange traded), physical commodities, most structured notes and municipal and corporate bonds.

• Level 3: Valuations utilizing significant, unobservable inputs. This provides the least objective evidence of fair value and requires a significant degree of judgment. Inputs may be used with internally developed methodologies and should reflect an entity’s assumptions using the best information available about the assumptions that market participants would use in pricing an asset or liability. Examples include certain corporate loans, real-estate and private equity investments and long-dated or complex over-the-counter derivatives.

Per SFAS No. 157, we have classified our assets and liabilities into these levels depending upon the data relied on to determine the fair values. The determination of fair value incorporates various factors required under SFAS No. 157. These factors include not only the credit standing of the counterparties involved, but also the impact of our nonperformance risk on our liabilities.

The fair values of our natural gas and crude oil price collars and swaps are valued based upon quotes obtained from counterparties to the agreements and are designated as Level 3. The total Level 3 liabilities were $282.8 million at June 30, 2008. We did not have any Level 3 assets at June 30, 2008. The derivative contracts were measured based on quotes from our counterparties. Such quotes have been derived using a Black-Scholes model that considers various inputs including current market and contractual prices for the underlying instruments, quoted forward prices for natural gas and crude oil, volatility factors and interest rates, such as a LIBOR curve for a similar length of time as the derivative contract term. Although we utilize multiple quotes to assess the reasonableness of our values, we have not attempted to obtain sufficient corroborating market evidence to support classifying these derivative contracts as Level 2. Our nonperformance risk was evaluated using a market credit spread provided by our bank.

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Results of Operations

Second Quarters of 2008 and 2007 Compared

We reported net income in the second quarter of 2008 of $54.6 million, or $0.55 per share. For the corresponding quarter of 2007, we reported net income of $41.4 million, or $0.43 per share. Net income increased in the second quarter of 2008 by $13.2 million, primarily due to an increase in operating revenues partially offset by an increase in operating and income tax expenses and a decrease in gain on sale of assets. Operating revenues increased by $73.0 million, largely due to increases in both natural gas production and brokered revenues, and crude oil and condensate revenues. Operating expenses increased by $45.1 million between quarters largely due to increased general and administrative expenses resulting from higher stock compensation, increased DD&A, higher brokered natural gas costs and, to a lesser extent, taxes other than income. In addition, net income was impacted by a decrease in gain on sale of assets of $4.0 million as well as an increase in expenses of $10.7 million resulting from a combination of higher income tax expense and interest and other expenses. Income tax expense was higher in the 2008 period as a result of increased income before income taxes in the second quarter of 2008 period compared to the second quarter of 2007 offset by a slight decrease in the effective tax rate.

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Natural Gas Production Revenues

Our average total company realized natural gas production sales price, including the realized impact of derivative instruments, was $9.30 per Mcf for the three months ended June 30, 2008 compared to $7.24 per Mcf for the comparable period of the prior year. These prices include the realized impact of derivative instrument settlements, which decreased the price by $0.97 per Mcf in 2008 and increased the price by $0.66 per Mcf in 2007. The following table excludes the unrealized loss from the change in derivative fair value of $2.9 million, which has been included within Natural Gas Production Revenues in the Condensed Consolidated Statement of Operations for the quarter ended June 30, 2008. There was no revenue impact from the unrealized change in natural gas derivative fair value for the three months ended June 30, 2007.

	Three Months Ended June 30,					Variance
	2008			2007		Amount			Percent
Natural Gas Production (Mmcf)
East		5,935			6,166		(231	)	(4	)%
Gulf Coast		7,711			6,455		1,256		19	%
West		7,115			6,364		751		12	%
Canada		1,343			930		413		44	%
Total Company		22,104			19,915		2,189		11	%
Natural Gas Production Sales Price ($/Mcf)
East	$	9.64		$	7.86	$	1.78		23	%
Gulf Coast	$	10.36		$	8.27	$	2.09		25	%
West	$	8.04		$	6.02	$	2.02		34	%
Canada	$	8.41		$	4.25	$	4.16		98	%
Total Company	$	9.30		$	7.24	$	2.06		28	%
Natural Gas Production Revenue (In thousands)
East	$	57,212		$	48,488	$	8,724		18	%
Gulf Coast		79,874			53,404		26,470		50	%
West		57,222			38,283		18,939		49	%
Canada		11,290			3,953		7,337		186	%
Total Company	$	205,598		$	144,128	$	61,470		43	%
Price Variance Impact on Natural Gas Production Revenue (In thousands)
East	$	10,541
Gulf Coast		16,080
West		14,419
Canada		5,581
Total Company	$	46,621
Volume Variance Impact on Natural Gas Production Revenue (In thousands)
East	$	(1,817	)
Gulf Coast		10,390
West		4,520
Canada		1,756
Total Company	$	14,849

The increase in Natural Gas Production Revenue of $61.5 million is due to the increase in realized natural gas sales prices in addition to an increase in natural gas production. Natural gas production in the Gulf Coast region increased due to drilling in the County Line and Minden fields. In addition, natural gas production increased in the West region associated with an increase in the drilling program and increased in Canada due to increased drilling activity in the Hinton field. These increases were partially offset by a natural decline in natural gas production in the East region.

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Brokered Natural Gas Revenue and Cost

	Three Months Ended June 30,					Variance
	2008			2007		Amount		Percent
Sales Price ($/Mcf)	$	12.15		$	8.68	$	3.47	40	%
Volume Brokered (Mmcf)	x	2,237		x	2,075		162	8	%
Brokered Natural Gas Revenues (In thousands)	$	27,188		$	18,001
Purchase Price ($/Mcf)	$	10.79		$	7.74	$	3.05	39	%
Volume Brokered (Mmcf)	x	2,237		x	2,075		162	8	%
Brokered Natural Gas Cost (In thousands)	$	24,140		$	16,051
Brokered Natural Gas Margin (In thousands)	$	3,048		$	1,950	$	1,098	56	%
(In thousands)
Sales Price Variance Impact on Revenue	$	7,804
Volume Variance Impact on Revenue		1,430
	$	9,234
(In thousands)
Purchase Price Variance Impact on Purchases	$	(6,883	)
Volume Variance Impact on Purchases		(1,253	)
	$	(8,136	)

The increased brokered natural gas margin of $1.1 million is a result of an increase in sales price that outpaced the increase in purchase price as well as an increase in the volumes brokered in the second quarter of 2008 over the same period in the prior year.

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Crude Oil and Condensate Revenues

Our average total company realized crude oil sales price, including the realized impact of derivative instruments, was $98.68 per Bbl for the second quarter of 2008 compared to $61.98 per Bbl for the second quarter of 2007. These prices include the realized impact of derivative instrument settlements, which decreased the price by $21.19 per Bbl in 2008. There was no realized impact of derivative instrument settlements in the second quarter of 2007. There was no revenue impact from the unrealized change in crude oil and condensate derivative fair value for the three months ended June 30, 2008 or 2007.

	Three Months Ended June 30,					Variance
	2008			2007		Amount			Percent
Crude Oil Production (Mbbl)
East		6			7		(1	)	(14	)%
Gulf Coast		136			161		(25	)	(16	)%
West		42			42		—		—
Canada		5			4		1		25	%
Total Company		189			214		(25	)	(12	)%
Crude Oil Sales Price ($/Bbl)
East	$	118.33		$	59.41	$	58.92		99	%
Gulf Coast	$	91.87		$	62.28	$	29.59		48	%
West	$	118.18		$	62.76	$	55.42		88	%
Canada	$	96.89		$	48.51	$	48.38		100	%
Total Company	$	98.68		$	61.98	$	36.70		59	%
Crude Oil Revenue (In thousands)
East	$	684		$	397	$	287		72	%
Gulf Coast		12,456			9,985		2,471		25	%
West		4,961			2,654		2,307		87	%
Canada		499			227		272		120	%
Total Company	$	18,600		$	13,263	$	5,337		40	%
Price Variance Impact on Crude Oil Revenue (In thousands)
East	$	340
Gulf Coast		4,013
West		2,307
Canada		225
Total Company	$	6,885
Volume Variance Impact on Crude Oil Revenue (In thousands)
East	$	(53	)
Gulf Coast		(1,542	)
West		—
Canada		47
Total Company	$	(1,548	)

The increase in realized crude oil prices, partially offset by a decrease in production, resulted in a net revenue increase of $5.3 million. The decrease in oil production is mainly the result of a natural decline in crude oil production in the Gulf Coast region.

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Impact of Derivative Instruments on Operating Revenues

The following table reflects the realized impact of cash settlements and the net unrealized change in fair value of derivative instruments:

	Three Months Ended June 30,
	2008						2007
(In thousands)	Realized			Unrealized			Realized		Unrealized
Operating Revenues - Increase / (Decrease) to Revenue
Cash Flow Hedges
Natural Gas Production	$	(21,414	)	$	(2,909	)	$	13,126	$	—
Crude Oil		(4,004	)		—			—		—
Total Cash Flow Hedges	$	(25,418	)	$	(2,909	)	$	13,126	$	—

We are exposed to market risk on derivative instruments to the extent of changes in market prices of natural gas and oil. However, the market risk exposure on these derivative contracts is generally offset by the gain or loss recognized upon the ultimate sale of the commodity. Although notional contract amounts are used to express the volume of natural gas price agreements, the amounts that can be subject to credit risk in the event of non-performance by third parties are substantially smaller. We do not anticipate any material impact on our financial results due to non-performance by third parties.

Operating Expenses

Total costs and expenses from operations increased by $45.1 million in the second quarter of 2008 compared to the same period of 2007. The primary reasons for this fluctuation are as follows:

• General and Administrative expenses increased by $20.5 million in the second quarter of 2008 compared with the second quarter of 2007. This is primarily due to increased stock compensation expense related to the payout of the final bonus in our supplemental employee incentive plan that commenced in January 2008 as well as increased expense related to our performance shares.

• Depreciation, Depletion and Amortization increased by $8.2 million in the second quarter of 2008 compared with the second quarter of 2007. This is primarily due to the impact on the DD&A rate of higher capital costs and commencement of production in an East Texas field and Canada.

• Brokered Natural Gas Cost increased by $8.0 million from the second quarter of 2007 to the second quarter of 2008. See the preceding table titled “Brokered Natural Gas Revenue and Cost” for further analysis.

• Taxes Other Than Income increased by $4.6 million from the second quarter of 2007 to the second quarter of 2008 primarily due to higher production taxes as a result of higher operating revenues and, to a lesser extent, higher ad valorem taxes, partially offset by lower franchise taxes.

• Direct Operations expenses increased by $3.6 million from the second quarter of 2007 to the second quarter of 2008 primarily due to higher personnel and labor expenses, maintenance expenses, treating costs and compressor costs.

Interest Expense, Net

Interest expense, net increased by $2.7 million in the second quarter of 2008 primarily due to higher average credit facility borrowings and lower interest income from short-term investments, offset in part by a lower weighted-average interest rate on our revolving credit facility borrowings and lower outstanding borrowings on our 7.19% fixed rate debt. Weighted-average borrowings under our credit facility based on daily balances were approximately $206 million during the second quarter of 2008 compared to approximately $3 million during the second quarter of 2007. The weighted-average effective interest rate on the credit facility decreased to 4.5% in the second quarter of 2008 from 8.3% in the second quarter of 2007.

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Income Tax Expense

Income tax expense increased by $8.0 million due to a comparable increase in our pre-tax income. The effective tax rate for the second quarter of 2008 and 2007 was 37.8% and 37.9%, respectively. The decrease in the effective tax rate is primarily due to a reduction in our overall state income tax rate for 2008.

Six Months of 2008 and 2007 Compared

We reported net income in the first six months of 2008 of $100.6 million, or $1.03 per share. For the corresponding period of 2007, we reported net income of $89.9 million, or $0.93 per share. Net income increased in the first half of 2008 by $10.7 million, primarily due to an increase in operating revenues, partially offset by increased operating, interest and income tax expenses and a decrease in gain on sale of assets. Operating revenues increased by $101.1 million, largely due to increases in both natural gas production and brokered revenues and crude oil and condensate revenues. Operating expenses increased by $68.4 million between periods largely due to increased general and administrative expenses resulting from higher stock compensation, higher DD&A and, to a lesser extent, higher brokered natural gas costs and taxes other than income. In addition, net income was impacted by a decrease in gain on sale of assets of $11.9 million as well as an increase in expenses of $10.1 million resulting from a combination of increased income tax expense and interest and other expenses. Income tax expense was higher in the 2008 period as a result of higher income before income taxes in the first six months of 2008 compared to the first six months of 2007, partially offset by a slight decrease in the effective tax rate primarily due to a reduction in our overall state income tax liability.

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Natural Gas Production Revenues

Our average total company realized natural gas production sales price, including the realized impact of derivative instruments, was $8.63 per Mcf for the six months ended June 30, 2008 compared to $7.33 per Mcf for the comparable period of the prior year. These prices include the realized impact of derivative instrument settlements, which decreased the price by $0.48 per Mcf in 2008 and increased the price by $0.77 per Mcf in 2007. The following table excludes the unrealized loss from the change in derivative fair value of $2.9 million, which has been included within Natural Gas Production Revenues in the Condensed Consolidated Statement of Operations for the six months ended June 30, 2008. There was no revenue impact from the unrealized change in natural gas derivative fair value for the six months ended June 30, 2007.

	Six Months Ended June 30,				Variance
	2008		2007		Amount		Percent
Natural Gas Production (Mmcf)
East		11,935		11,923		12	—
Gulf Coast		15,116		12,934		2,182	17	%
West		13,481		12,822		659	5	%
Canada		2,589		2,002		587	29	%
Total Company		43,121		39,681		3,440	9	%
Natural Gas Production Sales Price ($/Mcf)
East	$	8.96	$	7.97	$	0.99	12	%
Gulf Coast	$	9.35	$	8.01	$	1.34	17	%
West	$	7.67	$	6.26	$	1.41	23	%
Canada	$	7.91	$	5.97	$	1.94	32	%
Total Company	$	8.63	$	7.33	$	1.30	18	%
Natural Gas Production Revenue (In thousands)
East	$	106,921	$	94,986	$	11,935	13	%
Gulf Coast		141,311		103,644		37,667	36	%
West		103,442		80,303		23,139	29	%
Canada		20,483		11,945		8,538	71	%
Total Company	$	372,157	$	290,878	$	81,279	28	%
Price Variance Impact on Natural Gas Production Revenue (In thousands)
East	$	11,839
Gulf Coast		20,181
West		19,009
Canada		5,033
Total Company	$	56,062
Volume Variance Impact on Natural Gas Production Revenue (In thousands)
East	$	96
Gulf Coast		17,486
West		4,130
Canada		3,505
Total Company	$	25,217

The increase in Natural Gas Production Revenue of $81.3 million is due to the increase in realized natural gas sales prices in addition to an increase in natural gas production. Natural gas production in the Gulf Coast region increased due to drilling in the County Line and Minden fields. In addition, natural gas production increased in the West region associated with an increase in the drilling program and increased in Canada due to increased drilling in the Hinton field.

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Brokered Natural Gas Revenue and Cost

	Six Months Ended June 30,					Variance
	2008			2007		Amount		Percent
Sales Price ($/Mcf)	$	10.49		$	8.86	$	1.63	18	%
Volume Brokered (Mmcf)	x	5,990		x	5,778		212	4	%
Brokered Natural Gas Revenues (In thousands)	$	62,808		$	51,178
Purchase Price ($/Mcf)	$	9.09		$	7.74	$	1.35	17	%
Volume Brokered (Mmcf)	x	5,990		x	5,778		212	4	%
Brokered Natural Gas Cost (In thousands)	$	54,430		$	44,750
Brokered Natural Gas Margin (In thousands)	$	8,378		$	6,428	$	1,950	30	%
(In thousands)
Sales Price Variance Impact on Revenue	$	9,800
Volume Variance Impact on Revenue		1,878
	$	11,678
(In thousands)
Purchase Price Variance Impact on Purchases	$	(8,087	)
Volume Variance Impact on Purchases		(1,641	)
	$	(9,728	)

The increased brokered natural gas margin of $2.0 million is a result of an increase in sales price that outpaced the increase in purchase price as well as an increase in the volumes brokered in the first half of 2008 over the same period in the prior year.

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Crude Oil and Condensate Revenues

Our average total company realized crude oil sales price, including the realized impact of derivative instruments, was $92.58 per Bbl for the first six months of 2008 compared to $57.76 per Bbl for the first six months of 2007. These prices include the realized impact of derivative instrument settlements, which decreased the price by $14.88 per Bbl in 2008 and increased the price by $0.43 per Bbl in 2007. There was no revenue impact from the unrealized change in crude oil and condensate derivative fair value for the six months ended June 30, 2008 or 2007.

	Six Months Ended June 30,					Variance
	2008			2007		Amount			Percent
Crude Oil Production (Mbbl)
East		12			13		(1	)	(8	)%
Gulf Coast		280			309		(29	)	(9	)%
West		76			87		(11	)	(13	)%
Canada		11			10		1		10	%
Total Company		379			419		(40	)	(10	)%
Crude Oil Sales Price ($/Bbl)
East	$	103.89		$	56.60	$	47.29		84	%
Gulf Coast	$	88.11		$	57.85	$	30.26		52	%
West	$	108.12		$	58.33	$	49.79		85	%
Canada	$	87.26		$	51.77	$	35.49		69	%
Total Company	$	92.58		$	57.76	$	34.82		60	%
Crude Oil Revenue (In thousands)
East	$	1,227		$	721	$	506		70	%
Gulf Coast		24,657			17,857		6,800		38	%
West		8,204			5,088		3,116		61	%
Canada		999			539		460		85	%
Total Company	$	35,087		$	24,205	$	10,882		45	%
Price Variance Impact on Crude Oil Revenue (In thousands)
East	$	558
Gulf Coast		8,467
West		3,779
Canada		406
Total Company	$	13,210
Volume Variance Impact on Crude Oil Revenue (In thousands)
East	$	(52	)
Gulf Coast		(1,667	)
West		(663	)
Canada		54
Total Company	$	(2,328	)

The increase in realized crude oil prices, partially offset by a decrease in production, resulted in a net revenue increase of $10.9 million. The decrease in oil production is mainly the result of a natural decline in crude oil production in the Gulf Coast and West regions.

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Impact of Derivative Instruments on Operating Revenues

The following table reflects the realized impact of cash settlements and the net unrealized change in fair value of derivative instruments:

	Six Months Ended June 30,
	2008						2007
(In thousands)	Realized			Unrealized			Realized		Unrealized
Operating Revenues - Increase / (Decrease) to Revenue
Cash Flow Hedges
Natural Gas Production	$	(20,802	)	$	(2,909	)	$	30,719	$	—
Crude Oil		(5,638	)		—			182		—
Total Cash Flow Hedges	$	(26,440	)	$	(2,909	)	$	30,901	$	—

We are exposed to market risk on derivative instruments to the extent of changes in market prices of natural gas and oil. However, the market risk exposure on these derivative contracts is generally offset by the gain or loss recognized upon the ultimate sale of the commodity. Although notional contract amounts are used to express the volume of natural gas price agreements, the amounts that can be subject to credit risk in the event of non-performance by third parties are substantially smaller. We do not anticipate any material impact on our financial results due to non-performance by third parties.

Operating Expenses

Total costs and expenses from operations increased by $68.4 million in the first half of 2008 compared to the same period of 2007. The primary reasons for this fluctuation are as follows:

• General and Administrative expenses increased by $29.8 million in the first half of 2008 compared with the first half of 2007. This is primarily due to increased stock compensation expense related to the payouts of our supplemental employee incentive plan bonuses as well as increased expense related to our performance shares.

• Depreciation, Depletion and Amortization increased by $16.3 million in the first six months of 2008 compared with the first six months of 2008. This is primarily due to the impact on the DD&A rate of higher capital costs and commencement of production in an East Texas field and Canada.

• Brokered Natural Gas Cost increased by $9.6 million from the first six months of 2007 to the first six months of 2008. See the preceding table titled “Brokered Natural Gas Revenue and Cost” for further analysis.

• Taxes Other Than Income increased by $8.4 million from the six months ended June 30, 2007 to the six months ended June 30, 2008 due to higher production taxes as a result of higher operating revenues and, to a lesser extent, higher ad valorem taxes, partially offset by lower franchise taxes.

• Direct Operations expenses increased by $4.0 million from the first half of 2007 to the first half of 2008 primarily due to higher maintenance expenses, treating costs, personnel and labor expenses and compressor costs.

Interest Expense, Net

Interest expense, net increased by $4.7 million in the first half of 2008 primarily due to higher average credit facility borrowings and lower interest income from our short-term investments, offset in part by a lower weighted-average interest rate on our revolving credit facility borrowings and lower outstanding borrowings on our 7.19% fixed rate debt. Weighted-average borrowings under our credit facility based on daily balances were approximately $182 million during the first half of 2008 compared to approximately $3 million during the first half of 2007. The weighted-average effective interest rate on the credit facility decreased to 5.1% in the first six months of 2008 from 8.3% in the first six months of 2007.

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Income Tax Expense

Income tax expense increased by $5.4 million due to a comparable increase in our pre-tax income. The effective tax rate for the first six months of 2008 and 2007 was 36.3% and 36.6%, respectively. The decrease in the effective tax rate is primarily due to a reduction in our overall state income tax rate for 2008.

Recently Issued Accounting Pronouncements

In June 2008, the Financial Accounting Standards Board (FASB) issued FASB Staff Position (FSP) No. Emerging Issues Task Force (EITF) 03-6-1, “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities.” Under this FSP, unvested share-based payment awards that contain nonforfeitable rights to dividends or dividend equivalents, whether they are paid or unpaid, are considered participating securities and should be included in the computation of earnings per share pursuant to the two-class method. FSP No. EITF 03-6-1 is effective for financial statements issued for fiscal years beginning after December 15, 2008, and interim periods within those years. In addition, all prior period earnings per share data presented should be adjusted retrospectively and early application is not permitted. We do not believe that FSP No. EITF 03-6-1 will have a material impact on our financial position, results of operations or cash flows.

In May 2008, the FASB issued SFAS No. 162, “The Hierarchy of Generally Accepted Accounting Principles,” which identifies a consistent framework for selecting accounting principles to be used in preparing financial statements for nongovernmental entities that are presented in conformity with United States generally accepted accounting principles (GAAP). The current GAAP hierarchy was criticized due to its complexity, ranking position of FASB Statements of Financial Accounting Concepts and the fact that it is directed at auditors rather than entities. SFAS No. 162 will be effective 60 days following the SEC’s approval of the Public Company Accounting Oversight Board amendments to AU Section 411, “The Meaning of Present Fairly in Conformity with Generally Accepted Accounting Principles.” The FASB does not expect that SFAS No. 162 will have a change in current practice, and we do not believe that SFAS No. 162 will have an impact on our financial position, results of operations or cash flows.

In March 2008, the Financial Accounting Standards Board (FASB) issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities,” which amends SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities.” Enhanced disclosures to improve financial reporting transparency are required and include disclosure about the location and amounts of derivative instruments in the financial statements, how derivative instruments are accounted for and how derivatives affect an entity’s financial position, financial performance and cash flows. A tabular format including the fair value of derivative instruments and their gains and losses, disclosure about credit risk-related derivative features and cross-referencing within the footnotes are also new requirements. SFAS No. 161 is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008, with early application and comparative disclosures encouraged, but not required. We have not yet adopted SFAS No. 161. We do not believe that SFAS No. 161 will have an impact on its financial position, results of operations or cash flows.

In December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interest in Consolidated Financial Statements, an amendment of Accounting Research Bulletin (ARB) No. 51.” SFAS No. 160 clarifies that a noncontrolling interest (previously commonly referred to as a minority interest) in a subsidiary is an ownership interest in the consolidated entity and should be reported as equity in the consolidated financial statements. The presentation of the consolidated income statement has been changed by SFAS No. 160, and consolidated net income attributable to both the parent and the noncontrolling interest is now required to be reported separately. Previously, net income attributable to the noncontrolling interest was typically reported as an expense or other deduction in arriving at consolidated net income and was often combined with other financial statement amounts. In addition, the ownership interests in subsidiaries held by parties other than the parent must be clearly identified, labeled, and presented in equity in the consolidated financial statements separately from the parent’s equity. Subsequent changes in a parent’s ownership interest while the parent retains its controlling financial interest in its subsidiary should be accounted for consistently, and when a subsidiary is deconsolidated, any retained noncontrolling equity interest in the former subsidiary must be initially measured at fair value. Expanded disclosures, including a reconciliation of equity balances of the

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parent and noncontrolling interest, are also required. SFAS No. 160 is effective for fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2008 and earlier adoption is prohibited. Prospective application is required. At this time, we do not have any material noncontrolling interests in consolidated subsidiaries. Therefore, we do not believe that the adoption of SFAS No. 160 will have a material impact on our financial position, results of operations or cash flows.

