Coterra Energy (CTRA) 10-Q 2008 Q1 Quarterly report

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 March 31, 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 April 30, 2008, there were 97,949,944 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 Ended March 31, 2008 and 2007	3
		Condensed Consolidated Balance Sheet at March 31, 2008 and December 31, 2007	4
		Condensed Consolidated Statement of Cash Flows for the Three Months Ended March 31, 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	21
	Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	22
	Item 3.	Quantitative and Qualitative Disclosures about Market Risk	33
	Item 4.	Controls and Procedures	35
Part II. Other Information
	Item 1.	Legal Proceedings	35
	Item 1A.	Risk Factors	35
	Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	35
	Item 6.	Exhibits	35
Signatures			36

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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 March 31,
(In thousands, except per share amounts)	2008		2007
OPERATING REVENUES
Natural Gas Production	$	166,559	$	146,750
Brokered Natural Gas		35,620		33,177
Crude Oil and Condensate		16,487		10,942
Other		985		704
		219,651		191,573
OPERATING EXPENSES
Brokered Natural Gas Cost		30,290		28,699
Direct Operations—Field and Pipeline		17,491		17,131
Exploration		5,061		5,652
Depreciation, Depletion and Amortization		41,516		33,395
Impairment of Unproved Properties		4,751		3,986
General and Administrative		27,573		18,280
Taxes Other Than Income		16,897		13,165
		143,579		120,308
Gain on Sale of Assets		—		7,920
INCOME FROM OPERATIONS		76,072		79,185
Interest Expense and Other		5,991		3,924
Income Before Income Taxes		70,081		75,261
Income Tax Expense		24,106		26,714
NET INCOME	$	45,975	$	48,547
Basic Earnings Per Share	$	0.47	$	0.50
Diluted Earnings Per Share	$	0.46	$	0.50
Weighted Average Common Shares Outstanding		97,716		96,695
Diluted Common Shares (Note 5)		98,925		98,047

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)

	March 31, 2008			December 31, 2007
(In thousands, except share amounts)
ASSETS
Current Assets
Cash and Cash Equivalents	$	41,992		$	18,498
Accounts Receivable, Net		131,478			109,306
Income Taxes Receivable		7,483			3,832
Inventories		12,504			27,353
Deferred Income Taxes		56,093			26,456
Derivative Contracts (Note 7)		—			12,655
Other Current Assets		22,454			23,313
Total Current Assets		272,004			221,413
Properties and Equipment, Net (Successful Efforts Method) (Note 2)		1,972,023			1,908,117
Deferred Income Taxes		53,902			47,847
Other Assets		32,061			31,217
	$	2,329,990		$	2,208,594
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Accounts Payable	$	163,350		$	173,497
Current Portion of Long-Term Debt		20,000			20,000
Deferred Income Taxes		1,337			3,930
Income Taxes Payable		1,326			1,391
Derivative Contracts (Note 7)		78,074			5,383
Accrued Liabilities		57,539			48,065
Total Current Liabilities		321,626			252,266
Long-Term Liability for Pension Benefits (Note 10)		7,505			6,743
Long-Term Liability for Postretirement Benefits (Note 10)		20,723			20,204
Long-Term Debt (Note 4)		350,000			330,000
Deferred Income Taxes		508,138			481,770
Other Liabilities		57,752			47,354
Commitments and Contingencies (Note 6)
Stockholders’ Equity
Common Stock:
Authorized — 120,000,000 Shares of $0.10 Par Value Issued and Outstanding — 103,033,736 Shares and 102,681,468 Shares in 2008 and 2007, respectively		10,303			10,268
Additional Paid-in Capital		435,116			424,229
Retained Earnings		765,389			722,344
Accumulated Other Comprehensive Loss (Note 8)		(60,872	)		(894	)
Less Treasury Stock, at Cost:
5,204,700 Shares in both 2008 and 2007		(85,690	)		(85,690	)
Total Stockholders’ Equity		1,064,246			1,070,257
	$	2,329,990		$	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)