In December 2007, the FASB issued SFAS No. 141(R), “Business Combinations.” SFAS No. 141(R) was issued in an effort to continue the movement toward the greater use of fair values in financial reporting and increased transparency through expanded disclosures. It changes how business acquisitions are accounted for and will impact financial statements at the acquisition date and in subsequent periods. Certain of these changes will introduce more volatility into earnings. The acquirer must now record all assets and liabilities of the acquired business at fair value, and related transaction and restructuring costs will be expensed rather than the previous method of being capitalized as part of the acquisition. SFAS No. 141(R) also impacts the annual goodwill impairment test associated with acquisitions, including those that close before the effective date of SFAS No. 141(R). The definitions of a “business” and a “business combination” have been expanded, resulting in more transactions qualifying as business combinations. SFAS No. 141(R) is effective for fiscal years, and interim periods within those fiscal years, beginning on or after December 31, 2008 and earlier adoption is prohibited. We cannot predict the impact that the adoption of SFAS No. 141(R) will have on our financial position, results of operations or cash flows with respect to any acquisitions completed after December 31, 2008.

Forward-Looking Information

The statements regarding future financial performance and results, market prices and the other statements which are not historical facts contained in this report are forward-looking statements. The words “expect,” “project,” “estimate,” “believe,” “anticipate,” “intend,” “budget,” “plan,” “forecast,” “predict” and similar expressions are also intended to identify forward-looking statements. Such statements involve risks and uncertainties, including, but not limited to, market factors, market prices (including regional basis differentials) of natural gas and oil, results for future drilling and marketing activity, future production and costs and other factors detailed herein and in our other Securities and Exchange Commission filings. Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual outcomes may vary materially from those indicated.

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ITEM 3. Quantitative and Qualitative Disclosures about Market Risk

Derivative Instruments and Hedging Activity

Our hedging strategy is designed to reduce the risk of price volatility for our production in the natural gas and crude oil markets. A hedging committee that consists of members of senior management oversees our hedging activity. Our hedging arrangements apply to only a portion of our production and provide only partial price protection. These hedging arrangements limit the benefit to us of increases in prices, but offer protection in the event of price declines. Further, if our counterparties defaulted, this protection might be limited as we might not receive the benefits of the hedges. Please read the discussion below as well as Note 7 of the Notes to the Condensed Consolidated Financial Statements for a more detailed discussion of our hedging arrangements.

Hedges on Production – Swaps

From time to time, we enter into natural gas and crude oil swap agreements with counterparties to hedge price risk associated with a portion of our production. These cash flow hedges are not held for trading purposes. Under these price swaps, we receive a fixed price on a notional quantity of natural gas or crude oil in exchange for paying a variable price based on a market-based index, such as the NYMEX gas and crude oil futures.

During the first six months of 2008, natural gas price swaps covered 2,465 Mmcf of our gas production, or six percent of our first six months of 2008 gas production at an average price of $7.44 per Mcf. During the first half of 2008, we entered into natural gas price swaps covering a portion of our anticipated 2008, 2009 and 2010 production (including production related to the pending East Texas acquisition).

At June 30, 2008, we had open natural gas price swap contracts covering a portion of our anticipated 2008, 2009 and 2010 production as follows:

	Natural Gas Price Swaps
Contract Period	Volume in Mmcf	Weighted-Average Contract Price (per Mcf)		Net Unrealized Loss (In thousands)
As of June 30, 2008
Third Quarter 2008	3,678	$	11.22
Fourth Quarter 2008	3,678		11.22
Six Months Ended December 31, 2008	7,356	$	11.22	$	(18,044	)
First Quarter 2009	3,964	$	12.18
Second Quarter 2009	4,009		12.18
Third Quarter 2009	4,053		12.18
Fourth Quarter 2009	4,053		12.18
Year Ended December 31, 2009	16,079	$	12.18	$	(24,584	)
First Quarter 2010	4,758	$	11.43
Second Quarter 2010	4,811		11.43
Third Quarter 2010	4,863		11.43
Fourth Quarter 2010	4,863		11.43
Year Ended December 31, 2010	19,295	$	11.43	$	(17,201	)

44

We had no crude oil price swaps covering our first six months of 2008 production. During the first half of 2008, we entered into crude oil price swaps covering a portion of our anticipated 2008, 2009 and 2010 production. At June 30, 2008, we had open crude oil price swap contracts covering a portion of our anticipated 2008, 2009 and 2010 production as follows:

	Crude Oil Price Swaps
Contract Period	Volume in Mbbl	Contract Price (per Bbl)		Net Unrealized Loss (In thousands)
As of June 30, 2008
Third Quarter 2008	46	$	127.15
Fourth Quarter 2008	46		127.15
Six Months Ended December 31, 2008	92	$	127.15	$	(1,264	)
First Quarter 2009	90	$	125.25
Second Quarter 2009	91		125.25
Third Quarter 2009	92		125.25
Fourth Quarter 2009	92		125.25
Year Ended December 31, 2009	365	$	125.25	$	(5,413	)
First Quarter 2010	90	$	125.00
Second Quarter 2010	91		125.00
Third Quarter 2010	92		125.00
Fourth Quarter 2010	92		125.00
Year Ended December 31, 2010	365	$	125.00	$	(4,543	)

Hedges on Production – Options

From time to time, we enter into natural gas and crude oil collar agreements with counterparties to hedge price risk associated with a portion of our production. These cash flow hedges are not held for trading purposes. Under the collar arrangements, if the index price rises above the ceiling price, we pay the counterparty. If the index price falls below the floor price, the counterparty pays us. During the first six months of 2008, natural gas price collars covered 24,624 Mmcf, or 57%, of our first half of 2008 gas production, with a weighted-average floor of $8.45 per Mcf and a weighted-average ceiling of $10.55 per Mcf.

At June 30, 2008, we had open natural gas price collar contracts covering a portion of our anticipated 2008 and 2009 production as follows:

	Natural Gas Price Collars
Contract Period	Volume in Mmcf	Weighted-Average Ceiling / Floor (per Mcf)		Net Unrealized Loss (In thousands)
As of June 30, 2008
Third Quarter 2008	14,775	$	10.83 / $8.59
Fourth Quarter 2008	14,775		10.83 / 8.59
Six Months Ended December 31, 2008	29,550	$	10.83 / $8.59	$	(107,283	)
First Quarter 2009	11,652	$	12.39 / $9.40
Second Quarter 2009	11,781		12.39 / 9.40
Third Quarter 2009	11,910		12.39 / 9.40
Fourth Quarter 2009	11,910		12.39 / 9.40
Year Ended December 31, 2009	47,253	$	12.39 / $9.40	$	(98,156	)

45

During the first six months of 2008, a crude oil price collar covered 182 Mbbls, or 48%, of our first six months of 2008 crude oil production, with a floor of $60.00 per Bbl and a ceiling of $80.00 per Bbl.

At June 30, 2008 we had one open crude oil price collar contract covering a portion of our anticipated 2008 production as follows:

	Crude Oil Price Collar
Contract Period	Volume in Mbbl	Ceiling / Floor (per Bbl)		Net Unrealized Loss (In thousands)
As of June 30, 2008
Third Quarter 2008	92	$	80.00 / $60.00
Fourth Quarter 2008	92		80.00 / 60.00
Six Months Ended December 31, 2008	184	$	80.00 / $60.00	$	(12,792	)

We are exposed to market risk on these open contracts, to the extent of changes in market prices of natural gas and crude oil. However, the market risk exposure on these hedged contracts is generally offset by the gain or loss recognized upon the ultimate sale of the commodity that is hedged.

The amounts set forth under the net unrealized loss columns in the tables above represent our total unrealized loss position at June 30, 2008. Also included in our total loss on the Condensed Consolidated Balance Sheet is a reduction in our current and long-term liability for derivative contracts of $4.9 million and $1.6 million, respectively, related to our assessment of our nonperformance risk. This risk was evaluated by using a market credit spread provided by our bank.

The preceding paragraphs contain forward-looking information concerning future production and projected gains and losses, which may be impacted both by production and by changes in the future market prices of energy commodities. See “Forward-Looking Information” for further details.

ITEM 4. Controls and Procedures

As of the end of the current reported period covered by this report, the Company carried out an evaluation, under the supervision and with the participation of the Company’s management, including the Company’s Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of the Company’s disclosure controls and procedures pursuant to Rules 13a-15 and 15d-15of the Securities Exchange Act of 1934 (the “Exchange Act”). Based upon that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the Company’s disclosure controls and procedures are effective, in all material respects, with respect to the recording, processing, summarizing and reporting, within the time periods specified in the Commission’s rules and forms, of information required to be disclosed by the Company in the reports that it files or submits under the Exchange Act.

There were no significant changes in the Company’s internal control over financial reporting that occurred during the second quarter of 2008 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

PART II. OTHER INFORMATION

ITEM 1. Legal Proceedings

The information set forth under the caption “West Virginia Royalty Litigation” in Note 6 of the Notes to the Condensed Consolidated Financial Statements in Item 1 of Part I of this Quarterly Report on Form 10-Q is incorporated by reference in response to this item.

46

ITEM 1A. Risk Factors

For additional information about the risk factors facing the Company, see Item 1A of Part I of the Company’s Annual Report on Form 10-K for the year ended December 31, 2007.

Acquired properties may not be worth what we pay due to uncertainties in evaluating recoverable reserves and other expected benefits, as well as potential liabilities.

Successful property acquisitions require an assessment of a number of factors beyond our control. These factors include exploration potential, future natural gas and oil prices, operating costs, and potential environmental and other liabilities. These assessments are complex and inherently imprecise. Our review of the properties we have agreed to acquire in the East Texas acquisition will not necessarily reveal all existing or potential problems. In addition, our review may not allow us to fully assess the potential deficiencies of the properties. We do not inspect every well, and even when we inspect a well we may not discover structural, subsurface, or environmental problems that may exist or arise. We may not be entitled to contractual indemnification for pre-closing liabilities, including environmental liabilities, and our contractual indemnification may not be effective. Normally, we acquire interests in properties on an “as is” basis with limited remedies for breaches of representations and warranties.

The integration of the properties we acquire could be difficult, and may divert management’s attention away from our existing operations.

The integration of the properties we acquire could be difficult, and may divert management’s attention and financial resources away from our existing operations. These difficulties include:

• the challenge of integrating the acquired properties while carrying on the ongoing operations of our business; and

• the possibility of faulty assumptions underlying our expectations.

The process of integrating our operations could cause an interruption of, or loss of momentum in, the activities of our business. Members of our management may be required to devote considerable amounts of time to this integration process, which will decrease the time they will have to manage our existing business. If management is not able to effectively manage the integration process, or if any significant business activities are interrupted as a result of the integration process, our business could suffer.

ITEM 2. Unregistered Sales of Equity Securities and Use of Proceeds

Issuer Purchases of Equity Securities

The Board of Directors has authorized a share repurchase program under which the Company may purchase shares of common stock in the open market or in negotiated transactions. There is no expiration date associated with the authorization. During the six months ended June 30, 2008, the Company did not repurchase any shares of common stock. All purchases executed to date have been through open market transactions. The maximum number of shares that may yet be purchased under the plan as of June 30, 2008 was 4,795,300.

ITEM 4. Submission of Matters to a Vote of Security Holders

On April 30, 2008, the Company held its Annual Meeting of Stockholders. At this meeting, the Company’s stockholders voted on the following two matters:

• the election of two directors and

• the ratification of the appointment of PricewaterhouseCoopers LLP as the independent registered public accounting firm for the Company for its 2008 fiscal year.

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Of the 97,788,536 shares entitled to vote, 92,483,113 were present at the meeting in person or represented by proxy. Below are the results of the voting.

Shareholders voted to re-elect two directors by the following vote:

Dan O. Dinges
For:	88,345,984
Withheld:	4,137,129
William P. Vititoe
For:	88,327,883
Withheld:	4,155,230

The terms of office of directors David M. Carmichael, Robert L. Keiser, Robert Kelley and P. Dexter Peacock continued beyond the meeting date. As previously reported, John G.L. Cabot retired from the Board of Directors, in accordance with the Board’s mandatory retirement guidelines, following the conclusion of the annual meeting.

Shareholders voted to ratify the appointment of PricewaterhouseCoopers LLP as the independent registered public accounting firm for the Company for its 2008 fiscal year by the following vote:

For	87,750,151
Against	4,683,164
Abstain	49,798

48

ITEM 6. Exhibits

4.1	Credit Agreement dated as of October 28, 2002 among the Company, the Banks Parties Hereto and Fleet National Bank, as administrative agent (Form 10-Q for the quarter ended September 30, 2002).
	(a) Amendment No. 1 to Credit Agreement dated December 10, 2004 (Form 10-K for 2004).
	(b) Amendment No. 2 to Credit Agreement dated June 18, 2008.
	(c) Amendment No. 3 to Credit Agreement dated June 18, 2008.
4.2	Note Purchase Agreement dated July 16, 2008 between Cabot Oil & Gas Corporation and the Purchasers named therein (Form 8-K for July 16, 2008).
10.1	Purchase and Sale Agreement dated June 3, 2008 by and among Enduring Resources, LLC, Mustang Drilling, Inc., Minden Gathering Services, LLC and Cabot Oil & Gas Corporation.
10.2	Supplemental Employee Incentive Plan II of the Company, effective July 1, 2008.
15.1	Awareness letter of PricewaterhouseCoopers LLP
31.1	302 Certification - Chairman, President and Chief Executive Officer
31.2	302 Certification - Vice President and Chief Financial Officer
32.1	906 Certification

49

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.

	CABOT OIL & GAS CORPORATION
	(Registrant)
July 29, 2008	By:	/s/ Dan O. Dinges
		Dan O. Dinges
		Chairman, President and Chief Executive Officer
		(Principal Executive Officer)
July 29, 2008	By:	/s/ Scott C. Schroeder
		Scott C. Schroeder
		Vice President and Chief Financial Officer
		(Principal Financial Officer)
July 29, 2008	By:	/s/ Henry C. Smyth
		Henry C. Smyth
		Vice President, Controller and Treasurer
		(Principal Accounting Officer)

50

EX-4.1(B)

Exhibit 4.1(b)

SECOND AMENDMENT TO CREDIT AGREEMENT

THIS SECOND AMENDMENT TO CREDIT AGREEMENT (this “Amendment”) dated as of the 18th day of June, 2008, by and among CABOT OIL & GAS CORPORATION (“Borrower”), BANK OF AMERICA, N.A., successor to Fleet National Bank, as Administrative Agent, and the Banks party hereto.

WITNESSETH:

WHEREAS, Borrower, Administrative Agent and Banks named therein entered into that certain Credit Agreement dated as of October 28, 2002, amended by that certain First Amendment to Credit Agreement dated December 10, 2008 (as amended, the “Original Agreement”) for the purposes and consideration therein expressed; and

WHEREAS, Borrower, Administrative Agent and Banks desire to amend the Original Agreement for the purposes described herein;

NOW, THEREFORE, in consideration of the premises and the mutual covenants and agreements contained herein and in the Original Agreement, and for other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the parties hereto do hereby agree as follows:

ARTICLE I. — Definitions and References

§ 1.1. Terms Defined in the Original Agreement. Unless the context otherwise requires or unless otherwise expressly defined herein, the terms defined in the Original Agreement shall have the same meanings whenever used in this Amendment.

§ 1.2. Other Defined Terms. Unless the context otherwise requires, the following terms when used in this Amendment shall have the meanings assigned to them in this § 1.2.

“Amendment” means this Second Amendment to Credit Agreement.

“Credit Agreement” means the Original Agreement as amended hereby.

ARTICLE II. — Amendments

§ 2.1. Material Subsidiary. The reference to “any Subsidiary of Borrower” in the introductory clause of the definition of “Material Subsidiary” set forth in Section 1.01 of the Original Agreement is hereby amended to refer instead to “any Subsidiary of Borrower that is organized under the laws of any political subdivision of the United States”.

§ 2.2. Subsidiary Guaranties. The last sentence of Section 5.08 of the Original Agreement is hereby deleted in its entirety.

§ 2.3. Subsidiary Debt. Clause (i) of Section 5.15 of the Original Agreement is hereby amended in its entirety to read as follows:

(i) (A) guaranties of the Indebtedness, (B) guaranties of Debt of Borrower incurred in compliance with Section 5.10(a) by Subsidiary Guarantors, and (C) Debt owing to the Borrower or a Wholly-Owned Subsidiary

1

§ 2.4. Release and Termination of Cody Texas Subsidiary Guaranty. Administrative Agent and Lenders hereby release Cody Texas, L.P. from all obligations and liabilities under that certain Subsidiary Guaranty dated October 28, 2002 (the “Guaranty”) by Cody Texas, L.P. in favor of Administrative Agent for the benefit of the Banks, and do hereby RELEASE and TERMINATE such Guaranty.

ARTICLE III. — Conditions of Effectiveness

§ 3.1. Effective Date. This Amendment shall become effective as of the date first written above, when and only when

(a) Administrative Agent shall have received, at Administrative Agent’s office a counterpart of this Amendment executed and delivered by Borrower and all Banks;

(b) Administrative Agent shall have received, for the account of Administrative Agent and Banks, all amendment fees payable to Administrative Agent or any Bank;

(c) Administrative Agent shall have additionally received all of the following documents, each document (unless otherwise indicated) being dated the date of receipt thereof by Administrative Agent, duly authorized, executed and delivered, and in form and substance satisfactory to Administrative Agent:

(i) Supporting Documents. Such supporting documents as Administrative Agent may reasonably request.

ARTICLE IV. — Representations and Warranties

§ 4.1. Representations and Warranties of Borrower. In order to induce Administrative Agent and Banks to enter into this Amendment, Borrower represents and warrants to Administrative Agent and each Bank that:

(a) the representations and warranties of the Borrower contained in the Credit Agreement (except the representations and warranties covering historical information in Sections 4.04(a) and (b) and the first sentence of Section 4.05, and except to the extent the representations and warranties would cover price and other economic assumptions furnished by the Required Banks under Section 5.09(d)) are be true and correct on and as of the date hereof;

(b) no Default has occurred and is continuing;

(c) the execution, delivery and performance by the Borrower of this Amendment and each other Financing Document to which it is a party, and by each Subsidiary Guarantor of the Financing Documents to which it is a party, are within the Borrower’s and each Subsidiary Guarantor’s corporate powers, have been duly authorized by all necessary corporate action, require no action by or in respect of, or filing with, any governmental body, agency or official and do not contravene, or constitute a default under, any provision of applicable law or

2

regulation or of the certificate of incorporation or by-laws of the Borrower or any Subsidiary Guarantor or of any agreement or instrument evidencing or governing Debt of the Borrower or any Subsidiary or any other agreement, instrument, judgment, injunction, order or decree binding upon the Borrower or any Subsidiary or result in the creation or imposition of any Lien on any asset of the Borrower or any Subsidiary Guarantor pursuant to any such agreement, instrument, judgment, injunction, order or decree;

(d) this Amendment constitutes a valid and binding agreement of the Borrower and each of the other Financing Documents, when executed and delivered in accordance with the Credit Agreement, constitute valid and binding obligations of the Borrower and each Subsidiary Guarantor, to the extent a party thereto, in each case enforceable in accordance with its terms, except as the same may be limited by bankruptcy, insolvency or similar laws affecting creditors’ rights generally and by general principles of equity.

ARTICLE V. — Miscellaneous

§ 5.1. Ratification of Agreements. The Original Agreement, as hereby amended, is hereby ratified and confirmed in all respects. The Financing Documents, as they may be amended or affected by this Amendment, are hereby ratified and confirmed in all respects by Borrower. Any reference to the Credit Agreement in any Financing Document shall be deemed to refer to this Amendment also. The execution, delivery and effectiveness of this Amendment shall not, except as expressly provided herein, operate as a waiver of any right, power or remedy of Administrative Agent or any Bank under the Credit Agreement or any other Financing Document nor constitute a waiver of any provision of the Credit Agreement or any other Financing Document.

§ 5.2. Survival of Agreements. All representations, warranties, covenants and agreements of Borrower shall survive the execution and delivery of this Amendment and the performance hereof, including without limitation the making or granting of each Loan, and shall further survive until all of the Indebtedness is paid in full. All statements and agreements of Borrower or any Subsidiary Guarantor contained in any certificate or instrument delivered by Borrower or any Subsidiary Guarantor hereunder or under the Credit Agreement to Administrative Agent or any Bank shall be deemed to constitute representations and warranties by, or agreements and covenants of, Borrower under this Amendment and under the Credit Agreement.

§ 5.3. Financing Document. This Amendment is a Financing Document, and all provisions in the Credit Agreement pertaining to Financing Documents apply hereto.

§ 5.4. GOVERNING LAW. THIS AMENDMENT SHALL BE GOVERNED BY AND CONSTRUED IN ACCORDANCE WITH THE LAWS OF THE STATE OF NEW YORK AND ANY APPLICABLE LAWS OF THE UNITED STATES OF AMERICA IN ALL RESPECTS, INCLUDING CONSTRUCTION, VALIDITY AND PERFORMANCE.

§ 5.5. Counterparts. This Amendment may be separately executed in counterparts and by the different parties hereto in separate counterparts, each of which when so executed shall be deemed to constitute one and the same Amendment. Delivery of an executed signature page by facsimile transmission shall be effective as delivery of a manual executed counterpart.

3

IN WITNESS WHEREOF, this Amendment is executed as of the date first above written.

BORROWER:	CABOT OIL & GAS CORPORATION
	By:	/s/ Scott C. Schroeder
		Scott C. Schroeder
		Vice President and Chief Financial Officer
ADMINISTRATIVE AGENT:	BANK OF AMERICA, N.A.
	(successor to Fleet National Bank), Administrative Agent
	By:	/s/ Renita Cummings
	Name:	Renita Cummings
	Title:	Assistant Vice President

4

BANKS:	BANK OF AMERICA, N.A.
	(successor to Fleet National Bank), a Bank
	By:	/s/ Jeffrey H. Rathkamp
	Name:	Jeffrey H. Rathkamp
	Title:	Managing Director
	BMO CAPITAL MARKETS FINANCING, INC.
	(f/k/a Harris Nesbitt Financing, Inc.), Documentation Agent and a Bank
	By:	/s/ Mary Lou Allen
	Name:	Mary Lou Allen
	Title:	Vice President
	JPMORGAN CHASE BANK, N.A.
	Syndication Agent and a Bank
	By:	/s/ Michael A. Kamauf
	Name:	Michael A. Kamauf
	Title:	Vice President
	THE BANK OF NEW YORK
	By:	/s/ Richard A. Matthews
	Name:	Richard A. Matthews
	Title:	Vice President
	BNP PARIBAS
	By:	/s/ Courtney Kubesch
	Name:	Courtney Kubesch
	Title:	Vice President
	By:	/s/ Juan Carlos Sandoval
	Name:	Juan Carlos Sandoval
	Title:	Vice President

5

THE FROST NATIONAL BANK
By:	/s/ Andrew A. Merryman
Name:	Andrew A. Merryman
Title:	Senior Vice President
THE BANK OF TOKYO-MITSUBISHI UFJ, LTD.
(successor to UFJ Bank Limited)
By:
Name:
Title:
COMERICA BANK
By:	/s/ Rebecca L. Wilson
Name:	Rebecca L. Wilson
Title:	Assistant Vice President
BANK OF SCOTLAND
By:	/s/ Julia R. Franklin
Name:	Julia R. Franklin
Title:	Assistant Vice President

6

EX-4.1(C)

Exhibit 4.1(c)

THIRD AMENDMENT TO CREDIT AGREEMENT

THIS THIRD AMENDMENT TO CREDIT AGREEMENT (this “Amendment”) dated as of the 18th day of June, 2008, by and among CABOT OIL & GAS CORPORATION (“Borrower”), BANK OF AMERICA, N.A., successor to Fleet National Bank, as Administrative Agent, and the Banks party hereto.

WITNESSETH:

WHEREAS, Borrower, Administrative Agent and Banks named therein entered into that certain Credit Agreement dated as of October 28, 2002, amended by that certain First Amendment to Credit Agreement dated December 10, 2008 and that certain Second Amendment to Credit Agreement of even date herewith (as amended, the “Original Agreement”) for the purposes and consideration therein expressed; and

WHEREAS, Borrower, Administrative Agent and Banks desire to amend the Original Agreement for the purposes described herein;

NOW, THEREFORE, in consideration of the premises and the mutual covenants and agreements contained herein and in the Original Agreement, and for other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the parties hereto do hereby agree as follows:

ARTICLE I. — Definitions and References

§ 1.1. Terms Defined in the Original Agreement. Unless the context otherwise requires or unless otherwise expressly defined herein, the terms defined in the Original Agreement shall have the same meanings whenever used in this Amendment.

§ 1.2. Other Defined Terms. Unless the context otherwise requires, the following terms when used in this Amendment shall have the meanings assigned to them in this § 1.2.

“Amendment” means this Third Amendment to Credit Agreement.

“Credit Agreement” means the Original Agreement as amended hereby.

ARTICLE II. — Amendments

§ 2.1. New Debt Limit. Borrower has requested that the Banks redetermine the Debt Limit. Accordingly, pursuant to Section 5.10(b)(ii)(B) of the Credit Agreement, the Banks hereby approve, and the Administrative Agent hereby designates, a new Debt Limit of $1,200,000,000, effective as of the date hereof and continuing until but not including the next date as of which the Debt Limit is redetermined.

ARTICLE III. — Conditions of Effectiveness

§ 3.1. Effective Date. This Amendment shall become effective as of the date first written above, when and only when

(a) Administrative Agent shall have received, at Administrative Agent’s office a counterpart of this Amendment executed and delivered by Borrower and all Banks;

1

(b) Administrative Agent shall have received, for the account of Administrative Agent and Banks, all amendment fees payable to Administrative Agent or any Bank;

(c) Administrative Agent shall have additionally received all of the following documents, each document (unless otherwise indicated) being dated the date of receipt thereof by Administrative Agent, duly authorized, executed and delivered, and in form and substance satisfactory to Administrative Agent:

(i) Supporting Documents. Such supporting documents as Administrative Agent may reasonably request.

ARTICLE IV. — Representations and Warranties

§ 4.1. Representations and Warranties of Borrower. In order to induce Administrative Agent and Banks to enter into this Amendment, Borrower represents and warrants to Administrative Agent and each Bank that:

(a) the representations and warranties of the Borrower contained in the Credit Agreement (except the representations and warranties covering historical information in Sections 4.04(a) and (b) and the first sentence of Section 4.05, and except to the extent the representations and warranties would cover price and other economic assumptions furnished by the Required Banks under Section 5.09(d)) are be true and correct on and as of the date hereof;

(b) no Default has occurred and is continuing;

(c) the execution, delivery and performance by the Borrower of this Amendment and each other Financing Document to which it is a party, and by each Subsidiary Guarantor of the Financing Documents to which it is a party, are within the Borrower’s and each Subsidiary Guarantor’s corporate powers, have been duly authorized by all necessary corporate action, require no action by or in respect of, or filing with, any governmental body, agency or official and do not contravene, or constitute a default under, any provision of applicable law or regulation or of the certificate of incorporation or by-laws of the Borrower or any Subsidiary Guarantor or of any agreement or instrument evidencing or governing Debt of the Borrower or any Subsidiary or any other agreement, instrument, judgment, injunction, order or decree binding upon the Borrower or any Subsidiary or result in the creation or imposition of any Lien on any asset of the Borrower or any Subsidiary Guarantor pursuant to any such agreement, instrument, judgment, injunction, order or decree;

(d) this Amendment constitutes a valid and binding agreement of the Borrower and each of the other Financing Documents, when executed and delivered in accordance with the Credit Agreement, constitute valid and binding obligations of the Borrower and each Subsidiary Guarantor, to the extent a party thereto, in each case enforceable in accordance with its terms, except as the same may be limited by bankruptcy, insolvency or similar laws affecting creditors’ rights generally and by general principles of equity.

2

ARTICLE V. — Miscellaneous

§ 5.1. Ratification of Agreements. The Original Agreement, as hereby amended, is hereby ratified and confirmed in all respects. The Financing Documents, as they may be amended or affected by this Amendment, are hereby ratified and confirmed in all respects by Borrower. Any reference to the Credit Agreement in any Financing Document shall be deemed to refer to this Amendment also. The execution, delivery and effectiveness of this Amendment shall not, except as expressly provided herein, operate as a waiver of any right, power or remedy of Administrative Agent or any Bank under the Credit Agreement or any other Financing Document nor constitute a waiver of any provision of the Credit Agreement or any other Financing Document.

§ 5.2. Survival of Agreements. All representations, warranties, covenants and agreements of Borrower shall survive the execution and delivery of this Amendment and the performance hereof, including without limitation the making or granting of each Loan, and shall further survive until all of the Indebtedness is paid in full. All statements and agreements of Borrower or any Subsidiary Guarantor contained in any certificate or instrument delivered by Borrower or any Subsidiary Guarantor hereunder or under the Credit Agreement to Administrative Agent or any Bank shall be deemed to constitute representations and warranties by, or agreements and covenants of, Borrower under this Amendment and under the Credit Agreement.

§ 5.3. Financing Document. This Amendment is a Financing Document, and all provisions in the Credit Agreement pertaining to Financing Documents apply hereto.

§ 5.4. GOVERNING LAW. THIS AMENDMENT SHALL BE GOVERNED BY AND CONSTRUED IN ACCORDANCE WITH THE LAWS OF THE STATE OF NEW YORK AND ANY APPLICABLE LAWS OF THE UNITED STATES OF AMERICA IN ALL RESPECTS, INCLUDING CONSTRUCTION, VALIDITY AND PERFORMANCE.

§ 5.5. Counterparts. This Amendment may be separately executed in counterparts and by the different parties hereto in separate counterparts, each of which when so executed shall be deemed to constitute one and the same Amendment. Delivery of an executed signature page by facsimile transmission shall be effective as delivery of a manual executed counterpart.

3

IN WITNESS WHEREOF, this Amendment is executed as of the date first above written.

BORROWER:	CABOT OIL & GAS CORPORATION
	By:	/s/ Scott C. Schroeder
		Scott C. Schroeder
		Vice President and Chief Financial Officer
ADMINISTRATIVE AGENT:	BANK OF AMERICA, N.A.
	(successor to Fleet National Bank), Administrative Agent
	By:	/s/ Renita Cummings
	Name:	Renita Cummings
	Title:	Assistant Vice President

4

BANKS:	BANK OF AMERICA, N.A.
	(successor to Fleet National Bank), a Bank
	By:	/s/ Jeffrey H. Rathkamp
	Name:	Jeffrey H. Rathkamp
	Title:	Managing Director
	BMO CAPITAL MARKETS FINANCING, INC.
	(f/k/a Harris Nesbitt Financing, Inc.), Documentation Agent and a Bank
	By:	/s/ Mary Lou Allen
	Name:	Mary Lou Allen
	Title:	Vice President
	JPMORGAN CHASE BANK, N.A.
	Syndication Agent and a Bank
	By:	/s/ Michael A. Kamauf
	Name:	Michael A. Kamauf
	Title:	Vice President
	THE BANK OF NEW YORK
	By:	/s/ Richard A. Matthews
	Name:	Richard A. Matthews
	Title:	Vice President
	BNP PARIBAS
	By:	/s/ Courtney Kubesch
	Name:	Courtney Kubesch
	Title:	Vice President
	By:	/s/ Juan Carlos Sandoval
	Name:	Juan Carlos Sandoval
	Title:	Vice President

5

THE FROST NATIONAL BANK
By:	/s/ Andrew A. Merryman
Name:	Andrew A. Merryman
Title:	Senior Vice President
THE BANK OF TOKYO-MITSUBISHI UFJ, LTD.
(successor to UFJ Bank Limited)
By:
Name:
Title:
COMERICA BANK
By:	/s/ Rebecca L. Wilson
Name:	Rebecca L. Wilson
Title:	Assistant Vice President
BANK OF SCOTLAND
By:	/s/ Julia R. Franklin
Name:	Julia R. Franklin
Title:	Assistant Vice President

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EX-10.1

Exhibit 10.1

EXECUTION VERSION

PURCHASE AND SALE AGREEMENT

ENDURING RESOURCES, LLC,

MUSTANG DRILLING, INC. and

MINDEN GATHERING SERVICES, LLC

(“Seller”)

and

CABOT OIL & GAS CORPORATION

(“Buyer”)

June 3, 2008

PURCHASE AND SALE AGREEMENT

TABLE OF CONTENTS

ARTICLE 1	DEFINITIONS	1
ARTICLE 2	SALE AND PURCHASE OF PROPERTIES	8
2.1	Properties	8
2.2	Excluded Properties	10
ARTICLE 3	PURCHASE PRICE	10
3.1.	Purchase Price	10
3.2.	Earnest Money	10
ARTICLE 4	ADJUSTMENTS TO PURCHASE PRICE	10
4.1.	Increases in Purchase Price	10
4.2.	Decreases in Purchase Price	11
ARTICLE 5	REPRESENTATIONS AND WARRANTIES OF SELLER	12
5.1.	Enduring	12
5.2.	Mustang	12
5.3.	Minden	13
5.4.	Seller	14
ARTICLE 6	REPRESENTATIONS AND WARRANTIES OF BUYER	17
6.1.	Organization	17
6.2.	Authority	17
6.3.	No Conflicts	17
6.4.	Enforceability	18
6.5.	Basis of Buyer’s Decision; Property Review	18
6.6.	Buyer’s Experience and Counsel	18
6.7.	Closing Funds	18
6.8.	No Further Distribution	18
6.9.	Buyer’s Ability to Take Title	19
6.10.	Buyer’s Ability to Operate	19
6.11.	Finder’s Fees	19
ARTICLE 7	COVENANTS OF SELLER	19
7.1.	Conduct of Business Pending Closing	19
7.2.	Access	20
7.3.	Satisfaction of Conditions	20
7.4.	Non-Solicitation	20

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7.5.	Non-compete	21
7.6.	Consent Requirements	21
7.7.	Transition Services	22
7.8.	Financial Statements	22
7.9	Receivership Proceedings	23
7.10	Drilling Contracts	24
ARTICLE 8	COVENANTS OF BUYER	24
8.1.	Satisfaction of Conditions	24
ARTICLE 9	CONDITIONS PRECEDENT TO THE OBLIGATIONS OF SELLER	24
9.1.	Representations and Warranties	24
9.2.	Covenants	24
9.3.	No Litigation	24
ARTICLE 10	CONDITIONS PRECEDENT TO THE OBLIGATIONS OF BUYER	24
10.1.	Representations and Warranties	24
10.2.	Covenants	25
10.3.	No Litigation	25
10.4.	Consents	25
10.5.	Release of Liens	25
ARTICLE 11	TITLE MATTERS	25
11.1.	Title Defect Notice	25
11.2.	Determination of Title Defects and Defect Values	25
11.3.	Calculation of Defect Value	26
11.4.	Properties Subject to Title Defects	26
11.5.	Purchase Price Adjustment for Title Benefits	27
ARTICLE 12	ENVIRONMENTAL MATTERS	27
12.1.	Presence of Wastes, NORM, Hazardous Substances and Asbestos	27
12.2.	Environmental Assessment	28
12.3.	Notice of Adverse Environment Conditions	28
12.4.	Determination of Adverse Environmental Conditions and Remediation Values	28
12.5.	Properties Subject to Adverse Environmental Conditions	29
ARTICLE 13	SUSPENSE FUNDS HELD BY SELLER	30
13.1.	Suspense Funds Held By Seller	30

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ARTICLE 14	CLOSING	30
14.1.	The Closing	30
14.2.	Closing Statement	30
14.3.	Closing Deliveries	30
14.4.	Effect of Closing	31
ARTICLE 15	POST-CLOSING ADJUSTMENTS	32
15.1.	Final Settlement Statement	32
15.2.	Arbitration	32
15.3.	Payment of Final Purchase Price	32
ARTICLE 16	ALLOCATION OF RISK	33
16.1.	Seller’s Indemnity	33
16.2.	Limitations on Seller’s Indemnity	34
16.3.	Buyer’s Indemnity	34
16.4.	Assumption by Buyer	34
16.5.	Limitations of Warranties	35
16.6.	Third Party Claims	36
ARTICLE 17	RISK OF LOSS	37
17.1.	Casualty Loss	37
17.2.	Buyer’s Risk of Loss	37
ARTICLE 18	TERMINATION AND REMEDIES	37
18.1.	Termination	37
18.2.	Effect of Termination	38
ARTICLE 19	ADDITIONAL COVENANTS	39
19.1.	Further Assurances	39
19.2.	Access to Records by Seller	39
19.3.	Use of Seller’s Name	39
19.4.	Seller’s Employees	39
19.5.	Ad Valorem Tax Proration	39
19.6.	Public Announcements	40
ARTICLE 20	MISCELLANEOUS	40
20.1.	Notice	40
20.2.	Governing Law	41
20.3.	Assignment	41
20.4.	Entire Agreement	41
20.5.	Amendment; Waiver	41
20.6.	Severability	41
20.7.	Construction	41

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20.8.	Confidentiality	42
20.9.	Headings	42
20.10.	Counterparts	42
20.11.	Expenses, Fees and Taxes	42
20.12.	Tax-Deferred Exchange Option	42
20.13.	Relationship Between Seller	43

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Exhibits and Schedules:
Exhibit A:	Leases
Exhibit B:	Units and Wells
Exhibit C:	Excluded Properties
Exhibit D:	Form of Assignment

Schedule 1.1	Minden Gas Gathering System
Schedule 1.2	Receivership Proceedings
Schedule 2.1.3	Contracts
Schedule 2.1.4	Easements
Schedule 5.4.1	Material Contracts
Schedule 5.4.2	Preferential Purchase Rights / Consents
Schedule 5.4.3	Litigation and Claims
Schedule 5.4.5	Sale Contracts
Schedule 5.4.7	Imbalances
Schedule 5.4.10	Payout Balances
Schedule 5.4.13	Disputed Costs and Expenses
Schedule 5.4.14	Outstanding Obligations
Schedule 5.4.19	Insurance
Schedule 5.4.21	Environmental Matters
Schedule 5.4.23	Suspense Amounts
Schedule 7.1	Certain Operations
Schedule 7.2	Confidential Matters
Schedule 7.5	Restricted Area

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PURCHASE AND SALE AGREEMENT

This Purchase and Sale Agreement (“Agreement”) is made and entered into on June 3, 2008, by and among Enduring Resources, LLC, a Delaware limited liability company (“Enduring”), Mustang Drilling, Inc., a Texas corporation (“Mustang”), Minden Gathering Services, LLC, a Texas limited liability company (“Minden”, and together with Enduring and Mustang, “Seller”) and Cabot Oil & Gas Corporation, a Delaware corporation (“Buyer,” and together with Seller, the “Parties”).

ARTICLE 1

DEFINITIONS

“Acquiror” is defined in Section 7.5.

“Adverse Environmental Condition” means any contamination or condition exceeding regulatory limits and not otherwise authorized by permit or Law, resulting from any discharge, release, production, storage, treatment, seepage, escape, leakage, emission, emptying, leaching or any other activities on, in or from any Property, or the migration or transportation from other lands to any Property, of any Hazardous Materials that require Remediation at the Effective Time pursuant to any current federal, state or local Laws, including, but not limited to, the Environmental Laws, or that require Remediation under the terms of any Leases.

“Adverse Environmental Condition Notice” is defined in Section 12.3.

“Adverse Environmental Condition Removal” is defined in Section 12.5.3.

“Agreement” is defined in the preamble.

“Allocated Value” with respect to any Property means the value allocated to Seller’s interest in such Property as set forth on Exhibit B.

“Assignment” is defined in Section 14.3.1.

“Audited Financial Statements” is defined in Section 7.8.3.

“Auditor” is defined in Section 7.8.2.

“Business Day” means each Monday, Tuesday, Wednesday, Thursday and Friday that is not a day on which banks in Denver, Colorado, are generally authorized or obligated, by Law or executive order, to close.

“Buyer” is defined in the preamble.

“Buyer Group” means Buyer, its affiliates and its and their respective employees, officers, directors, attorneys, agents and representatives.

“Buyer’s Suspense Amounts” is defined in Section 13.1.

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“Casualty Loss” is defined in Section 17.1.

“Claim” means any loss, cost or expense (including reasonable attorneys’ fees, experts’ fees and court costs), damage, obligation, claim, liability or cause of action caused by, relating to or arising out of any lawsuit, regulatory or administrative action whose basis is the violation of any Law.

“Closing” is defined in Section 14.1.

“Closing Date” is defined in Section 14.1.

“Confidentiality Agreement” means the confidentiality agreement between Enduring and Buyer dated April 15, 2008.

“Contracts” is defined in Section 2.1.3.

“Cure Deadline” is defined in Section 11.4.1.

“Data” is defined in Section 7.2.

“Defect Notification Deadline” means 5:00 p.m., Denver, Colorado time, on July 18, 2008; provided, however, by notice to Seller given not later than July 11, 2008, Buyer may extend the Defect Notification Deadline until not later than August 4, 2008 (in which event, the Closing Date will be deferred by the number of days by which the Defect Notification Deadline is extended beyond July 18, 2008, and all subsequent dates and required activities having reference to the Closing Date shall be correspondingly extended) if Buyer has theretofore used its reasonable efforts, appropriate in the circumstances, to complete its title due diligence, but in good faith believes that as of the date such notice is given that it will not be able to complete such due diligence on or before July 18, 2008.

“Defect Value” means, with respect to each Property that is subject to a Title Defect, the lesser of (a) the Allocated Value of the Property subject to the Title Defect and (b) the amount determined in accordance with Section 11.3 with respect to the Title Defect.

“Deposit” is defined in Section 3.2.

“Drilling Contract” is defined in Section 7.10.

“Easements” is defined in Section 2.1.4.

“Effective Time” is defined in Section 2.1.

“Enduring” is defined in the preamble.

“Environmental Laws” means all applicable Laws concerning or relating to the pollution or protection of the environment, including the Clean Air Act, the Comprehensive Environmental Response, Compensation and Liability Act of 1980 (“CERCLA”), the Federal Water Pollution Control Act, the Safe Drinking Water Act, the Toxic Substance Control Act, the

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Hazardous and Solid Waste Amendments Act of 1984, the Superfund Amendments and Reauthorization Act of 1986, the Hazardous Materials Transportation Act, the Clean Water Act, the National Environmental Policy Act, the Endangered Species Act, the Fish and Wildlife Coordination Act, the National Historic Preservation Act and the Oil Pollution Act of 1990, as such Laws may be amended from time to time and all regulations, orders, rulings, directives, requirements and ordinances promulgated thereunder.

“Environmental Liabilities” means any and all liabilities, responsibilities, claims, suits, damages, costs (including remedial, removal, response, abatement, clean-up, investigative or monitoring costs and any other related costs and expenses), other causes of action, damages, settlements, expenses, charges, assessments, liens, penalties, fines, pre-judgment and post-judgment interest, attorneys’ fees and other legal fees (i) pursuant to any agreement, order, notice or responsibility, directive (including directives embodied in Environmental Laws), injunction, judgment or similar documents (including settlements) arising out of or in connection with any Environmental Laws, or (ii) pursuant to any claim by a governmental authority or other person for personal injury, property damage, damage to natural resources, Remediation or payment or reimbursement of Remediation costs incurred or expended by a governmental authority or person pursuant to common law or statute.

“Environmental Permits” means any permits, licenses, authorizations, registrations, consents or approvals granted or issued by any governmental authority or otherwise required under applicable Environmental Laws.

“Exchange Act” means the Securities Exchange Act of 1934, as amended, together with the rules and regulations of the SEC promulgated thereunder.

“Excluded Properties” is defined in Section 2.2.

“Facilities” is defined in Section 2.1.2.

“Final Settlement Statement” is defined in Section 15.1.

“Financial Statements” is defined in Section 7.8.1.

“Good and Defensible Title” means such record title to the Properties that (i) (a) entitles Seller to receive and retain, without suspension, reduction, or termination, not less than the Net Revenue Interest in all Hydrocarbons produced from the Wells and units described in Exhibit B through plugging, abandonment or salvage of the Wells described in Exhibit B or the Wells or wells to be drilled in such units, and (b) obligates Seller to bear the costs and expenses attributable to the maintenance, development and operation of the Wells and units described in Exhibit B through plugging, abandonment and salvage of the Wells described in Exhibit B or the Wells or wells to be drilled in such units of not more than the Working Interest in the Wells and units as set forth in Exhibit B (unless there is a corresponding increase in the Net Revenue Interest) and (ii) is free and clear of all liens and encumbrances, except for Permitted Encumbrances.

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“Hazardous Materials” means wastes, pollutants, contaminants, hazardous materials, hazardous wastes and any other materials or substances subject to regulation relating to the protection of the environment, human health, or worker safety.

“Hydrocarbons” means oil, gas, natural gas liquids, condensate and related hydrocarbons.

“Indemnified Party” is defined in Section 16.6.

“Indemnitor” is defined in Section 16.6.

“Lands” is defined in Section 2.1.1.

“Laws” is defined in Section 5.4.6.

“Leases” is defined in Section 2.1.1.

“Loss” means all damages, losses, liabilities, obligations, payments, amounts paid in settlement, fines, penalties, costs (including reasonable fees and expenses of attorneys, accountants and other professional advisors, as well as of expert witnesses, and other costs of investigation, preparation and litigation in connection with any pleading, claim, demand or other action) of any kind or nature whatsoever, whether known or unknown, contingent or vested, or matured or unmatured.

“Material Adverse Effect” means a material adverse effect on the (i) ownership, use or value of the Properties taken as a whole or (ii) ability of Seller to consummate the transactions contemplated by this Agreement.

“Material Contracts” is defined in Section 5.4.1.

“Minden” is defined in the preamble.

“Minden Consents” means consents, approvals or authorizations required to be obtained by Minden from grantors of Minden Gas Gathering Easements to permit the transfer thereof to Buyer.

“Minden Gas Gathering Easements” is defined in Section 2.1.4.

“Minden Gas Gathering System” means that certain gas gathering system located in Panola and Rusk Counties, Texas, which system specifically includes, without limitation, (i) approximately 33.4 miles of pipeline ranging from three inches to six inches in diameter, (ii) 5,400 horsepower of rental compression and (iii) three completed salt water disposal wells with 47,000 barrels per day of combined disposal capacity and one uncompleted salt water disposal well, which system is depicted on the map attached hereto as Schedule 1.1.

“Minden Transfer Expenses” means any payments made by Seller to any grantor of a Minden Gas Gathering Easement in connection with obtaining a Minden Consent, or obtaining a renewal or replacement of any such easement from the grantor thereof in favor of Buyer, as grantee.

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“Minimal Defect” means any individual Title Defect with a Defect Value of less than $50,000 or any individual Adverse Environmental Condition or series of related Adverse Environmental Conditions with a Remediation Value of less than $50,000.

“Mustang” is defined in the preamble.

“Net Revenue Interest” means Seller’s interest in and to all production of oil, gas and other minerals saved, produced and sold from any Well or unit after giving effect to all valid lessor’s royalties, overriding royalties, production payments, carried interests, liens and other encumbrances or charges against production therefrom.

“NORM” means naturally occurring radioactive material.

“Other Easements” is defined in Section 2.1.4.

“Parties” is defined in the preamble.

“Permits” is defined in Section 2.1.6.

“Permitted Encumbrances” means:

(a) Lessors’ royalties, overriding royalties, reversionary interests and similar burdens if the cumulative effect of the burdens does not operate to reduce Seller’s Net Revenue Interest in a Well or unit below the Net Revenue Interest for such Well or unit set forth in Exhibit B or operate to increase Seller’s Working Interest in a Well or unit to more than the Working Interest for such Well or unit set forth in Exhibit B;

(b) Division orders and sales contracts terminable without penalty upon no more than 90 days notice to the purchaser;

(c) Required third-party consents to assignment and similar agreements with respect to which waivers or consents are obtained from the appropriate parties;

(d) Materialman’s, mechanic’s, repairman’s, employee’s, contractor’s, operator’s, tax and other similar liens or charges arising in the ordinary course of business for obligations that are not delinquent or that will be paid and discharged in the ordinary course of business or if delinquent, that are being contested in good faith by appropriate action of which Buyer is notified in writing before Closing and for which Seller indemnifies Buyer subsequent to Closing;

(e) All rights to consent by, required notices to, filings with, or other actions by governmental entities in connection with the sale or conveyance of oil and gas leases or interests therein if they are routinely obtained subsequent to the sale or conveyance and have been properly obtained in connection with all prior sales and conveyances;

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(f) Easements, rights-of-way, servitudes, permits, surface leases and other rights in respect of surface operations that, individually or in the aggregate, do not materially interfere with the current operation of the portion of the Properties burdened thereby;

(g) All operating agreements, unit agreements, unit operating agreements, pooling agreements and pooling designations affecting the Properties that are contained in Seller’s files and which do not (i) reduce Seller’s interest with respect to oil, gas and other minerals produced from any Well or unit set forth in Exhibit B below the Net Revenue Interest therefor set forth in Exhibit B, or increase Seller’s Working Interest in any Well or unit set forth in Exhibit B to more than the Working Interest set forth in Exhibit B for that Well or unit (unless there is a corresponding increase in the Net Revenue Interest) or (ii) interfere in any material respect with the current operation of the portion of the Properties burdened thereby;

(h) Conventional rights of reassignment prior to release or surrender requiring notice to the holders of the rights;

(i) All rights reserved to or vested in any governmental, statutory or public authority to control or regulate any of the Properties in any manner, and all applicable Laws of any governmental authority, so long as the foregoing do not interfere in any material respect with the current operation of the portion of the Properties burdened thereby;

(j) The terms and conditions of the Leases and the Material Contracts listed on Schedule 5.4.1 which do not (i) reduce Seller’s interest with respect to oil, gas and other minerals produced from any Well or unit set forth in Exhibit B below the Net Revenue Interest therefor set forth in Exhibit B, or increase Seller’s Working Interest in any Well or unit set forth in Exhibit B to more than the Working Interest set forth in Exhibit B for that Well or unit (unless there is a corresponding increase in the Net Revenue Interest) or (ii) interfere in any material respect with the current operation of the portion of the Properties burdened thereby;

(k) Receivership proceedings set forth on Schedule 1.2; the pendency of which does not, and the resolution of which will not, (i) reduce Seller’s interest with respect to oil, gas and other minerals produced from any Well or unit set forth in Exhibit B below the Net Revenue Interest therefor set forth in Exhibit B, or increase Seller’s Working Interest in any Well or unit set forth in Exhibit B to more than the Working Interest set forth in Exhibit B for that Well or unit (unless there is a corresponding increase in the Net Revenue Interest) or (ii) interfere in any material respect with the current operation of the portion of the Properties burdened thereby; and

(l) Any Title Defects that Buyer has expressly waived in writing.