	Three Months Ended March 31,
(In thousands)	2008			2007
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income	$	45,975		$	48,547
Adjustments to Reconcile Net Income to Cash Provided by Operating Activities:
Depreciation, Depletion and Amortization		41,516			33,395
Impairment of Unproved Properties		4,751			3,986
Deferred Income Tax Expense		23,560			15,874
Gain on Sale of Assets		—			(7,920	)
Exploration Expense		5,061			5,652
Stock-Based Compensation Expense and Other		17,539			7,170
Changes in Assets and Liabilities:
Accounts Receivable, Net		(22,068	)		19,039
Income Taxes Receivable		(3,651	)		17,902
Inventories		14,849			17,587
Other Current Assets		859			(481	)
Other Assets		(534	)		(13,300	)
Accounts Payable and Accrued Liabilities		2,981			(28,548	)
Income Taxes Payable		4,577			10,963
Other Liabilities		1,931			10,127
Stock-Based Compensation Tax Benefit		(4,642	)		(4,135	)
Net Cash Provided by Operating Activities		132,704			135,858
CASH FLOWS FROM INVESTING ACTIVITIES
Capital Expenditures		(128,101	)		(113,748	)
Proceeds from Sale of Assets		—			5,784
Exploration Expense		(5,061	)		(5,652	)
Net Cash Used in Investing Activities		(133,162	)		(113,616	)
CASH FLOWS FROM FINANCING ACTIVITIES
Increase in Debt		20,000			—
Decrease in Debt		—			(10,000	)
Sale of Common Stock Proceeds		2,240			1,144
Stock-Based Compensation Tax Benefit		4,642			4,135
Dividends Paid		(2,930	)		(1,933	)
Net Cash Provided by / (Used in) Financing Activities		23,952			(6,654	)
Net Increase in Cash and Cash Equivalents		23,494			15,588
Cash and Cash Equivalents, Beginning of Period		18,498			41,854
Cash and Cash Equivalents, End of Period	$	41,992		$	57,442

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 presentation. 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 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. 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

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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 the 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.

2. PROPERTIES AND EQUIPMENT, NET

Properties and equipment, net are comprised of the following:

(In thousands)	March 31, 2008			December 31, 2007
Unproved Oil and Gas Properties	$	110,562		$	108,868
Proved Oil and Gas Properties		2,731,801			2,627,346
Gathering and Pipeline Systems		236,929			235,127
Land, Building and Improvements		4,902			5,094
Other		38,366			36,508
		3,122,560			3,012,943
Accumulated Depreciation, Depletion and Amortization		(1,150,537	)		(1,104,826	)
	$	1,972,023		$	1,908,117

At March 31, 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.

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3. ADDITIONAL BALANCE SHEET INFORMATION

Certain balance sheet amounts are comprised of the following:

	March 31,			December 31,
(In thousands)	2008			2007
ACCOUNTS RECEIVABLE, NET
Trade Accounts	$	117,245		$	94,550
Joint Interest Accounts		15,974			16,443
Other Accounts		2,237			2,291
		135,456			113,284
Allowance for Doubtful Accounts		(3,978	)		(3,978	)
	$	131,478		$	109,306
INVENTORIES
Natural Gas in Storage	$	5,793		$	20,472
Tubular Goods and Well Equipment		5,504			5,953
Pipeline Imbalances		1,207			928
	$	12,504		$	27,353
OTHER CURRENT ASSETS
Drilling Advances	$	2,365		$	2,475
Prepaid Balances		7,739			8,900
Restricted Cash		12,012			11,600
Other Accounts		338			338
	$	22,454		$	23,313
OTHER ASSETS
Note Receivable	$	13,375		$	13,375
Rabbi Trust Deferred Compensation Plan		9,618			9,744
Other Accounts		9,068			8,098
	$	32,061		$	31,217
ACCOUNTS PAYABLE
Trade Accounts	$	14,897		$	27,678
Natural Gas Purchases		7,985			6,465
Royalty and Other Owners		49,074			37,023
Capital Costs		68,957			83,754
Taxes Other Than Income		8,293			6,416
Drilling Advances		4,442			1,528
Wellhead Gas Imbalances		3,190			3,227
Other Accounts		6,512			7,406
	$	163,350		$	173,497
ACCRUED LIABILITIES
Employee Benefits	$	14,594		$	13,699
Supplemental Employee Incentive Plan		4,483			—
Current Liability for Pension Benefits		116			116
Current Liability for Postretirement Benefits		642			642
Taxes Other Than Income		18,965			13,216
Interest Payable		3,819			6,518
Litigation		12,012			11,600
Other Accounts		2,908			2,274
	$	57,539		$	48,065
OTHER LIABILITIES
Rabbi Trust Deferred Compensation Plan	$	17,360		$	16,018
Accrued Plugging and Abandonment Liability		25,460			24,724
Derivative Contracts		7,749			—
Other Accounts		7,183			6,612
	$	57,752		$	47,354

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4. LONG-TERM DEBT

At March 31, 2008, the Company had $160 million of borrowings outstanding under its revolving credit facility at a weighted-average interest rate of 5.9%. The credit facility provides for an available credit line of $250 million, which can be expanded up to $350 million, either with the existing banks or new banks. 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 March 31, 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 Company believes it is in compliance in all material respects with its debt covenants.

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 months ended March 31, 2008 and 2007:

	Three Months Ended March 31,
	2008	2007
Weighted-Average Shares - Basic	97,715,970	96,695,471
Dilution Effect of Stock Options and Awards at End of Period	1,208,805	1,351,187
Weighted-Average Shares - Diluted	98,924,775	98,046,658
Weighted-Average Stock Awards and Shares Excluded from Diluted Earnings per Share due to the Anti-Dilutive Effect	226,264	218,840

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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 March 31, 2008, these funds were classified within Other Current Assets in the Condensed Consolidated Balance Sheet. In the settlement, the Company and the class members also 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 $2.0 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.

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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 March 31, 2008, the total commitment remained unchanged 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 FASB Staff Position (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. 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 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 the related FSPs discussed above which did not have an impact on its financial position or results of operations for the quarter ended March 31, 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.

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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.

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 March 31, 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 March 31, 2008
Assets
Rabbi Trust Deferred Compensation Plan	$	9,618		$	—	$	—		$	9,618
Derivative Contracts		—			—	��	437			437
Total Assets	$	9,618		$	—	$	437		$	10,055
Liabilities
Rabbi Trust Deferred Compensation Plan	$	(17,360	)	$	—	$	—		$	(17,360	)
Derivative Contracts		—			—		(85,824	)		(85,824	)
Total Liabilities	$	(17,360	)	$	—	$	(85,824	)	$	(103,184	)

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.

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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 January 1, 2008	$	7,272
Total Gains or (Losses) (Realized or Unrealized):
Included in Earnings (2)		(1,022	)
Included in Other Comprehensive Income		(92,659	)
Purchases, Issuances and Settlements		1,022
Transfers In and/or Out of Level 3		—
Balance as of March 31, 2008	$	(85,387	)

⁽¹⁾ Net derivatives for Level 3 at December 31, 2007 included derivative assets of $0.4 million and derivative liabilities of $85.8 million.

⁽²⁾ All losses included in earnings were realized.

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.

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. Under the Company’s revolving credit agreement, the aggregate level of commodity hedging must not exceed 100% of the anticipated future equivalent production during the period covered by these cash flow hedges. At March 31, 2008, the Company had 33 cash flow hedges open: 29 natural gas price collar arrangements, three natural gas swap arrangements and one crude oil collar arrangement. At March 31, 2008, a $85.4 million ($53.7 million, net of tax) unrealized loss was recorded in Accumulated Other Comprehensive Income, along with a $78.1 million short-term derivative liability, a $7.7 million long-term derivative liability (included within Other Liabilities on the Condensed Consolidated Balance Sheet) and a $0.4 million long-term derivative receivable (included within Other Assets on the Condensed Consolidated Balance Sheet). The change in the fair value of derivatives designated as hedges that is effective is initially recorded to Accumulated Other Comprehensive Income. The ineffective portion, if any, of the change in the fair value of derivatives designated as hedges, and the change in fair value of all other derivatives is recorded currently in earnings as a component of Natural Gas Production and Crude Oil and Condensate Revenue, as appropriate. During the three months ended March 31, 2008 and 2007, there was no ineffectiveness recorded in the Condensed Consolidated Statement of Operations.

Based upon estimates at March 31, 2008, the Company would expect to reclassify to the Condensed Consolidated Statement of Operations over the next 12 months $49.1 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 March 31, 2008 related to anticipated 2008 and 2009 production.

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During the first three months of 2008, the Company entered into 17 new natural gas collar contracts covering a portion of its 2008 and 2009 production. As of March 31, 2008, natural gas price collars for the nine months ending December 31, 2008 will cover 44,163 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 March 31, 2008, natural gas price collars for the twelve months ending December 31, 2009 will cover 22,653 Mmcf of production at a weighted-average floor of $8.14 per Mcf and a weighted-average ceiling of $9.88 per Mcf.