“Permitted Investments” means investments in any of the following: (i) open market commercial paper, maturing within 270 days after acquisition thereof, which is rated at least A-1 by Standard & Poor’s Rating Services or P-1 by Moody’s Investors Service, Inc.; (ii) marketable obligations, maturing within 12 months after acquisition thereof, issued or unconditionally guaranteed by the United States of America or an instrumentality or agency thereof and entitled

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to the full faith and credit of the United States of America; (iii) time deposits (including certificates of deposit) maturing within 12 months from the date of deposit thereof, with any office of any national or state bank or trust company which is organized under the laws of the United States of America or any state therein, which has capital, surplus and undivided profits of at least $500,000,000, and whose certificates of deposit are rated at least Aa3 by Standard & Poor’s Rating Services or AA by Moody’s Investors Service, Inc.; (iv) repurchase obligations with a term of not more than seven days for underlying securities of the types described in clause (ii) above entered into with any commercial bank meeting the specifications of clause (iii) above; and (v) money market or other mutual funds substantially all of whose assets comprise securities of the types described in clauses (i) through (iv) above.

“Pioneer” is defined in Section 7.10.

“Preliminary Purchase Price” is defined in Section 14.2.

“Property” is defined in the last sentence of Section 2.1.

“Purchase Price” is defined in Section 3.1.

“Records” is defined in Section 2.1.7.

“Remediate,” “Remediation,” or “Remedial Action” means the removal, abatement, response, investigative, cleanup and/or monitoring activities undertaken to address any Adverse Environmental Conditions, or a release of Hazardous Materials; any investigation, study, assessment, testing, monitoring, containment, removal, disposal, closure, corrective action, passive remediation, natural attenuation or bioremediation; and the installation and operation of remediation systems.

“Remediation Value” is defined in Section 12.3.

“Retained Property” is defined in Section 7.6.1.

“SEC” means the United States Securities and Exchange Commission.

“Securities Act” means the Securities Act of 1933, as amended.

“Seller” is defined in the preamble.

“Seller Group” means Seller, its affiliates and its and their respective employees, officers, directors, attorneys, agents and representatives.

“Seller Retained Liabilities” is defined in the last sentence of Section 16.1.

“Seller’s Certificate” is defined in Section 14.3.3.

“Seller’s Knowledge” means the actual knowledge, following due inquiry of Seller’s respective officers, employees and contractors who are engaged to perform day-to-day operations with respect to the Properties (and in the case of Frank Bane, any of his

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subcontractors), of Barth E. Whitham – President and Chief Executive Officer, Enduring; Alex Campbell – Vice President Land, Enduring; Frank Hutto – Vice President Operations, Enduring; Phil Tater – Vice President G&G, Enduring; Brian Bess – Vice President Reservoir Engineering, Enduring; Paul Dorr – Vice President Planning, Enduring; Andrew Mills – President, Mustang; Michael Wilhite, Jr., Vice President Land, Mustang; Edward Fritcher, Vice President Operations, Mustang; and Frank Bane – Field Superintendent.

“Tax Deferred Exchange” is defined in Section 20.12.

“Termination Date” is defined in Section 18.1.5.

“Title Benefit” is defined in Section 11.5.

“Title Defect” is defined in Section 11.1.

“Title Defect Notice” is defined in Section 11.1.

“Title Defect Removal” is defined in Section 11.4.3.

“Transition Services Agreement” is defined in Section 7.7.

“Uncured Title Defect” means any Title Defect, other than a Minimal Defect, neither removed pursuant to a Title Defect Removal, nor cured in accordance with Section 11.4.1.

“Uncured Title Defects Value” means the aggregate Defect Value of all Uncured Title Defects.

“Wells” is defined in Section 2.1.2.

“Working Interest” means, with respect to the Wells or units set forth in Exhibit B, Seller’s interest in and to the full and entire leasehold estate created under and by virtue of the Leases and all rights and obligations of every kind and character appurtenant thereto or arising therefrom, without regard to any valid lessor’s royalty, overriding royalties, production payments, carried interests, liens, or other encumbrances or charges against production therefrom insofar as such interest in the leasehold estate is burdened with the obligation to bear and pay costs of operations.

ARTICLE 2

SALE AND PURCHASE OF PROPERTIES

2.1. Properties. Subject to the terms and conditions herein set forth and except for the Excluded Properties, Seller agrees to jointly sell, assign, convey and deliver to Buyer, and Buyer agrees to purchase and acquire from Seller at the Closing, but effective as of 7:00 a.m. CDT on May 1, 2008 (the “Effective Time”), all of Seller’s right, title and interest in and to the following:

2.1.1. The oil, gas and mineral leases, and the leasehold estates created thereby (including, without limitation, royalty interests, overriding royalties, net profits interests,

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production payments, carried interests and other interests in, under or relating to such leases) described in Exhibit A (collectively, the “Leases”), and all of the lands covered by the Leases (“Lands”), together with corresponding interests in and to all the property and rights incident thereto, including all rights in any pooled or unitized acreage by virtue of the Lands being a part thereof, all production from the pool or unit allocated to any such Land; and all interests in any wells within the pool or unit associated with the Lands;

2.1.2. All producing, non-producing, shut-in and abandoned oil and gas wells, salt water disposal wells, injection wells, and water wells located on the Leases or lands pooled or unitized therewith, including the wells within the geographical boundaries of the units described in Exhibit B (“Wells”), and all gathering lines, flowlines and pipelines connected to the Wells or located on the Lands as well as those comprised of, related to or associated with the Minden Gas Gathering System, and all other personal property, equipment, fixtures, and improvements located on and appurtenant to the Leases, Lands and Minden Gas Gathering System or elsewhere insofar as they are used, held for use or obtained in connection with the operation of the Leases, Lands, Wells or Minden Gas Gathering System or relate to the production, treatment, sale, or disposal of Hydrocarbons or water produced from the Leases or Lands or attributable thereto (the “Facilities”);

2.1.3. All farmout and farmin agreements, operating agreements, production sales and purchase contracts, unitization and pooling agreements, exploration agreements, participation agreements, transportation and gathering agreements, processing agreements, rig contracts, pipe and other supply contracts, saltwater disposal agreements, surface leases, division and transfer orders, and (to the extent transferable by Seller without material restrictions under third party agreements) all other contracts, contractual rights, interests and other agreements covering or affecting any or all of the Leases, Lands, Wells and Facilities, including, without limitation, those described in Schedule 2.1.3 (the “Contracts”);

2.1.4.(i) All fee property, easements, rights-of-way, surface use agreements, leases, servitudes and other real property interests and estates that relate and are attributable in any way to, or are used in connection with the ownership, use or operation of the Minden Gas Gathering System, including, without limitation, those described in Part I of Schedule 2.1.4 (the “Minden Gas Gathering Easements”) and (ii) all other fee property, easements, rights-of-way, and to the extent transferable, all licenses, authorizations, permits, and similar rights and interests applicable to, or used or useful in connection with, any or all of the Leases, Lands, Wells and Facilities, including, without limitation, those described in Part II of Schedule 2.1.4 (the “Other Easements”, together with the Minden Gas Gathering Easements, the “Easements”);

2.1.5. All Hydrocarbons produced after the Effective Time attributable to Seller’s interest in the Leases, Lands, Wells, Facilities and Contracts;

2.1.6. To the extent transferable, all environmental and other governmental (whether federal, state or local) permits, licenses, orders, authorizations, franchises and related instruments or rights relating to the ownership, operation or use of the Leases, Lands, Wells and Facilities (the “Permits”); and

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2.1.7. All books, files, records, correspondence, studies, surveys, reports, geologic, proprietary and, to the extent transferable without material restriction or payment of a transfer or licensing fee under third party agreements, non-proprietary geophysical and seismic data (including raw data and any interpretative data or information relating to such geologic, geophysical and seismic data) and other data in the actual possession or control of Seller and relating to the operation of the Leases, Lands, Wells and Facilities, including all title records, customer lists, supplier lists, sales materials, promotional materials, operational records, technical records, production and processing records, division order and lease right-of-way files, accounting files and contract files (the “Records”).

All of the real and personal properties, rights, titles, and interests described in Sections 2.1.1 through 2.1.7, subject to the limitations and terms expressly set forth herein and in Exhibits A and B, are hereinafter collectively called the “Properties” or, individually, a “Property.”

2.2. Excluded Properties. Notwithstanding anything to the contrary in this Agreement, the assets of Seller described in Exhibit C (collectively, the “Excluded Properties”) are not part of the sale and purchase contemplated hereunder, are excluded from the Properties and shall remain the property of Seller after the Closing.

ARTICLE 3

PURCHASE PRICE

3.1. Purchase Price. The total purchase price for all of the Properties is $602,788,000 (the “Purchase Price”), subject to adjustment hereinafter provided.

3.2. Earnest Money. On or before 12:00 P.M. Central Daylight Time on June 4, 2008, Buyer will tender to Seller by wire transfer $60,278,800 as a performance deposit (which amount plus an amount equal to interest or other earnings actually earned thereon from the date of this Agreement to the Closing Date or date of termination of this Agreement being referred to as the “Deposit”). Seller will promptly invest such $60,278,800 in Permitted Investments. The Deposit will be retained by Seller and credited against the Purchase Price if Closing occurs or will otherwise be distributed in accordance with the terms of this Agreement.

ARTICLE 4

ADJUSTMENTS TO PURCHASE PRICE

The Purchase Price shall be adjusted as follows:

4.1. Increases in Purchase Price. The Purchase Price shall be increased by an amount equal to the sum of the following amounts:

4.1.1. The amount of costs and expenses actually paid by Seller related to owning, operating, producing and maintaining the Properties from the Effective Time to the Closing Date, including such capital expenditures as are permitted by Section 7.1, plus a fixed overhead charge of $150,000 per month;

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4.1.2. The amount of all prepaid expenses, including ad valorem, property and similar taxes and assessments, paid by Seller based upon or measured by ownership of the Properties and attributable to periods of time after the Effective Time;

4.1.3. The amount of all upward adjustments to the Purchase Price provided for elsewhere in this Agreement, including the amount, if any, by which the value of all Title Benefits exceeds $12,055,760; provided, however, that no Title Benefit valued at less than $50,000 shall be included in such calculation;

4.1.4. The value of (i) all oil and other Hydrocarbons in pipelines or flowlines or in tanks above the pipeline sales connection, in each case that at the Effective Time is credited to the Properties and (ii) all unsold inventory of gas plant products attributable to the Seller’s interests in the Leases, Lands, Wells and Contracts at the Effective Time, each such value to be the market or, if applicable, the contract price in effect as of the Effective Time, less any applicable severance taxes and royalties; and

4.1.5. Minden Transfer Expenses paid by Seller prior to Closing, not to exceed $500,000.

4.2. Decreases in Purchase Price. The Purchase Price shall be decreased by an amount equal to the sum of the following amounts:

4.2.1. The amount of all proceeds paid to Seller, including proceeds from the sale of production, net of all applicable taxes and royalties actually paid by Seller, attributable to the Properties for periods of time after the Effective Time;

4.2.2. An amount equal to all ad valorem, property and similar taxes and assessments unpaid as of the Closing Date based upon or measured by the ownership of the Properties and attributable to periods of time prior to the Effective Time;

4.2.3. The amount, if any, relating to (i) Retained Properties under Section 7.6; (ii) Title Defect Removals under Section 11.4 and (iii) Adverse Environmental Condition Removals under Section 12.5.3.

4.2.4. The amount, if any, by which the sum of the Uncured Title Defects Value exceeds $12,055,760; provided, however, notwithstanding the foregoing, if an Uncured Title Defect arises from a Title Defect described in Section 11.3.2, the Purchase Price will be decreased by the Defect Value thereof;

4.2.5. The amount of all other downward adjustments to the Purchase Price provided for elsewhere in this Agreement; and

4.2.6. The amount of funds that constitute Buyer’s Suspense Amounts.

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ARTICLE 5

REPRESENTATIONS AND WARRANTIES OF SELLER

5.1. Enduring. Enduring, with respect to itself, severally but not jointly, hereby represents and warrants to Buyer as of the date of this Agreement as follows:

5.1.1. Organization. Enduring is a limited liability company duly formed, validly existing and in good standing under the laws of the State of Delaware. Enduring is in good standing and duly qualified to do business in the State of Texas.

5.1.2. Authority. Enduring has full power to enter into and perform its obligations under this Agreement and has taken all proper limited liability company action to authorize the entering into of this Agreement and the performance of its obligations hereunder.

5.1.3. No Conflict. Neither the execution and delivery of this Agreement, nor the consummation of the transactions contemplated hereby, nor the compliance with the terms hereof will result in (with due notice or lapse of time or both) any default under, the creation or imposition of any lien or encumbrance on, or give rise to any right of termination, cancellation or acceleration under, any material agreement or instrument to which Enduring is a party (including its governing documents) or by which any of the Properties is bound, or violate any Law applicable to Enduring or to any of the Properties, other than (i) requirements to obtain those consents to assignment or waivers of preferential rights to purchase from third parties set forth in Schedule 5.4.2, (ii) Permitted Encumbrances described in clause (e) of the definition thereof and (iii) defaults or violations (other than with respect to the governing documents of Enduring) that could not reasonably be expected to have a Material Adverse Effect.

5.1.4. Enforceability. This Agreement has been duly executed and delivered on behalf of Enduring and constitutes (and the Assignment and any other document required hereunder to be executed by Enduring, when executed and delivered at Closing, will constitute) the legal, valid and binding obligation of Enduring, enforceable against it in accordance with their terms, except as limited by bankruptcy or other similar laws applicable generally to creditors’ rights and as limited by general equitable principles.

5.2. Mustang. Mustang, with respect to itself, severally but not jointly, hereby represents and warrants to Buyer as of the date of this Agreement as follows:

5.2.1. Organization. Mustang is a corporation duly organized, validly existing and in good standing under the laws of the State of Texas.

5.2.2. Authority. Mustang has full power to enter into and perform its obligations under this Agreement and has taken all proper corporate action to authorize the entering into of this Agreement and the performance of its obligations hereunder.

5.2.3. No Conflict. Neither the execution and delivery of this Agreement, nor the consummation of the transactions contemplated hereby, nor the compliance with the terms hereof will result in (with due notice or lapse of time or both) any default under, the

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creation or imposition of any lien or encumbrance on, or give rise to any right of termination, cancellation or acceleration under, any material agreement or instrument to which Mustang is a party (including its governing documents) or by which any of the Properties is bound, or violate any Law applicable to Mustang or to any of the Properties, other than (i) requirements to obtain those consents to assignment or waivers of preferential rights to purchase from third parties set forth in Schedule 5.4.2, (ii) Permitted Encumbrances described in clause (e) of the definition thereof and (iii) defaults or violations (other than with respect to the governing documents of Mustang) that could not reasonably be expected to have a Material Adverse Effect.

5.2.4. Enforceability. This Agreement has been duly executed and delivered on behalf of Mustang and constitutes (and the Assignment and any other documents required hereunder to be executed by Mustang, when executed and delivered at Closing, will constitute) the legal, valid and binding obligation of Mustang, enforceable against it in accordance with their terms, except as limited by bankruptcy or other similar laws applicable generally to creditors’ rights and as limited by general equitable principles.

5.3. Minden. Seller represents and warrants jointly and severally to Buyer as of the date of this Agreement as follows:

5.3.1. Organization. Minden is a limited liability company duly formed, validly existing and in good standing under the laws of the State of Texas.

5.3.2. Authority. Minden has full power to enter into and perform its obligations under this Agreement and has taken all proper limited liability company action to authorize the entering into of this Agreement and the performance of its obligations hereunder.

5.3.3. No Conflict. Neither the execution and delivery of this Agreement, nor the consummation of the transactions contemplated hereby, nor the compliance with the terms hereof will result in (with due notice or lapse of time or both) any default under, the creation or imposition of any lien or encumbrance on, or give rise to any right of termination, cancellation or acceleration under, any material agreement or instrument to which Minden is a party (including its governing documents) or by which any of the Properties is bound, or violate any Law applicable to Minden or to any of the Properties, other than (i) requirements to obtain those consents to assignment or waivers of preferential rights to purchase from third parties set forth in Schedule 5.4.2, (ii) Permitted Encumbrances described in clause (e) of the definition thereof and (iii) defaults or violations (other than with respect to the governing documents of Minden) that could not reasonably be expected to have a Material Adverse Effect.

5.3.4. Enforceability. This Agreement has been duly executed and delivered on behalf of Minden and constitutes (and the Assignment and any other documents required hereunder to be executed by Minden, when executed and delivered at Closing, will constitute) the legal, valid and binding obligation of Minden, enforceable against it in accordance with their terms, except as limited by bankruptcy or other similar laws applicable generally to creditors’ rights and as limited by general equitable principles.

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5.4. Seller. Seller represents and warrants jointly and severally to Buyer as of the date of this Agreement that:

5.4.1. Contracts. Schedule 5.4.1 describes (i) all of the unit agreements, farmout and farmin agreements, pooling agreements, pooling designations, unit operating agreements and operating agreements, exploration agreements, participation agreements, transportation and gathering agreements, rig contracts, pipe and other supply contracts and area of mutual interest agreements included in the Properties, (ii) all of the production sales, marketing and processing agreements included in the Properties, other than such agreements which are terminable by Seller without penalty on 90 or fewer days’ notice, (iii) any contracts or agreements (other than contracts for utility services) included in or burdening the Properties that could reasonably be expected to obligate Seller to expend or pursuant to which Seller may receive in excess of $250,000 in any calendar year, (iv) any contract or agreement included in or related to the Properties that is with any affiliate of Seller (excluding agreements between or among Enduring or Mustang, on the one hand, and Minden, on the other, except to the extent such agreements are required to be listed on Schedule 5.4.1 pursuant to the other clauses of this Section 5.4.1) and (v) any contract or agreement that evidences an obligation to pay the deferred purchase price of property or services ((i) – (v) collectively, the “Material Contracts”). No Seller has received written notice of any default under any of the Material Contracts or the Leases other than defaults that, individually or in the aggregate, could not reasonably be expected to have a Material Adverse Effect. The Material Contracts and the Leases are in full force and effect and have not been modified or amended in any material respect, and Seller is not in default thereunder, except to the extent that any of the foregoing could not reasonably be expected, individually or in the aggregate, to have a Material Adverse Effect.

5.4.2. Preferential Purchase Rights/Consents. Except as set forth in Schedule 5.4.2 and for Permitted Encumbrances described in clause (e) of the definition thereof, there are no consents, approvals or authorizations required to be obtained for, or preferential purchase rights exercisable in connection with, the assignment of any Property to Buyer. Except as set forth on Schedule 5.4.2 and except with respect to non-proprietary seismic data, there are no material restrictions on the transfer of, or the requirement of the payment of a transfer or licensing fee with respect to, any of the Material Contracts.

5.4.3. Litigation and Claims. Except as set forth on Schedule 5.4.3, no suit, action, claim, investigation, demand, proceeding, lawsuit or other litigation is pending or, to Seller’s Knowledge, threatened with respect to (i) any Seller that has a material adverse effect on the ability of such Seller to consummate the transactions contemplated by this Agreement, (ii) any Seller and which relates to any of the Properties or (iii) any of the Properties.

5.4.4. Finder’s Fees. Seller has not incurred any liability, contingent or otherwise, for brokers’ or finders’ fees with respect to this transaction for which Buyer will have any responsibility whatsoever.

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5.4.5. Sale Contracts. Except as set forth on Schedule 5.4.5, there are no contracts or options outstanding for the sale, exchange or transfer of the Properties or any portion thereof.

5.4.6. Notices; Compliance with Laws. Seller’s operation of the Properties is not subject of any pending regulatory compliance or enforcement action and Seller has not received written notice, which has not heretofore been complied with, of any violation of any statute, law, ordinance, rule, regulation, order, ruling, restriction, writ, injunction, judgment or decree (collectively, “Laws”) issued with respect to the Properties. To the Knowledge of Seller, Seller and the Properties are in compliance in all material respects with all Laws in any way affecting or relating to the Properties.

5.4.7. Imbalances. Except as set forth on Schedule 5.4.7, there are no gas or other hydrocarbon production, pipeline, transportation or processing imbalances existing as of the Effective Time with respect to any of the Properties.

5.4.8. Property Obligations. All rentals, royalties, shut-in royalties, overriding royalties and other payments due pursuant to or with respect to the Properties required to be paid by Seller have been properly paid, except for such failures to pay that could not reasonably be expected to have a Material Adverse Effect.

5.4.9. Property Operation. The Wells and units listed on Exhibit B have been drilled, completed, operated, developed and produced in material compliance with all applicable Laws and all necessary certificates, consents, permits, licenses and other governmental authorizations that are material to the ownership, use or operation of the Properties have been obtained and are in full force and effect and all fees and charges related thereto have been paid. No representation is made in this Section 5.4.9 with respect to compliance with Environmental Laws or the obtaining and status of Environmental Permits, which are dealt with exclusively in Section 5.4.21.

5.4.10. Take-or-Pay; Payout. To Seller’s Knowledge, except as set forth on Exhibit B, Seller is not obligated, under a take-or-pay or similar arrangement, or by virtue of an election to non-consent, or not participate in a past or current operation on the Properties pursuant to the applicable operating agreement or otherwise, to produce Hydrocarbons, or allow Hydrocarbons to be produced, without receiving full payment at the time of delivery in an amount that corresponds to the Net Revenue Interest set forth in Exhibit B in the Hydrocarbons attributable to the affected Well or unit described in Exhibit B. Schedule 5.4.10 contains a complete and accurate list of the status of any “payout” balance as of the respective dates set forth therein for the Wells listed thereon.

5.4.11. Taxes. All taxes that are due based on or measured by the ownership of any Property, the production or removal of Hydrocarbons therefrom or the receipt of proceeds therefrom and required to be paid by Seller have been properly paid.

5.4.12. Timely Receipt. To Seller’s Knowledge, Seller is timely receiving, in all material respects, its share of proceeds from the sale of Hydrocarbons produced from or attributable to the Properties without suspense, counterclaim or set-off. There has been no

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production of Hydrocarbons from the Properties in excess of the allowable production established pursuant to applicable state or federal Law that would result in any restriction on production from or attributable to the Properties subsequent to the Effective Time.

5.4.13. Timely Payment. Seller has paid its share of all costs and expenses payable by it under or with respect to the Properties, except those being contested in good faith and listed on Schedule 5.4.13.

5.4.14. Outstanding Obligations. Except as otherwise described in Schedule 5.4.14, there are no outstanding authorizations for expenditures or other written commitments or proposals to conduct operations on the Properties.

5.4.15. Well and Facility Status. There are no Wells included in the Properties that (i) Seller is obligated by Law or contract to currently plug and abandon or (ii) are subject to exceptions to a requirement to plug and abandon issued by a governmental authority. Seller has not installed any underground storage tanks or constructed any unlined production pits in, on or underlying any of the Properties and, to the Knowledge of Seller, no underground storage tanks or unlined production pits have been installed or constructed by any one else in, on or underlying any of the Properties.

5.4.16. No Tax Partnership. The Properties are not subject to any tax partnership agreement or provisions requiring a partnership income tax return to be filed under Subchapter K of Chapter 1 of Subtitle A of the Internal Revenue Code of 1986, as amended.

5.4.17. Condition of Properties. The machinery, equipment, tangible personal property, fixtures and improvements included in the Properties are, taken as a whole, in operable condition.

5.4.18. Hedging. None of the Properties is subject to or is bound by any futures, hedge, swap, collar, put, call, option or other commodities contract or agreement, excluding production sales marketing agreements listed on Schedule 5.4.1, transportation and processing agreements.

5.4.19. Insurance. Schedule 5.4.19 contains a true and complete list of all policies of insurance which are maintained by Seller and which cover or relate to any of the Properties for any period from and after the Effective Time.