8. COMPREHENSIVE INCOME

Comprehensive Income includes Net Income and certain items recorded directly to Stockholders’ Equity and classified as Accumulated Other Comprehensive Income / (Loss). The following table illustrates the calculation of Comprehensive Income for the three month periods ended March 31, 2008 and 2007:

	Three Months Ended March 31,
(In thousands)	2008								2007
Accumulated Other Comprehensive Income / (Loss)—Beginning of Period						$	(894	)				$	37,160
Net Income			$	45,975					$	48,547
Other Comprehensive Income / (Loss), net of taxes:
Reclassification Adjustment for Settled Contracts, net of taxes of $(379) and $6,719, respectively				643						(11,056	)
Changes in Fair Value of Hedge Positions, net of taxes of $34,778 and $12,904, respectively				(58,903	)					(21,886	)
Defined Benefit Pension and Postretirement Plans:
Amortization of Net Obligation at Transition, net of taxes of $(59)	$	99
Amortization of Prior Service Cost, net of taxes of $(93)		158
Amortization of Net Loss, net of taxes of $(128)		218
Total Defined Benefit Pension and Postretirement Plans, net of taxes of $(280) and $—, respectively				475						—
Foreign Currency Translation Adjustment, net of taxes of $1,358 and $(282), respectively				(2,193	)					465
Total Other Comprehensive Loss				(59,978	)		(59,978	)		(32,477	)		(32,477	)
Comprehensive Income / (Loss)			$	(14,003	)				$	16,070
Accumulated Other Comprehensive Income / (Loss)—End of Period						$	(60,872	)				$	4,683

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Changes in the components of accumulated other comprehensive income / (loss), net of taxes, for the three months ended March 31, 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 gains on cash flow hedges, net of taxes of $34,399		(58,260	)		—			—			(58,260	)
Net change in defined benefit pension and postretirement plans, net of taxes of $(280)		—			475			—			475
Change in foreign currency translation adjustment, net of taxes of $1,358		—			—			(2,193	)		(2,193	)
Balance at March 31, 2008	$	(53,707	)	$	(13,552	)	$	6,387		$	(60,872	)

9. ASSET RETIREMENT OBLIGATIONS

The following table reflects the changes in the asset retirement obligations during the three months ended March 31, 2008:

(In thousands)
Carrying amount of asset retirement obligations at December 31, 2007	$	24,724
Liabilities added during the current period		458
Liabilities settled and divested during the current period		(10	)
Current period accretion expense		288
Carrying amount of asset retirement obligations at March 31, 2008	$	25,460

Accretion expense was $0.3 million and $0.2 million, respectively, for the three months ended March 31, 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 months ended March 31, 2008 and 2007 were as follows:

	Three Months Ended March 31,
(In thousands)	2008			2007
Qualified and Non-Qualified Pension Plans
Current Period Service Cost	$	828		$	733
Interest Cost		818			692
Expected Return on Plan Assets		(884	)		(754	)
Amortization of Prior Service Cost		13			36
Amortization of Net Loss		294			272
Net Periodic Pension Cost	$	1,069		$	979
Postretirement Benefits Other than Pension Plans
Current Period Service Cost	$	235		$	224
Interest Cost		308			266
Amortization of Prior Service Cost		238			238
Amortization of Net Loss		52			42
Amortization of Net Obligation at Transition		158			158
Total Postretirement Benefit Cost	$	991		$	928

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 during the first three months of 2008 and 2007 was $13.1 million and $6.6 million, pre-tax, respectively, and is included in General and Administrative Expense in the Condensed Consolidated Statement of Operations.

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 quarter of 2008. Compensation expense recorded for all unvested restricted stock awards for the first three months of 2008 and 2007 was $0.7 million and $2.0 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 three months of 2008, 15,360 restricted stock units were granted with a grant date per share value of $48.96. The compensation cost, which reflects the total fair value of these units, recorded in the first quarter of 2008 was $0.8 million. During the first quarter 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.

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

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Stock Appreciation Rights

During the first three 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:

	Three Months Ended March 31, 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 quarters of 2008 and 2007 for SARs was $0.8 million for each period. 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 March 31, 2008, it is currently considered probable that these three criteria will be met.

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

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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 March 31, 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 35% to approximately 77% 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 March 31, 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 was not marked to market.