5.4.20. Bankruptcy. There are no bankruptcy, reorganization or arrangement proceedings pending against, being contemplated by, or, to the Knowledge of Seller, threatened against any of Seller.

5.4.21. Environmental. Except as set forth in Schedule 5.4.21, to the Knowledge of Seller: (i) neither Seller nor any prior owner or operator of the Properties has caused or allowed the generation, use, treatment, storage or disposal of Hazardous Materials at or on any of the Properties except in compliance with all applicable Environmental Laws; (ii) Seller has conducted its operations on the Properties in compliance with all limitations, restrictions, standards and obligations established under Environmental Laws; (iii) Seller

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has obtained all Environmental Permits necessary for its operations on the Properties, and has operated and is operating in compliance with such Environmental Permits; (iv) there are no Environmental Liabilities pending or threatened by or before any court or any other governmental authority directed against Seller relating to its operations on the Properties that pertain or relate to (a) any Remedial Actions under any applicable Environmental Law, (b) non-compliances or alleged non-compliances by Seller of any Environmental Law or (c) personal injury or property damage claims relating to a release of Hazardous Materials; and (v) there are no Adverse Environmental Conditions. Seller has provided Buyer with copies of reports in its possession reflecting any Adverse Environmental Conditions of any Property, any prior Phase I or II Environmental Site Assessments relating to the Properties, and any violations of Environmental Law known to Seller that have not been remedied.

5.4.22. Minden Gas Gathering System. Minden has good and defensible title to (i) the Minden Gas Gathering System, (ii) the Minden Gas Gathering Easements (title to which is of record) and (iii) all fixtures, buildings and improvements located on the Minden Gas Gathering Easements. The Minden Gas Gathering System, the Minden Gas Gathering Easements and the other real property referenced in subsection (iii) of this Section 5.4.22 are free and clear of all liens and encumbrances other than any Permitted Encumbrance. To the Knowledge of Seller, the entirety of the Minden Gas Gathering System is located on or beneath land covered by a Minden Gas Gathering System Easement.

5.4.23. Suspense Funds. Schedule 5.4.23 contains a listing showing all proceeds from production attributable to the Properties that are held in suspense as of the date of this Agreement and sets forth the reason (as reflected in Seller’s records) that such proceeds are being held in suspense.

ARTICLE 6

REPRESENTATIONS AND WARRANTIES OF BUYER

Buyer represents and warrants to Seller as of the date of this Agreement that:

6.1. Organization. Buyer is a corporation duly organized, validly existing and in good standing under the laws of the State of Delaware. Buyer is in good standing and duly qualified to do business in the State of Texas.

6.2. Authority. Buyer has full power to enter into and perform its obligations under this Agreement and has taken all proper corporate action to authorize the entering into of this Agreement and the performance of its obligations hereunder.

6.3. No Conflicts. Neither the execution and delivery of this Agreement, nor the consummation of the transactions contemplated hereby, nor the compliance with the terms hereof will result in (with due notice or lapse of time or both) any default under, the creation or imposition of any lien or encumbrance on, or give rise to any right of termination, cancellation or acceleration under, any material agreement or instrument to which Buyer is a party (including its governing documents), or violate any Law applicable to Buyer, other than defaults or violations

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(other than with respect to the governing documents of Buyer) that could not reasonably be expected to have a material adverse effect on the ability of Buyer to consummate the transactions contemplated by this Agreement.

6.4. Enforceability. This Agreement has been duly executed and delivered on behalf of Buyer and constitutes the legal, valid and binding obligation of Buyer, enforceable against it in accordance with its terms, except as limited by bankruptcy or other similar laws applicable generally to creditor’s rights and as limited by general equitable principles.

6.5. Basis of Buyer’s Decision; Property Review. Buyer:

6.5.1. Has such knowledge and experience in financial and business matters that it is capable of evaluating the merits and risks of its investment in the Properties contemplated hereby, and is able to bear the economic risk of such investment indefinitely;

6.5.2. Has (i) had the opportunity to meet with officers and other representatives of Seller to discuss the Properties and (ii) received, or pursuant to the terms of this Agreement will have the right to receive, all materials, documents and other information that Buyer deems necessary or advisable to evaluate the Properties;

6.5.3. Has made or will make its own independent examination, investigation, analysis and evaluation of the Properties, including its own estimate of the value of the Properties; and

6.5.4. Has undertaken or will undertake such due diligence pertaining to the Properties as Buyer deems adequate, including that described above.

6.6. Buyer’s Experience and Counsel. Buyer is an experienced and knowledgeable investor and operator in the oil and gas business. Prior to entering into this Agreement, Buyer was advised by and has relied, in addition to the terms and provisions of this Agreement, solely on its own expertise and legal, tax, engineering, and other professional counsel concerning this Agreement, the Properties and the value thereof.

6.7. Closing Funds. At Closing, Buyer will have sufficient funds to enable the payment to Seller by wire transfer of the Preliminary Purchase Price in accordance with Section 14.3.2 and otherwise to perform Buyer’s obligations under this Agreement.

6.8. No Further Distribution. Buyer is acquiring the Properties for its own account and not with a view to, or for offer of resale in connection with, a distribution thereof, within the meaning of the Securities Act, and any other Laws pertaining to the distribution of securities. Except for traditional financing from reputable financial institutions or reputable energy industry capital providers, Buyer has not sought or solicited, nor is Buyer participating with, investors, partners or other third parties in order to fund the payment of the Preliminary Purchase Price in accordance with Section 14.3.2 and otherwise to perform Buyer’s obligations under this Agreement, and all funds used by Buyer in connection with this transaction are Buyer’s own funds.

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6.9. Buyer’s Ability to Take Title. Buyer is unaware of any fact or circumstance that would preclude or inhibit approval by any governmental agency of Seller’s assignment of the Properties to Buyer, including meeting existing or increased bonding or other security requirements.

6.10. Buyer’s Ability to Operate. Buyer is unaware of any fact or circumstance that would preclude or inhibit Buyer’s qualification to operate any Leases or Facilities previously operated by Seller, including meeting existing or bonding or other security requirements of any lessee or governmental agency.

6.11. Finder’s Fees. Buyer has not incurred any liability, contingent or otherwise, for brokers’ or finders’ fees with respect to this transaction for which Seller will have any responsibility whatsoever.

ARTICLE 7

COVENANTS OF SELLER

7.1. Conduct of Business Pending Closing. From the date hereof to the Closing Date, except as disclosed in Schedule 7.1 or as otherwise consented to in writing by Buyer, Seller will:

7.1.1. Not (i) act in any manner with respect to the Properties other than in the normal, usual and customary manner, consistent with prior practice; (ii) dispose of, encumber or relinquish any of the Properties (other than any relinquishment resulting from the expiration of any Lease or Material Contract in accordance with its terms that does not result from a failure of Seller to comply with Section 7.1.7); (iii) waive, compromise or settle any material right or claim with respect to any of the Properties; or (iv) except with respect to those matters identified in Schedule 5.4.14, make capital or workover expenditures with respect to the Properties in excess of $250,000 (net to Seller’s interest) in the aggregate or except if required by an emergency when there shall have been insufficient time to obtain advance consent (in which case Seller will promptly notify Buyer of any such emergency expenditures);

7.1.2. Use commercially reasonable efforts to preserve relationships with all third parties having business dealings with respect to the Properties;

7.1.3. Cooperate with Buyer in the notification of all applicable governmental regulatory authorities of the transactions contemplated hereby and cooperate with Buyer in obtaining the issuance by each such authority of such permits, licenses and authorizations as may be necessary for Buyer to own and operate the Properties following the Closing;

7.1.4. Use commercially reasonable efforts to seek appointment of Buyer as the successor operator to Seller with respect to all Properties currently operated by Seller;

7.1.5. Maintain all insurance listed on Schedule 5.4.19;

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7.1.6. Use commercially reasonable efforts to obtain (i) the consents, approvals and authorizations and (ii) waiver of the preferential purchase rights listed (or which should be listed) on Schedule 5.4.2;

7.1.7. Use commercially reasonable efforts to maintain and keep the Properties in full force and effect and, with respect to any Lease that would expire or terminate after the date hereof and prior to the Closing Date pursuant to its terms, use commercially reasonable efforts to extend or renew any such Lease to the extent permitted under the terms and provisions of such Lease;

7.1.8. Use commercially reasonable efforts to maintain and keep in full force and effect, and perform and comply in all material respects with all of its obligations under, contracts and agreements included in, relating to or affecting the Properties; and

7.1.9. Give prompt written notice to Buyer of any notice of default (or threat of default, whether disputed or denied) received or given by any Seller under any instrument or agreement affecting the Properties to which any Seller is a party or by which any Seller or any of the Properties is bound.

7.2. Access. Seller will afford to Buyer and its authorized representatives reasonable access, at Buyer’s sole risk and expense, from the date hereof until the Closing Date during normal business hours, to (i) the Properties operated by Seller; provided, however, that Buyer shall indemnify and hold harmless the Seller Group from and against any and all Claims arising from Buyer’s inspection of the Properties (including Claims for personal injuries, property damage and reasonable attorneys’ and experts’ fees, AND SPECIFICALLY FOR CLAIMS ARISING OUT OF OR PARTIALLY (BUT NOT FULLY) CAUSED BY THE NEGLIGENCE (BUT NOT THE GROSS NEGLIGENCE) OF SELLER OR ITS AGENTS OR REPRESENTATIVES), and (ii) Seller’s operating, accounting, contract, corporate and legal files, records, materials, data and information regarding the Properties (“Data”); provided, however, that Data shall not include (x) any legal materials, the disclosure of which Seller determines would jeopardize the assertion of a privilege in ongoing or anticipated litigation with third parties, which legal materials are listed on Schedule 7.2 or (y) information, the disclosure of which would violate any confidentiality agreement to which Seller is bound with any third party, which information is listed on Schedule 7.2.

7.3. Satisfaction of Conditions. Seller will use commercially reasonable efforts to take all actions and to do all things necessary to consummate, make effective and comply with all of the terms of this Agreement (including satisfaction, but not waiver, of the Closing conditions for which Seller is responsible or otherwise in control).

7.4. Non-Solicitation. Seller agrees that, between the date hereof and Closing, Seller will not itself or through any investment banker, broker, agent, representative or affiliate, directly or indirectly, (i) offer to sell, or solicit, negotiate or seek in any other way offers or proposals to purchase, all or any portion of the Properties, (ii) provide any third parties, other than Buyer and its representatives, with access to data concerning the purchase of all or any portion of the Properties, or (iii) take any similar actions with respect to a sale of the stock or other equity interest in Seller or any merger, consolidation or business combination involving Seller. Seller

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shall notify Buyer if, between the date hereof and Closing, any written offer or proposal is received by, or any negotiation is sought in writing to be initiated or continued with, Seller or any of its investment bankers, brokers, agents, representatives or affiliates with respect to any of the foregoing.

7.5. Non-compete. For a period of five years following the Closing, Seller covenants and agrees in favor of Buyer that neither Seller nor any officer or controlled affiliate of any Seller will purchase or otherwise obtain, either directly or indirectly, any interest in any of the property included with the geographical area outlined on the plat attached to this Agreement as Schedule 7.5 (the “Restricted Area”). If within this 5-year period, any of Seller acquires any property, or the right to acquire any property, within the Restricted Area in connection with an acquisition of a package of properties that includes any properties within the Restricted Area (the “Acquiror”), the Acquiror will offer Buyer the opportunity to acquire the portion of those properties located within the Restricted Area (or cause the person proposing to sell or convey such properties to the Acquiror to offer such properties directly to Buyer) at the same price or for the same consideration paid or given by, or required to be paid or given by the Acquiror (as allocated, to the properties in the Restricted Area between the Acquiror and the property seller, acting reasonably), and otherwise on the same terms and conditions applicable to the Acquiror’s acquisition or proposed purchase thereof.

7.6. Consent Requirements.

7.6.1. If a consent, approval or authorization listed (or which should be listed) on Schedule 5.4.2 (other than a Minden Consent) is not obtained, complied with or otherwise satisfied prior to the Closing Date, then, at Buyer’s option, any Property or portion thereof affected by such consent, approval or authorization (a “Retained Property”) shall be held back from the Properties 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 thereof or, if an Allocated Value has not been assigned to such Retained Property, by a portion of the Allocated Value of the Property to which such Retained Property relates, or is associated with or appurtenant to. In the event that on or before sixty (60) days following the Closing any consents, approvals or authorizations affecting a Retained Property are obtained, complied with or otherwise satisfied, then a separate closing on each such Retained Property will be held otherwise in accordance with the terms of this Agreement on the date that the Final Settlement Statement is agreed by the Parties, at which time Seller will convey all such Retained Properties to Buyer and Buyer will pay to Seller an amount which equals the aggregate of the amount withheld from the initial Closing on account of such Retained Properties pursuant to this Section 7.6 (as adjusted, pursuant to the Final Settlement Statement); provided, however, if the consent, approval or authorization relating to any Retained Property so held back at the initial Closing is not obtained, complied with or otherwise satisfied within sixty (60) days following the Closing Date, then such Retained Property shall be eliminated from the Properties and this Agreement; provided further, however, that, if Buyer, prior to the expiration of such sixty (60) day period, elects in writing to waive receipt of the consent, approval or authorization relating to the Retained Property which has not been obtained, complied with or satisfied, Seller shall immediately convey such Retained Property to Buyer for the portion of the Purchase Price withheld from the initial Closing with respect thereto.

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7.6.2. To the extent that the assignment of any Minden Gas Gathering Easement requires that prior to assignment, a Minden Consent must be obtained, this Agreement does not constitute an agreement to assign any such easement if an attempted assignment without any such consent would constitute a breach or violation thereof. In the event that any such Minden Consent is not obtained as of the Closing Date, the Parties will proceed with the Closing without any reduction to the Purchase Price on account thereof. In such case, Seller agrees that after Closing, it will continue to use commercially reasonable efforts to do or cause to be done all such things as are necessary and proper with respect to the Minden Gas Gathering Easements not assigned at Closing to (i) obtain all Minden Consents related thereto not obtained as of the Closing Date and (ii) assure that the rights of Minden under such easements are preserved for the benefit of Buyer (including any extension or renewal of any such easement). With respect to any portion of the Minden Gas Gathering System located on lands covered by a Minden Gas Gathering Easement not conveyed at Closing, Minden and Buyer will enter into a transportation agreement for nominal consideration pursuant to which Buyer will have all capacity rights and all operational responsibility with respect to each such portion and bear all ownership, operation, maintenance and other costs and risks of the Minden Gas Gathering System and, except to the extent of the Seller Retained Liabilities, defend and indemnify Seller against all such costs and risks. Buyer will make all filings necessary to be named the operator of the Minden Gas Gathering System (including with the Texas Railroad Commission) and to obtain and hold all Permits relating to the Minden Gas Gathering System. When any Minden Consents are obtained, Minden will assign the related easements to Buyer within ten days following receipt of such consents, and the transportation agreement with respect to the portion of the Minden Gas Gathering System located thereon will terminate. If a Minden Consent outstanding as of Closing is denied, or cannot be obtained at reasonable cost, unless otherwise directed by Buyer, Seller will, at its sole cost and expense, re-route the affected portion of the Minden Gas Gathering System to locations covered by easements purchased by Seller for the benefit and in the name of Buyer, at which time the transportation agreement with respect to the re-routed portion will terminate.

7.7. Transition Services. Between the date hereof and the Closing Date, each of Seller and Buyer shall use its reasonable efforts to negotiate in good faith a form of transition services agreement on terms that are mutually acceptable to Seller and Buyer to be executed at Closing by Seller and Buyer (the “Transition Services Agreement”).

7.8. Financial Statements.

7.8.1 Seller will use its commercially reasonable efforts to prepare, at the sole cost and expense of Buyer, either (i) if relief is granted by the SEC, statements of revenues and direct operating expenses and all notes thereto related to the Properties or (ii) if such relief is not granted by the SEC, the financial statements required by the SEC (such financial statements set forth in the foregoing clauses (i) and (ii), as applicable, the “Financial Statements”), in each case of clauses (i) and (ii), that will be required of

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Buyer by the SEC in connection with reports, registration statements and other filings to be made by Buyer related to the transactions contemplated by this Agreement with the SEC pursuant to the Securities Act, or the Exchange Act, in such form that such statements and the notes thereto can be audited. Seller (x) shall cooperate with and permit Buyer to reasonably participate in the preparation of the Financial Statements and (y) shall provide Buyer and its representatives with reasonable access to the personnel of Seller and its affiliates who engage in the preparation of the Financial Statements.

7.8.2. Seller will execute and deliver or cause to be executed and delivered to Erhardt Keefe Steiner Hottman PC (the “Auditor”) such representation letters, in form and substance customary for representation letters provided to external audit firms by management of Seller (if the financial statements are the subject of an audit), as may be reasonably requested by the Auditor, with respect to the Financial Statements, if (i) to the extent such a representation letter is delivered by Seller’s management, or on its behalf, Seller’s management is hereby indemnified and provided a defense by Buyer with regard to the execution, delivery or any other action related to the provision of such representation letter to the same extent as any executive officer or director of Buyer would be indemnified had they performed such action; (ii) Buyer provides a customary representation letter to the Auditor, if reasonably requested; and (iii) Buyer’s existing outside auditors provide a customary representation letter to the Auditor, if reasonably requested.

7.8.3. Seller will engage the Auditor to perform an audit of the Financial Statements and will use commercially reasonable efforts to cause the Auditor to issue unqualified opinions with respect to the Financial Statements (the Financial Statements and related audit opinions being hereinafter referred to as the “Audited Financial Statements”) and provide its written consent for the use of its audit reports with respect to the Financial Statements in reports, registration statements or other documents filed by Buyer under the Exchange Act or the Securities Act, as needed. Buyer will reimburse Seller for all fees charged by the Auditor from and after the date of this Agreement with respect to the preparation and delivery by the Auditor to Buyer of the Audited Financial Statements and any other fees charged by the Auditor to facilitate Buyer’s ongoing compliance with SEC rules and regulations. Seller shall take all action as may be necessary to facilitate the completion of such audit and delivery of the Audited Financial Statements to Buyer as soon as reasonably practicable, but no later than ten (10) days prior to the date that such Audited Financial Statements would be required to be filed by Buyer with the SEC.

7.9. Receivership Proceedings. If any oil, gas and/or mineral lease is granted to any Seller prior to Closing pursuant to or in connection with any receivership proceeding described in Schedule 1.2, then the Parties will supplement Exhibit A to include such lease. Furthermore, with respect to any receivership proceeding described on Schedule 1.2 that remains unresolved prior to the Closing, Seller will handle any such proceeding until same is finally resolved or concluded and will promptly assign to Buyer any oil, gas and/or mineral lease that is granted to any Seller pursuant to or in connection with such proceeding.

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7.10. Drilling Contract. Reference is hereby made to that certain Drilling Bid Proposal and Daywork Drilling Contract dated May 3, 2007 (the “Drilling Contract”), by and between Enduring and Pioneer Drilling Services Ltd. (“Pioneer”). Seller does hereby covenant and agree to promptly enter into a new drilling contract for not less than three (3) wells with Pioneer or another party who is reasonably acceptable to Buyer on terms that are materially similar to the Drilling Contract.

ARTICLE 8

COVENANTS OF BUYER

8.1. Satisfaction of Conditions. Buyer will use commercially reasonable efforts to take all actions and do all things necessary to consummate, make effective and comply with all of the terms of this Agreement (including satisfaction, but not waiver, of the Closing conditions for which Buyer is responsible or otherwise in control).

ARTICLE 9

CONDITIONS PRECEDENT TO THE OBLIGATIONS OF SELLER

The obligations of Seller to be performed at the Closing are subject to the fulfillment (or waiver by Seller in its sole discretion), before or at the Closing, of each of the following conditions:

9.1. Representations and Warranties. The representations and warranties by Buyer set forth in Article 6 shall be true and correct in all material respects (if not qualified by materiality) or true and correct in all respects (if qualified by materiality) at and as of the Closing as though made at and as of the Closing.

9.2. Covenants. Buyer shall have performed and complied in all material respects with all covenants and agreements required to be performed and complied with by it at or prior to Closing.

9.3. No Litigation. There shall be no suits, actions or other proceedings (excluding any initiated by Seller or any of its affiliates) pending or threatened seeking to restrain or prohibit the consummation of the transactions contemplated by this Agreement.

ARTICLE 10

CONDITIONS PRECEDENT TO THE OBLIGATIONS OF BUYER

The obligations of Buyer to be performed at the Closing are subject to the fulfillment (or waiver by Buyer in its sole discretion), before or at the Closing, of each of the following conditions:

10.1. Representations and Warranties. The representations and warranties of Seller set forth in Article 5 shall be true and correct in all material respects (if not qualified by materiality) or true and correct in all respects (if qualified by materiality) as of the Closing as though made at and as of the Closing.

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10.2. Covenants. Seller shall have performed and complied in all material respects with all covenants and agreements required to be performed and complied with by it at or prior to Closing.

10.3. No Litigation. There shall be no suits, actions or other proceedings (excluding any initiated by Buyer or any of its affiliates) pending or threatened seeking to restrain or prohibit the consummation of the transactions contemplated by this Agreement.

10.4. Consents. All consents, approvals and authorizations required to be obtained by Seller before Closing (excluding Minden Consents) and set forth on Schedule 5.4.2 (or which, if required for the assignment of a Property other than a Contract which is not a Material Contract, should have been set forth on Schedule 5.4.2) shall have been obtained or shall have expired without being exercised.

10.5. Release of Liens. All mortgages, deeds of trust and other liens burdening the Properties, if any (other than Permitted Encumbrances), granted by Seller or any of their respective affiliates will have been released at or before Closing.

10.6. Drilling Contract. Seller shall have satisfied its obligations under Section 7.10.

ARTICLE 11

TITLE MATTERS

11.1. Title Defect Notice. Buyer shall in good faith provide Seller with written notice (a “Title Defect Notice”) at or before the Defect Notification Deadline of any fact that causes Seller’s title to any Property to be less than Good and Defensible Title (“Title Defect”), in each case together with, in reasonable detail, a description of (i) the Well and/or unit with respect to which the claimed Title Defect(s) relate, (ii) the nature of such claimed Title Defect(s) and (iii) Buyer’s calculation of the value of each claimed Title Defect(s) in accordance with the guidelines set forth in Section 11.3. Any Title Defect that is not identified in a properly and timely delivered Title Defect Notice will thereafter conclusively be deemed waived for purposes of this Article 11.

11.2. Determination of Title Defects and Defect Values.

11.2.1. Within five Business Days after Seller’s receipt of a Title Defect Notice, Seller will notify Buyer as to whether Seller agrees with the Title Defects claimed therein and the values proposed for those Title Defects. If Seller does not agree with any claimed Title Defect or any proposed value, then the Parties will promptly enter into good faith negotiations and will attempt to agree on those matters. The value agreed by the Parties with respect to a Title Defect will be the Defect Value for that Title Defect.

11.2.2. If the Parties cannot reach agreement concerning either the existence of a Title Defect or a value therefor with respect to any Property within five Business Days after the date Buyer receives the notice from Seller under Section 11.2.1, then, upon either Party’s written request, the Parties will submit the dispute to a mutually acceptable attorney or other consultant experienced in title examination in the State of Texas for prompt resolution; provided, however, that if at any time any consultant so chosen fails or

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refuses to perform hereunder, a new consultant will be chosen by the Parties. The cost of any such consultant will be borne 50% by Seller and 50% by Buyer. For any dispute resolution proceeding, Seller and Buyer will present a written statement of their respective positions on the dispute to the consultant within three Business Days after the consultant is selected, and within ten Business Days of receipt of such statements the consultant will make a determination of all points of disagreement in accordance with the terms and conditions of this Agreement. The determination by the consultant will be conclusive and binding on the Parties and will be enforceable against each Party in any court of competent jurisdiction, and the value determined by the consultant with respect to a Title Defect will be the Defect Value for that Title Defect. If necessary to complete such determination, the Closing Date will be deferred until the consultant has made a determination of the disputed issues with respect thereto and all subsequent dates and required activities having reference to the Closing Date will be correspondingly deferred; provided, however, that unless the Parties agree to the contrary, the Closing Date will not be deferred under this Section 11.2.2 for more than five Business Days after the date on which the consultant has made its determination of the disputed issues hereunder.

11.3. Calculation of Defect Value.

11.3.1. If a Title Defect exists because Seller owns a lesser Net Revenue Interest in a Property than that shown for such Property on Exhibit B, then the Defect Value with respect to such Title Defect shall be the amount equal to the product of (i) the Allocated Value of such Property multiplied by (ii) a fraction, the numerator of which is the difference between (x) the Net Revenue Interest for the affected Property set forth on Exhibit B minus (y) the Net Revenue Interest for that Property agreed or determined to be owned by Seller and the denominator of which is the Net Revenue Interest for that Property set forth on Exhibit B.

11.3.2. If a Title Defect is a lien, encumbrance or other charge upon a Property that is liquidated in amount, but the Title Defect is not a Minimal Defect, the Defect Value shall be an amount sufficient to fully discharge such lien, encumbrance or other charge.

11.3.3. If a Title Defect results from any matter not described in Section 11.3.1 or Section 11.3.2, the Defect Value shall be an amount equal to the difference between the value of the Property affected by such Title Defect without such Title Defect and the value of such Property with such Title Defect (taking into account the Allocated Value of the Property).

11.4. Properties Subject to Title Defects.

11.4.1. Seller has the right, but not the obligation, at its sole cost and expense, to cure within sixty (60) days after the Closing Date (the “Cure Deadline”) any fact or circumstance agreed or determined to be a Title Defect. If, prior to the Cure Deadline, a Title Defect affecting any Property conveyed to Buyer at the Closing is cured by Seller to the reasonable satisfaction of Buyer, Buyer will pay to Seller pursuant to the Final Settlement Statement an amount which is equal to the amount by which the Purchase Price was reduced pursuant to Section 4.2.4 on account of such Title Defect.

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11.4.2. With respect to any Property that as of the Closing Date is subject to an outstanding preferential purchase right that has not been exercised or waived, or deemed waived by the lapse of the period within which such right may have been exercised, the affected Property, or pro rata portion thereof, will not be conveyed at the Closing and the Purchase Price payable at Closing shall be reduced by the Allocated Value thereof. In the event that prior to the Cure Deadline, any preferential purchase right affecting any Property, or portion thereof, expires without being exercised, then a separate closing on those Properties will be held otherwise in accordance with the terms of this Agreement on the date that the Final Settlement Statement is agreed between the Parties, at which time Seller will convey all such Properties to Buyer and Buyer will pay to Seller an amount which equals the aggregate Allocated Value of the Properties so conveyed (as adjusted, pursuant to the Final Settlement Statement).

11.4.3. If a third party exercises an applicable preferential right of purchase with respect to any Property prior to Closing, the Purchase Price will be reduced by the Allocated Value of the affected Property or, if the preferential right affects less than 100% of the Property, a pro rata portion thereof calculated in accordance with Section 11.3.1, and the affected Property (or portion thereof) will be removed from this Agreement. The removal of a Property or portion thereof under this Section 11.4.3 is referred to as a “Title Defect Removal”.

11.5. Purchase Price Adjustment for Title Benefits. Seller will in good faith provide Buyer with written notice at or before the Defect Notification Deadline if Seller believes that it owns a greater Net Revenue Interest in a Property than is set forth in Exhibit B (without a proportionate increase in the Working Interest in such Property) (a “Title Benefit”). If it is agreed or determined prior to the Closing Date that Seller owns a Title Benefit, the value of such Title Benefit shall be an amount equal to the product of (i) the Allocated Value of the affected Property and (ii) a fraction, the numerator of which is the difference between the Net Revenue Interest for such Property agreed or determined to be owned by Seller and the Net Revenue Interest for such Property set forth on Exhibit B, and the denominator of which is the Net Revenue Interest for such Property set forth on Exhibit B.

ARTICLE 12

ENVIRONMENTAL MATTERS

12.1. Presence of Wastes, NORM, Hazardous Substances and Asbestos. BUYER ACKNOWLEDGES THAT THE PROPERTIES HAVE BEEN USED TO EXPLORE FOR, DEVELOP, AND PRODUCE HYDROCARBONS, AND THAT SPILLS OF WASTES, CRUDE OIL, PRODUCED WATER, HAZARDOUS SUBSTANCES AND OTHER MATERIALS MAY HAVE OCCURRED THEREON. ADDITIONALLY, THE PROPERTIES, INCLUDING PRODUCTION EQUIPMENT, MAY CONTAIN ASBESTOS, HAZARDOUS SUBSTANCES OR NORM. NORM MAY AFFIX OR ATTACH ITSELF TO THE INSIDE OF WELLS, MATERIALS AND EQUIPMENT AS SCALE OR IN OTHER FORMS, AND NORM-CONTAINING MATERIAL MAY HAVE BEEN BURIED OR OTHERWISE DISPOSED OF ON THE PROPERTIES. A HEALTH HAZARD MAY EXIST IN CONNECTION WITH THE PROPERTIES BY REASON THEREOF. SPECIAL PROCEDURES MAY BE REQUIRED FOR REMEDIATION, REMOVING, TRANSPORTING AND DISPOSING OF ASBESTOS, NORM, HAZARDOUS SUBSTANCES AND OTHER MATERIALS FROM THE PROPERTY.

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12.2. Environmental Assessment. Buyer shall have the opportunity to conduct at its sole risk and expense an environmental assessment of the Properties; provided, however, that Seller has the right to have its representatives present at any on-site inspection or assessment, including any Phase II audit (which Buyer may not conduct unless it has provided Seller with at least two Business Days’ prior notice of its intention to do so). Seller will provide reasonable access for this purpose to Properties operated by Seller; for any Property not operated by Seller, Seller will reasonably cooperate with Buyer in contacting the operators of any such non-operated Property directly to arrange for access for the purposes of environmental assessment. While performing any environmental assessment, Buyer or any of its representatives and agents must comply with Seller’s environmental and safety rules and policies on Seller-operated Properties, and with the operator’s environmental and safety rules and policies on all other Properties. Prior to Closing, Buyer will not disclose any information obtained in its environmental assessment to third parties unless agreed to in writing by Seller or unless such disclosure is expressly required by applicable Law or is required pursuant to legal process of any court or governmental authority. To the extent permitted by Law, Buyer will notify Seller in advance of any such disclosure and will furnish Seller copies of all materials to be disclosed prior to any disclosure thereof. As soon as reasonably possible after Buyer’s receipt thereof, Buyer shall forward to Seller copies of all reports, data, analysis, test results, remediation costs estimates and recommended remediation procedure or other information concerning or derived from Buyer’s environmental assessment.

12.3. Notice of Adverse Environment Conditions. Buyer shall provide Seller with written notice (an “Adverse Environmental Condition Notice”) at or before the Defect Notification Deadline of any Adverse Environmental Condition discovered by Buyer in connection with its due diligence activities, in each case together with, in reasonable detail, a description of (i) the Well, unit and/or Lease, Easement or other Property with respect to which such Adverse Environmental Condition(s) is claimed, (ii) the nature of such Adverse Environmental Condition(s) and (iii) Buyer’s proposed calculation of the cost to remediate such Adverse Environmental Condition(s) (the “Remediation Value”).

12.4. Determination of Adverse Environmental Conditions and Remediation Values.

12.4.1. Within ten Business Days after Seller’s receipt of an Adverse Environmental Condition Notice, Seller will notify Buyer as to whether Seller agrees with the Adverse Environmental Conditions claimed therein and the Remediation Value proposed to be required for Remediation of the Adverse Environmental Conditions. If Seller does not agree with any claimed Adverse Environmental Condition or any proposed Remediation Value, then the Parties will promptly enter into good faith negotiations and will attempt to agree on such matters. The value agreed by the Parties with respect to an Adverse Environmental Condition will be the Remediation Value for that Adverse Environmental Condition, and will be the value used for the purpose of Sections 12.5.3 and 18.1.4.

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12.4.2. If the Parties cannot reach agreement concerning either the existence of a Adverse Environmental Condition or a Remediation Value therefor with respect to any Property within five Business Days after the date Buyer receives the notice from Seller under Section 12.4.1, then, upon either Party’s written request, the Parties will submit such dispute to a mutually acceptable environmental consultant or other consultant experienced in oil and gas producing property environmental remediation in the State of Texas for prompt resolution; provided, however, that if at any time any consultant so chosen fails or refuses to perform hereunder, a new consultant shall be chosen by the Parties. The cost of any such consultant will be borne 50% by Seller and 50% by Buyer. For any dispute resolution proceeding, Seller and Buyer will present a written statement of their respective positions on the dispute to the consultant within three Business Days after the consultant is selected, and within ten Business Days of receipt of such statements the consultant will make a determination of all points of disagreement in accordance with the terms and conditions of this Agreement. The determination by the consultant will be conclusive and binding on the Parties and will be enforceable against each Party in any court of competent jurisdiction, and the value determined by the consultant with respect to an Adverse Environmental Condition will be the Remediation Value for that Adverse Environmental Condition for purposes of Sections 12.5.3 and 18.1.4. If necessary to complete such determination, the Closing Date will be deferred until the consultant has made a determination of the disputed issues with respect thereto and all subsequent dates and required activities having reference to the Closing Date shall be correspondingly deferred; provided, however, that unless the Parties agree to the contrary, the Closing Date will not be deferred under this Section 12.4.2 for more than five Business Days after the date on which the consultant has made its determination of the disputed issues hereunder.

12.5. Properties Subject to Adverse Environmental Conditions.

12.5.1. Seller will Remediate any Adverse Environmental Condition, other than Minimal Defects, at Seller’s sole cost in accordance with applicable Environmental Laws. Seller will diligently pursue and complete such Remediation in accordance with the requirements of applicable Environmental Laws and the terms of the Leases. Buyer will allow Seller and its agents and representatives such access to the affected Property as is reasonably necessary for performance of the Remediation of such Adverse Environmental Conditions under this Section 12.5.1; provided, however, that Seller agrees that it will conduct its work so as not to unreasonably interfere with Buyer’s operations.

12.5.2. Seller’s obligation to Remediate any Adverse Environmental Conditions under this Section 12.5 will not be subject to the limitations set forth in Section 16.2.

12.5.3. Notwithstanding Section 12.5.1, with respect to any Property subject to an Adverse Environmental Condition with a Remediation Value in excess of (i) in the case of a Well or unit described in Exhibit B, the greater of (A) 25% of the Allocated Value of such Well or unit and (B) $2,000,000 and (ii) in the case of any other Property, $2,000,000, Seller has the option (which must be exercised by notice to Buyer at least five Business Days prior to Closing) to remove such Property from this Agreement, in which case the Purchase Price will be reduced by the Allocated Value of such Property. The removal of a Property or portion thereof under this Section 12.5.3 is referred to as an “Adverse Environmental Condition Removal”.

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ARTICLE 13

SUSPENSE FUNDS HELD BY SELLER

13.1. Suspense Funds Held By Seller. On or before five Business Days prior to the Closing Date, Seller will provide to Buyer a listing showing all proceeds from production attributable to the Properties that are currently held in suspense by Seller and the reason (as reflected in Seller’s records) that such proceeds are being held in suspense (“Buyer’s Suspense Amounts”). Seller will allow Buyer a credit against the Purchase Price equal to the amount thereof. Buyer will be responsible for proper distribution of all Buyer’s Suspense Amounts to the parties lawfully entitled thereto, and hereby agrees to indemnify, defend, and hold harmless the Seller Group from and against any and all Claims arising out of or relating to Buyer’s retention or distribution of such suspended proceeds.

ARTICLE 14

CLOSING

14.1. The Closing. The closing of the purchase and sale of the Properties pursuant to this Agreement (“Closing”) shall be held in Houston, Texas at the Seller’s counsel’s offices of Akin Gump Strauss Hauer & Feld LLP, 1111 Louisiana, Suite 4400, Houston, Texas 77002 on August 4, 2008 (“Closing Date”). If Closing is not consummated by the Closing Date due solely to the failure of any condition to Closing set forth in Sections 9.1 or 9.2 to be satisfied as of that date, Seller may terminate this Agreement and retain the Deposit as liquidated damages and as Seller’s sole and exclusive remedy for Buyer’s breach of this Agreement.

14.2. Closing Statement. Seller will provide Buyer with a closing statement reflecting its good faith estimation of the Purchase Price, as adjusted pursuant to Article 4 (the “Preliminary Purchase Price”), at least three Business Days prior to the Closing. There shall be attached to such closing statement such supporting documentation and other data as is reasonably necessary to substantiate the Preliminary Purchase Price reflected therein.

14.3. Closing Deliveries. At Closing the following events shall occur, each event under the control of one Party hereto being a condition precedent to the events under the control of the other Party, and each event being deemed to have occurred simultaneously with the other events:

14.3.1. Seller will execute and deliver to Buyer, and Buyer will execute and receive, (i) one or more instruments of assignment, in substantially the form of the Bill of Sale, Assignment and Assumption Agreement set forth as Exhibit D (the “Assignment”), (ii) assignments, on appropriate forms for filing with applicable governmental authorities, assigning Seller’s interest in the Leases to Buyer and (iii) the Transition Services Agreement;

14.3.2. Buyer will deliver via wire transfer to an account specified by Seller, in immediately available funds, the Preliminary Purchase Price less the Deposit;

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14.3.3. Seller will deliver a certificate executed by an authorized corporate officer of Seller, dated as of Closing, certifying on behalf of Seller that the conditions set forth in Section 10.1 and Section 10.2 have been fulfilled (the “Seller’s Certificate”); and Buyer will deliver a certificate executed by an authorized corporate officer of Buyer, dated as of Closing, certifying on behalf of Buyer that the conditions set forth in Section 9.1 and Section 9.2 have been fulfilled;

14.3.4. Each Party will execute, acknowledge and deliver division orders, transfer orders or letters in lieu thereof that have been prepared by Seller and that are reasonably acceptable to Buyer directing all purchasers of production from the Properties to make payment to Buyer of proceeds attributable to such production occurring on or after the Effective Time;

14.3.5. As to those Properties operated by Seller or an affiliate, Seller and Buyer will execute all appropriate state or local forms that have been prepared by Seller and that are reasonably acceptable to Buyer that are required to be executed to effect the administrative change of operator of those Properties from Seller or its affiliate to Buyer;

14.3.6. With respect to any Wells or units for which Seller or an affiliate is designated as the operator under the applicable operating or other similar agreement, Seller or its affiliate will send letters to all non-operating working interest owners that have been prepared by Seller and that are reasonably acceptable to Buyer advising of Seller’s or its affiliate’s resignation as operator and recommending that Buyer be appointed as successor operator; and

14.3.7. Seller shall execute and deliver to Buyer a statement described in Treasury Regulation §1.1445-2(b)(2) certifying that Seller is not a foreign person within the meaning of the Internal Revenue Code of 1986, as amended.

14.4. Effect of Closing.

14.4.1. After Closing, all proceeds, accounts receivable, notes receivable, income, revenues, monies and other items included in the Properties, or attributable to the Properties after the Effective Time, shall belong to and be paid over to Buyer, and all proceeds, accounts receivable, notes receivable, income, revenues, monies and other items included in or attributable to the Properties prior to the Effective Time shall belong to and be paid over to Seller.

14.4.2. After Closing, all accounts payable and other costs and expenses incurred with respect to the Properties prior to the Effective Time shall be the obligation of and be paid by Seller and all accounts payable and other costs and expenses incurred with respect to the Properties after the Effective Time (other than those for which Seller is given credit in the determination of the adjusted Purchase Price pursuant to Article 4 or as adjusted pursuant to Article 15, each of which shall be the obligation of Seller) shall be the obligation of and be paid by Buyer.

14.4.3. If monies are received by any Party which, under the terms of this Section 14.4, belong to the other Party, the same shall immediately be paid over to the

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proper Party. If an invoice or other evidence of an obligation is received which under the terms of this Section 14.4 is partially the obligation of Seller and partially the obligation of Buyer, then the Parties shall consult each other and each shall promptly pay its portion of such obligation to the obligee.

ARTICLE 15

POST-CLOSING ADJUSTMENTS

15.1. Final Settlement Statement. After the Closing Date, Seller will prepare, in accordance with this Agreement, a statement, a copy of which will be delivered by Seller to Buyer no later than 60 days after the Closing Date, setting forth each adjustment to the Purchase Price contemplated by this Agreement and showing the calculation of those adjustments in accordance with Article 4, together with supporting documentation and other data as is reasonably necessary to substantiate the adjusted Purchase Price reflected therein (“Final Settlement Statement”). Buyer will have 30 days after receipt of the Final Settlement Statement to review the statement and to provide written notice to Seller of Buyer’s objection to any item on the statement. Buyer’s notice must clearly identify the item(s) objected to and the reasons and support for the objection(s). If Buyer does not provide written objection(s) within the 30-day period, the Final Settlement Statement will be deemed correct and will not be subject to further adjustment. If Buyer provides proper written objection(s) within the 30-day period, the Final Settlement Statement will be deemed correct with respect to the items with respect to which no objection was raised. Buyer and Seller will meet to negotiate and resolve any proper objections within 15 days of Seller’s receipt of Buyer’s objections. If the Parties agree on all of those objections, the adjusted Final Settlement Statement will be deemed correct and will not be subject to further adjustment. Any items not agreed to at the end of the 15-day period may, upon either Party’s written request, be resolved by arbitration in accordance with Section 15.2.

15.2. Arbitration. If the Parties cannot agree upon the Final Settlement Statement, the dispute will be submitted promptly to a mutually agreeable third-party accountant, which shall act as an arbitrator and promptly decide all points of disagreement with respect to the Final Settlement Statement. The decision of the arbitrator on all of those points will be final and binding upon the Parties and will be enforceable against each Party in any court of competent jurisdiction. The costs and expenses of the arbitrator shall be borne 50% by Seller and 50% by Buyer.

15.3. Payment of Final Purchase Price. If the Purchase Price shown on the Final Settlement Statement is more than the Preliminary Purchase Price, Buyer will pay the difference to Seller in immediately available funds within five Business Days after the Final Settlement Statement has been agreed by the Parties or decided by the arbitrator, as applicable. If the Purchase Price shown on the Final Settlement Statement is less than the Preliminary Purchase Price, Seller will pay the difference to Buyer in immediately available funds within five Business Days after the Final Settlement Statement has been agreed by the Parties or decided by the arbitrator, as applicable.

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ARTICLE 16

ALLOCATION OF RISK

16.1. Seller’s Indemnity. After Closing, subject to Section 16.2, Seller will indemnify and hold harmless the Buyer Group from and against any and all Losses suffered by Buyer Group arising from or relating to:

16.1.1. any breach of any representation or warranty made by Seller in Article 5; provided, however, that for purposes of determining whether any representation or warranty made by Seller in Article 5 (excluding Section 5.4.21) that is qualified by materiality (including Material Adverse Effect) or Knowledge has been breached, all such materiality and Knowledge qualifiers shall be disregarded as though they were not contained therein;

16.1.2. any breach of any covenant or agreement by Seller in this Agreement;

16.1.3. any Adverse Environmental Condition that Seller is required to Remediate pursuant to Section 12.5.1;

16.1.4. the offsite disposal, prior to the Closing and during Seller’s or any of its affiliates’ ownership of the Properties, of hazardous materials arising from the operation or use of the Properties;

16.1.5. the obligation to pay royalties, overriding royalties and other payments owing to third parties on account of production from the Properties prior to the Effective Time and during any Seller’s or any of its respective affiliates’ ownership of the Properties;

16.1.6. the matters described on Schedule 5.4.3;

16.1.7. any fines or penalties issued by a governmental authority arising out of any violations of Environmental Laws or Environmental Permits prior to the Closing Date and during Seller’s or any of its affiliates’ ownership of the Properties relating to the operation or use of the Properties;

16.1.8. any personal injury or property damage claims asserted by non-governmental third parties arising out of the operations relating to the Properties, or any release of Hazardous Materials on or before the Closing Date and during Seller’s or any of its affiliates’ ownership of the Properties; and

16.1.9. any transportation agreement entered into by and between Buyer and Minden pursuant to Section 7.6.2.

The matters for which Seller has the obligation to indemnify and hold harmless the Buyer Group under this Section 16.1, as limited by Section 16.2, are referred to herein as “Seller Retained Liabilities.”

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16.2. Limitations on Seller’s Indemnity. Notwithstanding anything to the contrary contained herein:

16.2.1. The representations and warranties made by Seller in this Agreement shall survive Closing for one (1) year following the Closing Date and shall not be actionable thereafter; provided, however, that notwithstanding the foregoing, the representations and warranties made by Seller in Section 5.4.21 shall survive the Closing only for six months following the Closing Date and shall not be actionable thereafter;

16.2.2. With respect to Seller’s obligations to indemnify and hold harmless Buyer Group from and against any and all Losses suffered by Buyer Group arising from or relating to any breach of any covenant or agreement by Seller in this Agreement which by its terms is required to be performed prior to Closing, these obligations shall survive Closing for one (1) year following the Closing Date and shall not be actionable thereafter with respect to any Claims thereafter arising from any such breach;

16.2.3. Seller’s aggregate liability to the Buyer Group for Losses under Section 16.1.1 related to breaches of Seller’s representations and warranties in Article 5 is limited to $120,557,600; and

16.2.4. Seller will have no liability to the Buyer Group for Losses related to breaches of Seller’s representations and warranties in Article 5 unless and until the aggregate Losses claimed under Section 16.1.1 exceeds $12,055,760, and then only to the extent of such excess (subject to the limitation of Section 16.2.3).

16.3. Buyer’s Indemnity. Except to the extent of the Seller Retained Liabilities, after Closing, Buyer will indemnify and hold harmless the Seller Group from and against any and all Losses suffered by the Seller Group relating to (i) the ownership or operation of the Properties by Buyer from and after the Effective Time, (ii) all Adverse Environmental Conditions, including any such conditions arising out of or relating to any discharge, release, production, storage, treatment or any activities on or in the Properties, or the migration or transportation from any other lands to the Properties, whether before or after the Effective Time, of materials or substances that are at present, or become in the future, subject to regulation under Environmental Laws, whether such laws or regulations now exist or are hereafter enacted, INCLUDING ANY LOSSES ARISING IN WHOLE OR IN PART FROM THE SOLE OR CONCURRENT NEGLIGENCE OR STRICT LIABILITY OF ANY MEMBER OF THE SELLER GROUP and (iii) the obligations assumed by Buyer under Section 16.4. EXCEPT TO THE EXTENT OF THE SELLER RETAINED LIABILITIES, BUYER HEREBY RELEASES THE SELLER GROUP FROM AND AGAINST ANY AND ALL CLAIMS FOR CONTRIBUTION UNDER CERCLA, ANY OTHER PRESENT OR FUTURE ENVIRONMENTAL LAW OR OTHER LAW, OR UNDER COMMON LAW OR OTHERWISE.

16.4. Assumption by Buyer.

16.4.1. Except to the extent of the Seller Retained Liabilities, effective at Closing, Buyer hereby assumes and agrees to fully and timely pay, perform, and discharge in accordance with their terms, all duties, liabilities and obligations arising out of or otherwise related to the ownership and operation of the Properties by Buyer acquired by Buyer at Closing from and after the Effective Time.

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16.4.2. From and after the Closing, except to the extent of the Seller Retained Liabilities, (i) Buyer will comply with all Environmental Laws and all other applicable Laws and will properly obtain and maintain all permits required by public authorities with regard to the Properties, and will provide and maintain with the applicable regulatory agency(ies) all required bonds, and (ii) Buyer assumes all of Seller’s obligations with regard to abandonment of the Wells and all other existing unplugged wells on any Lands, whether producing or nonproducing, and abandonment of the leasehold Property including, where applicable, the plugging of wells and the restoration of the surface as completely as practicable and/or in compliance with all applicable Laws and in compliance with all Leases and other agreements included in or affecting the Properties, and will indemnify and hold the Seller Group harmless with respect to all of those obligations.

16.4.3. Buyer will remain liable under Sections 16.3 and 16.4 even if Buyer assigns, sells or transfers the Properties, or any portion thereof, to a third party.

16.5. Limitations of Warranties. Notwithstanding anything in this Agreement to the contrary, the Properties are being sold by Seller to Buyer without recourse, covenant, or warranty of any kind, express, implied, or statutory, except (i) to the extent of the Seller Retained Liabilities and except to the extent expressly provided in this Agreement or the Seller’s Certificate and (ii) that in the Assignment, Seller will warrant Good and Defensible Title to the Properties against every person whomsoever lawfully claiming or to claim the same or any part thereof by, through, or under Seller, but not otherwise. WITHOUT LIMITATION OF THE GENERALITY OF THE IMMEDIATELY PRECEDING SENTENCE AND EXCEPT TO THE EXTENT EXPRESSLY PROVIDED IN THIS AGREEMENT, THE SELLER’S CERTIFICATE OR IN THE ASSIGNMENT, SELLER IS CONVEYING THE PROPERTIES AS-IS, WHERE-IS AND WITH ALL FAULTS AND EXPRESSLY DISCLAIMS AND NEGATES (A) ANY IMPLIED OR EXPRESS WARRANTY OF MERCHANTABILITY, (B) ANY IMPLIED OR EXPRESS WARRANTY OF FITNESS FOR A PARTICULAR PURPOSE AND (C) ANY IMPLIED OR EXPRESS WARRANTY OF CONFORMITY TO MODELS OR SAMPLES OF MATERIALS. EXCEPT TO THE EXTENT EXPRESSLY PROVIDED IN THIS AGREEMENT, THE SELLER’S CERTIFICATE OR IN THE ASSIGNMENT, SELLER ALSO EXPRESSLY DISCLAIMS AND NEGATES ANY IMPLIED OR EXPRESS WARRANTY AT COMMON LAW, BY STATUTE OR OTHERWISE RELATING TO THE CONDITION OR STATE OF REPAIR OF ANY OF THE PROPERTIES. EXCEPT TO THE EXTENT EXPRESSLY PROVIDED IN THIS AGREEMENT, THE SELLER’S CERTIFICATE OR IN THE ASSIGNMENT, BUYER HEREBY WAIVES ANY WARRANTY OR REPRESENTATION, EXPRESS OR IMPLIED, WITH RESPECT TO THE ACCURACY, COMPLETENESS OR MATERIALITY OF THE INFORMATION, REPORTS, PROJECTIONS, MATERIALS, RECORDS, AND DATA NOW, HERETOFORE, OR HEREAFTER FURNISHED OR MADE AVAILABLE TO BUYER IN CONNECTION WITH THE PROPERTIES OR THIS AGREEMENT (INCLUDING ANY DESCRIPTION OF THE PROPERTIES, WORKING INTERESTS OR NET REVENUE INTERESTS, ENVIRONMENTAL CONDITION OF THE PROPERTIES, OR ANY OTHER MATTERS CONTAINED IN ANY OTHER MATERIAL FURNISHED OR MADE AVAILABLE TO

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BUYER BY SELLER OR BY SELLER’S AGENTS OR REPRESENTATIVES). EXCEPT TO THE EXTENT EXPRESSLY PROVIDED IN THIS AGREEMENT, THE SELLER’S CERTIFICATE OR IN THE ASSIGNMENT, ANY AND ALL SUCH INFORMATION, REPORTS, PROJECTIONS, MATERIALS, RECORDS AND DATA NOW, HERETOFORE OR HEREAFTER FURNISHED BY SELLER IS PROVIDED AS A CONVENIENCE ONLY AND ANY RELIANCE ON OR USE OF SAME IS AT BUYER’S SOLE RISK. SELLER ALSO EXPRESSLY DISCLAIMS AND NEGATES ANY IMPLIED OR EXPRESS WARRANTY AT COMMON LAW, BY STATUTE OR OTHERWISE RELATING TO THE ACCURACY OF ANY OF THE INFORMATION FURNISHED WITH RESPECT TO THE EXISTENCE OR EXTENT OF RESERVES OR THE VALUE OF THE PROPERTIES BASED THEREON, THE QUALITY OR QUANTITY OF HYDROCARBON RESERVES (IF ANY), PRODUCTION RATES, RECOMPLETION OPPORTUNITIES, DECLINE RATES, PRICING ASSUMPTIONS, ABILITY OR POTENTIAL FOR PRODUCTION OF HYDROCARBONS FROM THE LEASES, RESERVES CATEGORIZATION; THIS DISCLAIMER AND DENIAL OF WARRANTY ALSO EXTENDS TO THE EXPRESS OR IMPLIED REPRESENTATION OR WARRANTY AS TO THE PRICES BUYER AND SELLER ARE OR WILL BE ENTITLED TO RECEIVE FROM PRODUCTION OF HYDROCARBONS FROM THE PROPERTIES, IT BEING UNDERSTOOD THAT ALL RESERVE, PRICING AND VALUE ESTIMATES UPON WHICH BUYER HAS RELIED OR IS RELYING HAVE BEEN DERIVED BY THE INDIVIDUAL EVALUATION OF BUYER. THERE ARE NO WARRANTIES THAT EXTEND BEYOND THE FACE OF THIS AGREEMENT, THE SELLER’S CERTIFICATE OR THE ASSIGNMENT. BUYER ACKNOWLEDGES THAT THIS WAIVER IS CONSPICUOUS.

16.6. Third Party Claims. If a claim by a third party is made against a member of the Seller Group or the Buyer Group (an “Indemnified Party”), and if such party intends to seek indemnity with respect thereto under this Article 16, such Indemnified Party shall promptly notify Buyer or Seller, as the case may be (the “Indemnitor”), of such claims. The Indemnitor shall have thirty (30) days after receipt of such notice to undertake, conduct and control, through counsel of its own choosing and at its own expense, the settlement or defense thereof, and the Indemnified Party shall cooperate with it in connection therewith; provided, however, that the Indemnitor shall permit the Indemnified Party to participate in such settlement or defense through counsel chosen by such Indemnified Party; provided further, however, the fees and expenses of such counsel shall be borne by such Indemnified Party. So long as the Indemnitor, at Indemnitor’s cost and expense, (i) has undertaken the defense of, and assumed full responsibility for all Losses with respect to, such claim in accordance with and subject to any applicable limitations set forth in this Agreement, (ii) is reasonably contesting such claim in good faith, by appropriate proceedings, and (iii) has taken such action (including the posting of a bond, deposit or other security) as may be necessary to prevent any action to foreclose a lien against or attachment of the property of the Indemnified Party for payment of such claim, the Indemnified Party shall not pay or settle any such claim. Notwithstanding compliance by the Indemnitor with the preceding sentence, the Indemnified Party shall have the right to pay or settle any such claim; provided, however, that in such event it shall waive any right to indemnity therefor by the Indemnitor for such claim. If, within thirty (30) days after the receipt of the Indemnified Party’s notice of a claim of indemnity hereunder, the Indemnitor does not notify the Indemnified Party that it elects, at Indemnitor’s cost and expense, to undertake the defense thereof and assume full responsibility for all Losses with respect thereto, or gives such notice and

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thereafter fails to contest such claim in good faith or to prevent action to foreclose a lien against or attachment of the Indemnified Party’s property as contemplated above, the Indemnified Party shall have the right to contest, settle or compromise the claim but shall not thereby waive any right to indemnity therefor pursuant to this Agreement in accordance with the terms hereof and subject to any applicable limitations set forth herein.

ARTICLE 17

RISK OF LOSS

17.1. Casualty Loss. If, after the date hereof and prior to the Closing any portion of the Properties is damaged or destroyed by fire or other casualty, or if any portion of the Properties shall be taken by condemnation or the exercise of eminent domain (in either case, a “Casualty Loss”), Buyer shall be entitled to any applicable insurance proceeds or condemnation awards and an adjustment to the Purchase Price based upon the Allocated Value of the Property destroyed or harmed, to the extent such loss is not covered by insurance or condemnation award; provided, however, that if prior to Closing a Casualty Loss of more than $60,278,800 occurs, either Party shall have the right to terminate this Agreement by delivery of written notice to the other Party.

17.2. Buyer’s Risk of Loss. Except as specifically provided in Section 17.1 with respect to any Casualty Loss and except to the extent constituting a Seller Retained Liability, Buyer shall assume all risk of loss with respect to any change in condition of the Properties from the Effective Time and Seller shall have no liability, as operator of the Properties or otherwise, for Losses sustained with respect to the condition of the Properties or their ability to produce Hydrocarbons.

ARTICLE 18

TERMINATION AND REMEDIES

18.1. Termination. Prior to Closing, this Agreement may be terminated as provided below.

18.1.1. The Parties may terminate this Agreement by mutual written consent.

18.1.2. After the Closing Date, if Closing has not occurred, either Party may terminate this Agreement by delivery of written notice to the other Party; provided, however, that no Party may terminate this Agreement pursuant to this Section 18.1.2 if such Party’s failure to comply with its obligations under this Agreement caused the Closing not to occur on or before the Closing Date.

18.1.3. Either Party may terminate this Agreement in accordance with Section 17.1.

18.1.4. Either Party may terminate this Agreement no later than one Business Day prior to the Closing Date if as of such date the aggregate of the following amounts exceeds ten percent (10%) of the Purchase Price: (i) the Uncured Title Defects Value plus (ii) the Remediation Value for all Adverse Environmental Conditions plus (iii) the aggregate reduction in the Purchase Price pursuant to Title Defect Removals and Adverse Environmental Condition Removals plus (iv) the aggregate reduction in the Purchase Price on account of Retained Properties.

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18.1.5. Either Party may terminate this Agreement if the Closing shall not have occurred on or before November 17, 2008 (the “Termination Date”); provided, however, that the right to terminate this Agreement under this Section 18.1.5 shall not be available (i) to Seller, if any breach of this Agreement by Seller has been the principal cause of, or resulted in, the failure of the Closing to occur on or before the Termination Date or (ii) to Buyer, if any breach of this Agreement by Buyer has been the principal cause of, or resulted in, the failure of the Closing to occur on or before the Termination Date.

18.2. Effect of Termination.

18.2.1. If (i) the Parties agree under Section 18.1.1, (ii) written notice is delivered under Section 18.1.3 or Section 18.1.4 (iii) written notice is delivered under Section 18.1.2 and the passage of the Closing Date without the occurrence of the Closing was not due to the failure of any condition to Closing set forth in Sections 9.1, 9.2, 10.1 or 10.2 to be satisfied as of that date (in which case Section 18.2.2 or Section 18.2.3, as applicable, will govern) or (iv) written notice is delivered under Section 18.1.5 and the principal cause of the failure of the Closing to occur on or before the Termination Date was not the result of the breach of this Agreement by Seller or Buyer (in which case Section 18.2.2 or Section 18.2.3, as applicable, will govern), then neither Party shall have any further obligation to the other Party hereunder except (a) Seller will promptly return the Deposit to Buyer, (b) Buyer’s indemnity obligations under Section 7.2 will survive such termination and (c) the Confidentiality Agreement will survive such termination in accordance with its terms.

18.2.2. If written notice is delivered under Section 18.1.2 by Seller, and the passage of the Closing Date without the occurrence of the Closing was due solely to (i) the failure of any condition to Closing set forth in Section 9.1 or 9.2 to be satisfied as of that date, or (ii) Buyer’s refusal or inability to close notwithstanding the satisfaction of the conditions precedent set forth in Article 10, or if written notice is delivered under Section 18.1.5 by Seller, and the principal cause of the failure of the Closing to occur on or before the Termination Date was a breach by Buyer of this Agreement, then, in either case, Seller, as Seller’s sole and exclusive remedy, may retain the Deposit as liquidated damages (not as a penalty) and neither Party will have any further obligation to the other Party hereunder, except that Buyer’s indemnity obligations under Section 7.2 will survive such termination and the Confidentiality Agreement will survive such termination in accordance with its terms; provided, however, in lieu of delivering any notice of termination as otherwise permitted to do so, Seller may enforce specifically this Agreement in any court of the United States or any state court having jurisdiction.

18.2.3. If written notice is delivered under Section 18.1.2 by Buyer, and the passage of the Closing Date without the occurrence of the Closing was due to (i) the failure of any condition to Closing set forth in Section 10.1 or 10.2 to be satisfied as of that date, or (ii) Seller’s refusal or inability to close notwithstanding the satisfaction of the conditions precedent set forth in Article 9, or if written notice is delivered under Section 18.1.5 by Buyer, and the principal cause of the failure of the Closing to occur on or before the Termination Date was a breach by Seller of this Agreement, Seller will promptly return the Deposit to Buyer and Buyer shall be entitled to pursue against Seller any remedy available to it at law or in equity (in which case Buyer’s indemnity obligations under

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Section 7.2 will survive such termination and the Confidentiality Agreement will survive such termination in accordance with its terms); provided, however, in lieu of delivering any notice of termination as otherwise permitted to do so, Buyer may enforce specifically this Agreement in any court of the United States or any state court having jurisdiction.

ARTICLE 19

ADDITIONAL COVENANTS

19.1. Further Assurances. After the Closing, Seller and Buyer will execute, acknowledge and deliver or cause to be executed, acknowledged and delivered such instruments and take such other action as may be necessary or advisable to carry out their respective obligations under this Agreement and under any agreement, document, certificate or other instrument delivered pursuant hereto. Seller will use commercially reasonable efforts to cooperate with Buyer’s efforts to obtain all approvals and consents of governmental authorities required by or necessary for the transactions contemplated by this Agreement that are customarily obtained after Closing.

19.2. Access to Records by Seller. Within five days after Closing, Seller will deliver to Buyer, at Buyer’s address, the originals of all Records and Data, except that Seller may retain (i) copies of all Data related both to the Properties, on the one hand, and properties other than the Properties being sold herein, on the other hand, and (ii) copies of all accounting Data. For a period of four years after the date of Closing, Buyer will retain the Records and Data delivered to it pursuant hereto and will make such Data available to Seller if reasonably requested by Seller upon reasonable notice at Buyer’s headquarters at reasonable times and during office hours.

19.3. Use of Seller’s Name. Buyer agrees that, as soon as practicable after the Closing, it will remove or cause to be removed the names and marks “Enduring Resources, LLC,” and all variations and derivatives thereof and logos relating thereto from the Properties of which it has assumed operations and will not thereafter make any use whatsoever of such names, marks and logos.

19.4. Seller’s Employees. For two years after the Closing, neither Buyer nor any of its affiliates shall hire, retain or attempt to hire or retain any Denver-based employee or independent contractor of Seller of whom Buyer has actual knowledge; provided, however, that no such restriction shall apply to any such employee or independent contractor who contacts Buyer or responds to any ad for employment placed by Buyer. Buyer will be permitted to contact any of Seller’s non-Denver-based employees relating to the Properties and offer post-Closing employment to such employees.

19.5. Ad Valorem Tax Proration. Ad valorem taxes related to the Properties will be prorated as of the Effective Time. For ad valorem taxes for a period which the Effective Time splits which have been paid by Seller, Buyer shall be responsible for the portion thereof equal to the percentage of such period represented by the portion of such period beginning at the Effective Time and the Purchase Price will be adjusted upward on account thereof in accordance with Section 4.1.2. For ad valorem taxes for a period which the Effective Time splits which have not been paid to Seller, Buyer shall pay such taxes and Seller shall promptly reimburse Buyer for a percentage of such taxes equal to the portion of such period which ends on the day immediately preceding the Effective Time to the extent the Purchase Price is not adjusted downward on account thereof pursuant to Section 4.2.2, as adjusted pursuant to Article 15.

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19.6. Public Announcements. Without the prior written approval of the other Party, which approval shall not be unreasonably withheld, no Party will issue, or permit any agent or affiliate of it to issue, any press releases or otherwise make, or cause any agent or affiliate of it to make, any public statements with respect to this Agreement and the transactions contemplated hereby, except where such release or statement is deemed in good faith by the releasing Party to be required by Law or any national securities exchange, in which case the Party will use its commercially reasonable efforts to provide a copy to the other Party prior to any release or statement; provided, however, without the prior written consent of Enduring or Mustang, as the case may be, no press release by Buyer will mention Enduring or Mustang by name.

ARTICLE 20

MISCELLANEOUS

20.1. Notice. All notices required or permitted under this Agreement must be in writing and must be delivered personally or by certified mail, postage prepaid and return receipt requested or by telecopier as follows:

Seller:	Enduring Resources, LLC
	475 17th Street
	Suite 1500
	Denver, Colorado 80202
	Attention:      Barth E. Whitham
	President and CEO
	Telecopier:    (303) 573-0461
With a copy to:	Akin Gump Strauss Hauer & Feld LLP
	1111 Louisiana Street, 44th Floor
	Houston, Texas 77002
	Attention:      James L. Rice III
	Telecopier:    (713) 236-0822
Buyer:	Cabot Oil & Gas Corporation
	1200 Enclave Parkway
	Houston, Texas 77077
	Attention:      Vice President, Land
	Telecopier:    (281) 589-4839
With a copy to:	Fulbright & Jaworski L.L.P.
	1301 McKinney, Suite 5100
	Houston, Texas 77010-3095
	Attention:      Deborah A. Gitomer
	Telecopier:    (713) 651-5246

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or to such other place within the United States of America as either Party may designate as to itself by written notice to the other. All notices given by personal delivery or mail shall be effective on the date of actual receipt at the appropriate address. Notices given by telecopier shall be effective upon actual receipt if received during the recipient’s normal business hours or at the beginning of the next Business Day after receipt if received after the recipient’s normal business hours. All notices by telecopier shall be confirmed in writing on the day of transmission either by mailing by postage prepaid certified mail with return receipt requested, or by personal delivery.

20.2. Governing Law. This Agreement and the obligations of the Parties hereunder will be governed by and construed in accordance with the laws of the State of Texas, without giving effect to any choice of law principles.

20.3. Assignment. This Agreement shall be binding upon and shall inure to the benefit of the Parties hereto and their respective successors and permitted assigns. Notwithstanding the preceding sentence, except as permitted by Section 20.12, neither Party may assign this Agreement or its rights hereunder without the other Party’s written consent, which may not be unreasonably withheld.

20.4. Entire Agreement. This Agreement, together with the Exhibits and Schedules hereto, the Confidentiality Agreement and the certificates, documents, instruments and writings that are delivered pursuant to this Agreement, constitute the entire agreement and understanding of the Parties in respect of its subject matter and supersede all prior understandings, agreements, or representations by or among the Parties, written or oral, to the extent they relate in any way to the subject matter hereof or the transactions contemplated hereby. Except in the case of Sections 16.1 and 16.3 with respect to the members of the Buyer Group and the Seller Group, respectively, there are no third party beneficiaries having rights under or with respect to this Agreement.

20.5. Amendment; Waiver. No amendment, modification, replacement, termination or cancellation of any provision of this Agreement will be valid, unless in writing and signed by Buyer and Seller. No waiver by any Party of any default, misrepresentation or breach of warranty or covenant hereunder, whether intentional or not, will 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 because of any prior or subsequent such occurrence.

20.6. Severability. The provisions of this Agreement will be deemed severable and the invalidity or unenforceability of any provision will not affect the validity or enforceability of the other provisions hereof; provided, however, that if any provision of this Agreement, as applied to any Party or to any circumstance, is adjudged by a court of competent jurisdiction, arbitrator, or mediator not to be enforceable in accordance with its terms, the Parties agree that the court of competent jurisdiction, arbitrator, or mediator making such determination will have the power to modify the provision in a manner consistent with its objectives such that it is enforceable, or to delete specific words or phrases, and in its reduced form, such provision will then be enforceable and will be enforced.

20.7. Construction. The Parties have participated jointly in the negotiation and drafting of this Agreement. If an ambiguity or question of intent or interpretation arises, this Agreement

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will be construed as if drafted jointly by the Parties and no presumption or burden of proof will arise favoring or disfavoring any Party because of the authorship of any provision of this Agreement. Any reference to any federal, state, local, or foreign Law will be deemed also to refer to such Law as amended and all rules and regulations promulgated thereunder, unless the context requires otherwise. The words “include,” “includes” and “including” will be deemed to be followed by “without limitation.” Pronouns in masculine, feminine, and neuter genders will be construed to include any other gender, and words in the singular form will be construed to include the plural and vice versa, unless the context otherwise requires. The words “this Agreement,” “herein,” “hereof,” “hereby,” “hereunder” and words of similar import refer to this Agreement as a whole and not to any particular subdivision unless expressly so limited. The Exhibits and Schedules identified in this Agreement are incorporated herein by reference and made a part hereof. References herein to any Section or Article shall be references to a Section or Article of this Agreement unless the context clearly requires otherwise.

20.8. Confidentiality. All information made available to Buyer pursuant to this Agreement shall be maintained as confidential by Buyer until Closing in accordance with the Confidentiality Agreement. Buyer shall remain subject, until the Closing, to the Confidentiality Agreement, at which time the Confidentiality Agreement will be deemed terminated. Buyer will take all actions reasonably necessary to ensure that Buyer’s employees, consultants, representatives and agents comply with the provisions of this Section 20.8.

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

20.10. Counterparts. This Agreement may be executed in two or more counterparts, each of which will be deemed an original but all of which together will constitute one and the same instrument.

20.11. Expenses, Fees and Taxes. Each of the Parties hereto will pay its own fees and expenses incident to the negotiation and preparation of this Agreement and consummation of the transactions contemplated hereby, including brokers’ fees. Buyer will be responsible for the cost of all fees for the recording of the Assignment and other transfer documents. Except to the extent contemplated in Sections 4.1.5 and 7.8 or the Transition Service Agreement, all other costs will be borne by the Party incurring them. Notwithstanding anything to the contrary herein, it is acknowledged and agreed by and between Seller and Buyer that the Purchase Price excludes any sales taxes or other taxes in connection with the sale of property pursuant to this Agreement. If a determination is ever made that a sales tax or other transfer tax applies, Buyer will be liable for such tax as well as any applicable conveyance, transfer and recording fees, and real estate transfer stamps or taxes imposed on any transfer of property pursuant to this Agreement. Buyer will indemnify and hold the Seller Group harmless with respect to the payment of any of such taxes, including any interest or penalties assessed thereon. The indemnity and hold harmless obligation contained in the preceding sentence will survive the Closing.

20.12. Tax-Deferred Exchange Option. Seller has the right to elect to effect a tax-deferred exchange under Internal Revenue Code Section 1031 (a “Tax Deferred Exchange”) for the Properties, or any portion thereof, at any time prior to the Closing Date. If Seller elects to

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effect a Tax-Deferred Exchange, Buyer agrees to execute escrow instructions, documents, agreements or instruments to effect the exchange; provided, however, that Buyer will incur no additional costs, expenses, fees or liabilities as a result of or connected with the exchange. Seller may assign any of its rights and delegate performance of any of its duties under this Agreement in whole or in part to a third party in order to effect such an exchange; provided, however, that Seller will remain responsible to Buyer for the full and prompt performance of its delegated duties. Seller will indemnify and hold the Buyer Group harmless from and against all Claims and Losses resulting from Buyer’s participation in any exchange undertaken pursuant to this Section 20.12 pursuant to the request of Seller. The indemnity and hold harmless obligation contained in the preceding sentence will survive the Closing.

20.13. Relationship Among Seller. Except for the representations and warranties provided severally in Sections 5.1 and 5.2 by Enduring and Mustang, respectively, the representations, warranties, covenants, agreements and obligations of Seller hereunder are joint and several; and each Party Seller is liable to Buyer with respect to the performance of this Agreement for itself and the other Party Seller and with respect to the satisfaction of all of its and the other Party Seller’s obligations to Buyer hereunder. Buyer may rely on the written notices, requests, waivers and consents of Enduring, its officers and designated agents as the binding actions of Seller hereunder. Buyer may furnish all notices and other information required hereunder to Enduring and such notices and other information will be received by Enduring on behalf of Seller, and Buyer may pay all amounts that may be required to be paid by Buyer hereunder to Seller, to Enduring for Seller’s account; provided, however, Buyer has no responsibility to inquire as to the application of such amounts by Enduring and is hereby released from any liability to Seller arising from such application by Enduring.

[Remainder of page intentionally left blank]

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Executed as of the date set forth above.

SELLER:
ENDURING RESOURCES, LLC
By:	/s/ Barth E. Whitham
	Barth E. Whitham
	President and Chief Executive Officer
MUSTANG DRILLING, INC.
By:	/s/ Andrew D. Mills
	Andrew D. Mills
	President
MINDEN GATHERING SERVICES, LLC
By:	/s/ Barth E. Whitham
	Barth E. Whitham
	Manager
By:	/s/ Michael T. Wilhite, Jr.
	Michael T. Wilhite, Jr.
	Manager
BUYER:
CABOT OIL & GAS CORPORATION
By:	/s/ Dan O. Dinges
	Dan O. Dinges
	Chairman, President and Chief Executive Officer

EX-10.2

Exhibit 10.2

CABOT OIL & GAS CORPORATION

SUPPLEMENTAL EMPLOYEE INCENTIVE PLAN II

(Effective as of July 1, 2008)

1. Plan. Effective as of July 1, 2008 (the “Effective Date”), Cabot Oil & Gas Corporation (the “Company”) hereby establishes the Cabot Oil & Gas Corporation Supplemental Employee Incentive Plan II (the “Plan”) to reward certain non-officer employees of the Company by providing the opportunity to earn cash incentive compensation upon the Company’s attainment of certain pre-determined performance goals with regard to value creation.

2. Objectives. The Company anticipates that, by tying incentive compensation to value creation, the Plan will motivate Eligible Employees to align their interests with the Company’s long-term business plan and shareholder interests. The Plan’s further objective is to facilitate the Company’s ability to attract and retain talented employees by differentiating the Company as an employer of choice in a competitive talent market. By providing some compensation protection to Eligible Employees, the Plan also mitigates possible concerns about the stability of employment relationships in a consolidating industry. Any benefit payable under this Plan is and shall be characterized for all purposes as a retention bonus payment.

3. Definitions. The terms set forth below shall have the following meanings:

“Board” means the Board of Directors of the Company.

“Calendar Quarter” means each of the following periods of each year: (a) January 1 through March 31; (b) April 1 through June 30; (c) July 1 through September 30; and (d) October 1 through December 31.

“Change in Control” means:

(I) The acquisition by any individual, entity or group (within the meaning of Section 13(d)(3) or 14(d)(2) of the Exchange Act (a “Person”) of beneficial ownership (within the meaning of Rule 13d-3 promulgated under the Exchange Act) of 35% or more of either (1) the then outstanding shares of common stock of the Company (the “Outstanding Company Common Stock”) or (2) the combined voting power of the then outstanding voting securities of the Company entitled to vote generally in the election of directors (the “Outstanding Company Voting Securities”); provided, however, that for purposes of this subsection (I), the following acquisitions shall not constitute a Change of Control: (i) any acquisition directly from the Company, (ii) any acquisition by the Company, (iii) any acquisition by any employee benefit plan (or related trust) sponsored or maintained by the Company or any entity controlled by the Company or (iv) any acquisition by any entity pursuant to a transaction which complies with clauses (1), (2) and (3) of subsection (III) of this definition; or

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(II) Individuals who, as of the date hereof, constitute the Board (the “Incumbent Board”) cease for any reason to constitute at least a majority of the Board; provided, however, that any individual becoming a director subsequent to the date hereof whose election, or nomination for election by the Company’s stockholders, was approved by a vote of at least a majority of the directors then comprising the Incumbent Board shall be considered as though such individual were a member of the Incumbent Board, but excluding, for this purpose, any such individual whose initial assumption of office occurs as a result of an actual or threatened election contest with respect to the election or removal of directors or other actual or threatened solicitation of proxies or consents by or on behalf of a Person other than the Board; or

(III) Consummation of a reorganization, merger or consolidation or sale or other disposition of all or substantially all of the assets of the Company (a “Business Combination”), in each case, unless, following such Business Combination, (1) all or substantially all of the individuals and entities who were the beneficial owners, respectively, of the Outstanding Company Common Stock and Outstanding Company Voting Securities immediately prior to such Business Combination beneficially own, directly or indirectly, more than 50% of, respectively, the then outstanding shares of common stock and the combined voting power of the then outstanding voting securities entitled to vote generally in the election of directors, as the case may be, of the entity resulting from such Business Combination (including, without limitation, an entity that as a result of such transaction owns the Company or all or substantially all of the Company’s assets either directly or through one or more subsidiaries) in substantially the same proportions as their ownership, immediately prior to such Business Combination, of the Outstanding Company Common Stock and Outstanding Company Voting Securities, as the case may be, (2) no Person (excluding any entity resulting from such Business Combination or any employee benefit plan (or related trust) of the Company or such entity resulting from such Business Combination) beneficially owns, directly or indirectly, 35% or more of, respectively, the then outstanding shares of common equity of the entity resulting from such Business Combination or the combined voting power of the then outstanding voting securities of such entity except to the extent that such ownership existed prior to the Business Combination and (3) at least a majority of the members of the board of directors of the corporation, or the similar managing body of a non-corporate entity, resulting from such Business Combination were members of the Incumbent Board at the time of the execution of the initial agreement, or of the action of the Board, providing for such Business Combination; or

(IV) Approval by the stockholders of the Company of a complete liquidation or dissolution of the Company, other than a liquidation or dissolution in connection with a transaction to which subsection (III) applies.

Notwithstanding the foregoing, none of the events described in subsections (I) through (IV) above shall constitute a Change in Control unless such event also meets the requirements of Section 409A(a)(2)(A)(v) of the Code and the related regulations and guidance.

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“Closing Price” means, for any given trading day, the closing price of a share of Common Stock, as reported by Bloomberg Finance L.P. or a data source selected by the Committee.

“Code” means the Internal Revenue Code of 1986, as amended from time to time.

“Committee” means the Compensation Committee of the Board.

“Common Stock” means the Common Stock, par value $.10 per share, of the Company.

“Competitor” means any person or entity that is engaged in the exploration and production of oil, gas or other hydrocarbons, the transportation thereof, any other midstream activities or the provision of oilfield services.

“Deferred Distribution” means the portion of an Interim Distribution or Final Distribution to be deferred in accordance with Section 9.

“Deferred Payment Date” means the date on which a Deferred Distribution shall be made, as determined in accordance with Section 9.

“Disability” means the condition of an Eligible Employee who has been determined to be disabled in accordance with the terms of the Cabot Group Health and Welfare Plan; provided, however, that the terms of such plan define disability in a manner consistent with Treasury Regulation § 1.409A-3(i)(4).

“Early Achievement Period” means the period from the Effective Date through December 31, 2010.

“Eligible Employee” means any full-time employee who (a) is not an officer of the Company on the relevant Trigger Date and (b) has completed at least one year of continuous service with the Company that includes such Trigger Date.

“Eligible Retiree” shall have the meaning set forth in Section 7 or Section 8 of this Plan, as applicable.

“Exchange Act” means the Securities Exchange Act of 1934, as amended from time to time.

“Final Deadline” means June 30, 2012.

“Final Distribution” means a distribution under Section 8.

“Final Payment Date” means the fifteenth business day following the Final Trigger Date.

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“Final Price Goal” means $105 per share of Common Stock (appropriately adjusted by the Committee to reflect any stock splits, stock dividends or extraordinary cash distributions to stockholders).

“Final Trigger Date” means the first date that meets the specifications of the next sentence. If, for any 20 trading days (which need not be consecutive) that fall within a period of 60 consecutive trading days ending on or before the Final Deadline, the Closing Price of the Common Stock on each of such 20 trading days equals or exceeds the Price Goal, then the Final Trigger Date shall be the last of such 20 trading days.

“Interim Deadline” means June 30, 2010.

“Interim Distribution” means a distribution under Section 7.

“Interim Payment Date” means the fifteenth business day following the Interim Trigger Date.

“Interim Price Goal” means $85 per share of Common Stock (appropriately adjusted by the Committee to reflect any stock splits, stock dividends or extraordinary cash distributions to stockholders).

“Interim Trigger Date” means the first date that meets the specifications of the next sentence. If, for any 20 trading days (which need not be consecutive) that fall within a period of 60 consecutive trading days ending on or before the Interim Deadline, the Closing Price of the Common Stock on each of such 20 trading days equals or exceeds the Interim Price Goal, then the Interim Trigger Date shall be the last of such 20 trading days.

“Other Employee” means any full-time employee who (a) is not an officer of the Company on the relevant Trigger Date and (b) has not completed one year of continuous service with the Company that includes such Trigger Date.

“Payment Date” means the Interim Payment Date or the Final Payment Date, as applicable.

“Price Goal” means either the Interim Price Goal or the Final Price Goal, as applicable.

“Retired” describes a person who has retired from employment with the Company (a) at or after age 55 with at least 10 years of service or (b) at or after age 65 with at least 5 years of service.

“Trigger Date” means either the Interim Trigger Date or the Final Trigger Date, as applicable.

4. Administration. The Plan shall be administered by the Compensation Committee of the Board of Directors (the “Committee”).

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The Committee shall have full and exclusive power and authority to administer the Plan and to take all actions that are specifically contemplated hereby or are necessary or appropriate in connection with the administration hereof. The Committee shall also have full and exclusive power to interpret the Plan and to adopt such rules, regulations and guidelines for carrying out the Plan as it may deem necessary or proper. Subject to the limitations of Section 12, the Committee may, in its discretion, (a) eliminate or make less restrictive any restrictions applicable to any person or class of persons, (b) waive any restriction or other provision of the Plan, (c) extend the Final Deadline or the Interim Deadline, (d) amend or modify the Plan in any manner that is either (i) not materially adverse to any Eligible Employee, Eligible Retiree or Other Employee or (ii) consented to by such Eligible Employee, Eligible Retiree or Other Employee. The Committee may correct any defect or supply any omission or reconcile any inconsistency in the Plan in the manner and to the extent the Committee deems necessary or desirable to further the Plan purposes. Any decision of the Committee in the interpretation and administration of the Plan shall lie within its sole and absolute discretion and shall be final, conclusive and binding on all parties concerned. No member of the Committee shall be liable for anything done or omitted to be done by him, by any member of the Committee or by any officer of the Company in connection with the performance of any duties under the Plan, except for his own willful misconduct or as expressly provided by statute.

5. Delegation of Authority. The Committee may delegate to the Chief Executive Officer and to other senior officers of the Company its duties under this Plan, subject to the conditions or limitations established by the Committee.

6. Eligibility.

(a) The Committee has the sole authority to determine whether an individual is an Eligible Employee or an Eligible Retiree with respect to a particular Trigger Date. Such determination shall be made without regard to the status of such individual with respect to any other Trigger Date.

(b) The Committee, in its sole discretion, may select any Other Employee to participate in the Plan, subject to the terms and conditions of this Plan and such other additional terms as the Committee may prescribe (including, but not limited to the designation of a distribution amount that differs from that of an Eligible Employee).

(c) Any person who (i) has failed to satisfy all of the criteria necessary for classification as an Eligible Employee as of such relevant Trigger Date or (ii) is an Other Employee who has not been selected to participate in the Plan shall not participate in any distributions associated with such Trigger Date, except as otherwise provided in Sections 7 and 8 of this Plan document.

7. Interim Distributions. Except as otherwise provided, if the Committee, acting in its sole discretion, determines that an Interim Trigger Date has occurred, an Interim Distribution shall become payable, in accordance with the terms of Section 9, to each Eligible Employee, Eligible Retiree and Other Employee who has been selected to receive an Interim Distribution.

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(a) Interim Distribution to Eligible Employees. Each individual who is an Eligible Employee on the Interim Trigger Date shall receive an Interim Distribution in an amount equal to 20% (or such greater percentage as the Committee, in its sole discretion, may designate with respect to such individual) of his base salary as of the Interim Trigger Date (adjusted as described below for persons hired after the Effective Date); provided, however, that the Committee, in its sole discretion, may reduce the amount of, or eliminate entirely, the Interim Distribution payable to an otherwise Eligible Employee if such person has been placed on probation or suspension for a period of time that includes either the Trigger Date or the Payment Date.

(b) Interim Distribution to Retirees. A person who Retired after the Effective Date but prior to the Interim Trigger Date and who would have been an Eligible Employee had the Interim Trigger Date occurred on the date of such person’s retirement shall be entitled to an Interim Distribution under the Plan if the person was employed by the Company during at least 50% of the period from the Effective Date to the Interim Trigger Date (a person entitled to such a payment is referred to as an “Eligible Retiree” for purposes of this Section 7). The Interim Distribution for such Eligible Retiree shall be 20% (or such greater percentage as the Committee, in its sole discretion, may designate with respect to such individual) of his base salary as of his retirement date (adjusted as described below for quarters of service).

(c) Death or Disability. For the purpose of determining entitlement to an Interim Distribution, an employee who has terminated employment prior to the Interim Trigger Date as the result of death or Disability will be treated as if he had Retired on the date of such termination.

(d) Quarters of Service. Each Eligible Employee who has not been continuously employed by the Company from the Effective Date to the Interim Trigger Date and each Eligible Retiree shall have his Interim Distribution reduced to reflect his time of service. Each such person’s Interim Distribution shall equal the amount determined under the other provisions of this Section 7 multiplied by a fraction (i) the numerator of which is the number of complete Calendar Quarters that such Eligible Employee or Eligible Retiree worked after the Effective Date and prior to the Interim Trigger Date, and (ii) the denominator of which is the number of complete Calendar Quarters after the Effective Date and prior to the Interim Trigger Date.

(e) Other Employees. Each person who is an Other Employee who has been selected by the Committee to participate in the Plan shall receive an Interim Distribution in the amount designated by the Committee, acting in its sole discretion. Unless otherwise designated by the Committee in its sole discretion, any such Interim Distribution shall be payable in accordance with the same terms and conditions applicable to the Interim Distributions that are paid to Eligible Employees.

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(f) If the Interim Price Goal and the Final Price Goal are achieved on the same date, the Interim Trigger Date shall be disregarded and all payments under this Agreement shall be calculated by reference to the Final Trigger Date.

8. Final Distributions. Except as otherwise provided, if the Committee, acting in its sole discretion, determines that a Final Trigger Date has occurred, a Final Distribution shall become payable, in accordance with the terms of Section 9, to each Eligible Employee, Eligible Retiree and Other Employee who has been selected to participate in the Plan.

(a) Final Distribution. Each individual who is an Eligible Employee on the Final Trigger Date shall receive a Final Distribution in an amount equal to 50% or, if the Interim Trigger Date previously occurred, 30% (or, in either case, such greater percentage as the Committee, in its sole discretion, may designate with respect to such individual) of his base salary as of the Final Trigger Date (adjusted as described below for persons hired after the Effective Date); provided, however, that the Committee, in its sole discretion, may reduce the amount of, or eliminate entirely, the Final Distribution payable to an otherwise Eligible Employee if such person has been placed on probation or suspension for a period of time that includes either the Trigger Date or the Payment Date.

(b) Final Distribution to Retirees. A person who Retired after the Effective Date but prior to the Final Trigger Date and who would have been an Eligible Employee had the Final Trigger Date occurred on the date of such person’s retirement shall be entitled to a Final Distribution under the Plan if the person was employed by the Company during at least 50% of the period from the Effective Date to the Final Trigger Date (a person entitled to such a payment is referred to as an “Eligible Retiree” for purposes of this Section (8)). The Final Distribution for such Eligible Retiree shall be 50% or, if the Interim Trigger Date previously occurred, 30% (or, in either case, such greater percentage as the Committee, in its sole discretion, may designate) of his base salary as of his retirement date (adjusted as described below for quarters of service).

(c) Death or Disability. For the purpose of determining entitlement to a Final Distribution, an employee who has terminated employment prior to the Final Trigger Date as the result of death or Disability will be treated as if he had Retired on the date of such termination.

(d) Quarters of Service. Each Eligible Employee who has not been continuously employed by the Company from the Effective Date to the Final Trigger Date and each Eligible Retiree shall have his Final Distribution reduced to reflect his time of service. Each such person’s Final Distribution shall equal the amount determined under the other provisions of this Section 8 multiplied by a fraction (i) the numerator of which is the number of complete Calendar Quarters that such Eligible Employee or Eligible Retiree has worked after the Effective Date and prior to the Final Trigger Date, and (ii) the denominator of which is the number of complete Calendar Quarters after the Effective Date and prior to the Final Trigger Date.

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(e) Other Employees. Each person who is an Other Employee who has been selected by the Committee to participate in the Plan shall receive a Final Distribution in the amount designated by the Committee, acting in its sole discretion. Unless otherwise designated by the Committee in its sole discretion, any such Final Distribution shall be payable in accordance with the same terms and conditions applicable to the Final Distributions that are paid to Eligible Employees.

9. Timing of Distributions Upon Achievement of Interim or Final Price Goals.

(a) In the event that a Price Goal is achieved during the Early Achievement Period, the amount of the total Interim Distribution or Final Distribution to which an Eligible Employee, Eligible Retiree or Other Employee is entitled shall be calculated in accordance with Section 7 or 8 of this Agreement, as applicable, and paid as provided in this Section 9. In such case, an amount equal to 25% of the total Interim Distribution or Final Distribution shall be distributed to each such Eligible Employee, Eligible Retiree and Other Employee who has been selected to receive such Interim or Final Distribution in a lump-sum cash payment on the applicable Payment Date. The remaining 75% of such Interim or Final Distribution shall be distributed in a lump-sum cash payment on the applicable Deferred Payment Date set forth in the following table:

Period During which the Trigger Date Occurs	Deferred Payment Date
July 1, 2008 to June 30, 2009	The business day on or next following the 18-month anniversary of the applicable Trigger Date.
July 1, 2009 to June 30, 2010	The business day on or next following the 12-month anniversary of the applicable Trigger Date.
July 1, 2010 to December 31, 2010	The business day on or next following the 6- month anniversary of the applicable Trigger Date.

If the Final Trigger Date occurs after the Early Achievement Period, each Eligible Employee, Eligible Retiree or Other Employee who has been selected to participate in the Plan shall receive the total amount of his Final Distribution in a lump-sum cash payment on the Final Payment Date.

(b) Each person who is an Eligible Employee on the relevant Trigger Date shall participate in any particular payment associated with such Trigger Date only if he (i) is still an Eligible Employee on the date of such payment or (ii) has terminated employment due to death, Disability or his becoming Retired on or after the Trigger Date. Notwithstanding the foregoing and subject to waiver by the Committee, in its sole discretion, (i) an Eligible Employee shall not participate

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in any such payment if, on or before the date of such payment, such Eligible Employee gives notice of an intention to terminate employment with the Company for any reason other than his becoming Retired, and (ii) any person (including, but not limited to, any Eligible Retiree) who is employed by, or who has accepted an offer of employment from, a Competitor at any time during the period commencing on the Trigger Date and ending on the date of a particular payment shall not participate in such payment.

(c) The Committee’s decision to reduce the amount of or eliminate entirely the Interim or Final Distribution of an individual who has been placed on probation or suspension as contemplated by Section 7(a) or Section 8(a) shall apply to all payments otherwise associated with such distribution, including any payment that would be subject to deferral under this Section 9. If an individual has been placed on probation or suspension as of a Deferred Payment Date, the Committee, in its sole discretion, may reduce the amount of, or eliminate entirely any payments that would otherwise be made on such Deferred Payment Date.

10. Distributions Upon Change in Control. Upon the consummation of a Change in Control on or before the Final Deadline at a per share price (as determined by the Committee in the event of a transaction other than an all-cash transaction) equal to or in excess of the Price Goal, or, if such test is not met, the Interim Price Goal on or before the Interim Deadline, the date of such consummation shall be deemed to be the Final Trigger Date or the Interim Trigger Date, respectively, and all amounts payable upon such Trigger Date shall be distributed in accordance with Section 7 or 8 of this Plan, as applicable, without regard to any deferral otherwise required by Section 9.

11. Taxes. The Company shall have the right to deduct applicable taxes from any distribution and withhold an appropriate amount of such distribution for payment of taxes required by law or to take such other action as may be necessary in the opinion of the Company to satisfy all obligations for withholding of such taxes.

12. Amendment, Modification, Suspension or Termination. Except as otherwise provided, the Board may amend, modify, suspend or terminate the Plan for the purpose of meeting or addressing any changes in legal requirements or for any other purpose permitted by law, except that (a) after a Trigger Date, no amendment or alteration that would materially impair any individual’s rights resulting from the occurrence of such Trigger Date shall be made without such individual’s consent and (b) no amendment or alteration shall be effective prior to approval by the Company’s stockholders to the extent such approval is required by applicable legal requirements or applicable requirements of the securities exchange on which the Company’s Common Stock is listed. No amendment, modification, suspension or termination of the Plan shall be effective unless and until such intentions are reduced to writing and duly executed by a Company officer with the authority to perform such an act. Notwithstanding the foregoing and consistent with the requirements of Section 16, the Plan shall not be amended in a manner that would cause the Plan, any portion thereof or any benefit payable under the Plan to fail to comply with the requirements of Section 409A of the Code, to the extent applicable, and, further, the provisions of any purported amendment that may reasonably be expected to result in such non-compliance shall be of no force or effect with respect to the Plan.

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13. No Right of Employment. Nothing in the Plan shall interfere with or limit in any way the right of the Company to terminate any person’s employment or other service relationship at any time, or confer upon any person any right to continue in the capacity in which he is employed or otherwise serves the Company.

14. Assignability. No Award or any other benefit under this Plan shall be assignable or otherwise transferable except as follows:

(a) In the case of an Eligible Employee’s death after he becomes entitled to a payment as of a Trigger Date but before such payment is made, the amount of such accrued but unpaid benefit shall be transferred to the Eligible Employee’s estate;

(b) A distribution under this Plan may be transferred pursuant to a domestic relations order issued by a court of competent jurisdiction that is not contrary to the terms and conditions of this Plan.

15. Unfunded Plan. This Plan shall be unfunded. Although bookkeeping accounts may be established with respect to Eligible Employees or Eligible Retirees who become entitled to distributions under this Plan, any such accounts shall be used merely as a bookkeeping convenience. The Company shall not be required to segregate any assets for the purpose of funding its obligations under this Plan; nor shall this Plan be construed as providing for such segregation. Neither the Company, the Board nor the Committee shall be deemed to be a trustee of any amounts that may be distributed under this Plan. Any liability or obligation of the Company to any individual with respect to any distribution under this Plan shall be based solely upon the contractual obligations set forth in this Plan. No security, whether by pledge or encumbrance on any property of the Company, is necessary to secure the Company’s obligations pursuant to this Plan. Neither the Company, the Board nor the Committee shall be required to give any security or bond for the performance of any duty imposed or in satisfaction of any obligation created by this Plan.

16. Section 409A of the Code. The Company intends that any amounts payable under the Plan satisfy the requirements of Section 409A of the Code to avoid imposition of applicable taxes thereunder. Thus, notwithstanding anything in this Plan to the contrary, if any Plan provision or amount under the Plan would result in the imposition of an applicable tax under Section 409A of the Code and related regulations and Treasury pronouncements, the Company may take any and all necessary actions for the purposes of reforming, eliminating or amending such Plan provision or benefits payable under the Plan that the Company, in its sole discretion, shall deem to be desirable in order to avoid imposition of the applicable tax and no action taken to comply with Section 409A shall be deemed to adversely affect the rights of an Eligible Employee or an Eligible Retiree to an amount. The Company shall neither cause nor permit any payment, benefit or consideration to be substituted for a benefit that is payable under this Plan in violation of Section 409A. Each individual payment that is made pursuant to the terms of this Plan is a separate and independent payment for purposes of Section 409A. Notwithstanding the foregoing, in no event shall any action be taken under this Section 16 that would impose any expenses upon or increase any costs to the Company.

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17. Severability. If any provision of the Plan shall be held illegal or invalid for any reason, such illegality or invalidity shall not affect the remaining provisions hereof; instead, each provision shall be fully severable and the Plan shall be construed and enforced as if such illegal or invalid provision had never been included herein.

18. Construction. Headings are given to the Sections and subsections of the Plan solely as a convenience to facilitate reference. Such headings shall not be deemed in any way material or relevant to the construction or interpretation of the Plan or any provision thereof. Words in the masculine gender shall include the feminine gender, the plural shall include the singular and the singular shall include the plural.

19. Entire Contract. This Plan, together with any individual agreements that the Committee may require pursuant to Section 6 hereof (if any), constitutes the complete and exclusive statement of the terms of this Plan. Any amendment to the Plan shall only be recognized as constituting part of this Plan if it is adopted in accordance with the provisions of Section 12 hereof.

20. Governing Law. This Plan and all determinations made and actions taken pursuant hereto, to the extent not otherwise governed by mandatory provisions of the Code or the securities laws of the United States, shall be governed by and construed in accordance with the laws of the State of Texas.

IN WITNESS WHEREOF, Cabot Oil & Gas Corporation has caused this Plan to be executed by its duly authorized officer, effective as provided herein.

CABOT OIL & GAS CORPORATION
By:	/s/ Abraham Garza
Title:	Vice President, Human Resources
Date:	July 24, 2008

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EX-15.1

EXHIBIT 15.1

July 29, 2008

Securities and Exchange Commission

100 F Street, N.E.

Washington, D.C. 20549

Commissioners:

We are aware that our report dated July 29, 2008 on our review of interim financial information of Cabot Oil & Gas Corporation (the “Company”) for the three and six month periods ended June 30, 2008 and 2007 and included in the Company’s quarterly report on Form 10-Q for the quarter ended June 30, 2008 is incorporated by reference in its Registration Statements on Form S-8 (File Nos. 333-37632, 33-53723, 33-35476, 33-71134, 333-92264, 333-123166 and 333-135365) and Form S-3 (File Nos. 333-68350, 333-83819 and 333-151725).

Very truly yours,

/s/ PricewaterhouseCoopers LLP

EX-31.1

EXHIBIT 31.1

CERTIFICATIONS

I, Dan O. Dinges, certify that:

1. I have reviewed this interim report on Form 10-Q of Cabot Oil & Gas Corporation;

2. Based on my knowledge, this interim 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 interim report;

3. Based on my knowledge, the financial statements, and other financial information included in this interim 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 interim 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 interim 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 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: July 29, 2008

/s/ Dan O. Dinges

Dan O. Dinges

Chairman, President and Chief Executive Officer

EX-31.2

EXHIBIT 31.2

I, Scott C. Schroeder, certify that:

1. I have reviewed this interim report on Form 10-Q of Cabot Oil & Gas Corporation;

2. Based on my knowledge, this interim 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 interim report;

3. Based on my knowledge, the financial statements, and other financial information included in this interim 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 interim 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 interim 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 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: July 29, 2008

/s/ Scott C. Schroeder

Scott C. Schroeder

Vice President and Chief Financial Officer

EX-32.1

EXHIBIT 32.1

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) (the “Act”), each of the undersigned, Dan O. Dinges, Chief Executive Officer of Cabot Oil & Gas Corporation, a Delaware corporation (the “Company”), and Scott C. Schroeder, Chief Financial Officer of the Company, hereby certify that, to his knowledge:

(1) the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2008 (the “Report”) fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Dated: July 29, 2008

/s/ Dan O. Dinges

Dan O. Dinges

Chief Executive Officer

/s/ Scott C. Schroeder

Scott C. Schroeder

Chief Financial Officer