	March 31, 2008
Risk Free Rate of Return	1.4% -   1.7	%
Stock Price Volatility	35.1% - 37.7	%
Expected Dividend	0.2	%

The Monte Carlo value per share for the liability component for all outstanding market condition performance share awards ranged from $18.39 to $36.94 at March 31, 2008. The long-term liability for all market condition performance share awards, included in Other Liabilities in the Condensed Consolidated Balance Sheet, at March 31, 2008 and December 31, 2007 was $0.9 million and $0.2 million, respectively. The short-term liability, included in Accrued Liabilities in the Condensed Consolidated Balance Sheet, at March 31, 2008 and December 31, 2007, for certain market condition performance share awards was $9.8 million and $5.5 million.

Total compensation cost recognized for both the equity and liability components of all performance share awards as well as expense related to the supplemental employee incentive plan discussed below during the three months ended March 31, 2008 and 2007 was $10.8 million and $2.8 million, respectively.

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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 plan provides a total bonus pool of up to $45 million, as determined by the Compensation Committee of the Company’s Board of Directors. The bonus pool becomes available if, for any 20 trading days (which need not be consecutive) that fall within a period of 60 consecutive trading days occurring prior to 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 will allocate to eligible employees in its discretion the pool remaining after making the minimum distributions.

The plan also provides that up to 20%, or $9 million, of the total bonus pool, as determined by the Compensation Committee, will be paid as interim distributions 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. Subsequent to March 31, 2008, the Company achieved the interim target goal of $50 per share for 20 out of 60 trading days and a distribution totaling $3.1 million was paid to employees. These awards have been accounted for as liability awards under SFAS No. 123(R), and the total expense for the first quarter of 2008 was $4.5 million.

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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 March 31, 2008, and the related condensed consolidated statements of operations and of cash flows for the three month periods ended March 31, 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

May 5, 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 month periods ended March 31, 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 three months ended March 31, 2008 increased by $28.1 million, or 15%, from the three months ended March 31, 2007. Natural gas production revenues increased by $19.8 million, or 13%, for the quarter ended March 31, 2008 as compared to the quarter ended March 31, 2007 due to an increase in realized natural gas prices and an increase in natural gas production, primarily in the Gulf Coast. Crude oil and condensate revenues increased by $5.6 million, or 51%, for the first three months of 2008 as compared to the first three months of 2007 due to an increase in realized crude oil prices, slightly offset by a decrease in crude oil production, primarily in the West. Brokered natural gas revenues increased by $2.4 million due to an increase in sales price as well as an increase in brokered volumes.

Our average realized natural gas price for the quarter ended March 31, 2008 was $7.92 per Mcf, seven percent higher than the $7.42 per Mcf price realized in the same period of the prior year. Our average realized crude oil price was $86.55 per Bbl, 62% higher than the $53.36 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 three months of 2008 increased by six percent from the first three months of 2007. For the three months ended March 31, 2008, we produced 22.2 Bcfe compared to production of 21.0 Bcfe for the comparable period of the prior year. Natural gas production was 21.0 Bcf and oil production was 190 Mbbls for the first quarter of 2008. Natural gas production increased by six percent when compared to the comparable period of the prior year, which had production of 19.8 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 East region associated with an increase in the drilling program and an increase in Canada due to increased pipeline capacity in Canada for the Hinton field. These increases were partially offset by a decline in natural gas production in the West region due to natural decline and, to a lesser extent, lease access issues due to weather conditions in the Rocky Mountains. Oil production decreased by 15 Mbbls, or seven percent, from 205 Mbbls in the first quarter of 2007 to 190 Mbbls produced in the first quarter of 2008. This was primarily the result of a decrease of 11 Mbbls in the West region due to natural decline in Oklahoma.

We had net income of $46.0 million, or $0.47 per share, for the three months ended March 31, 2008 compared to net income of $48.5 million, or $0.50 per share, for the comparable period of the prior year. The decrease in net income is primarily due to the recognition of a $7.9 million gain on the sale of assets in the 2007 period. Operating revenues increased by $28.1 million primarily due to increases in crude oil and natural gas production revenues, as discussed above. Operating expenses increased by $23.3 million in the first quarter of 2008 as compared to the first quarter 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 $2.0 million increase in interest and other expenses, reduced income before taxes by $5.1 million and consequently decreased income tax expense by $2.6 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

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approximately $560 million in capital and exploration expenditures, up $70 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 incremental increase includes additional planned drilling activity and lease acquisition investments. We believe our cash on hand 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 three months ended March 31, 2008, approximately $113.9 million has been invested in our exploration and development efforts.

During the first quarter of 2008, we drilled 85 gross wells (83 development, one exploratory and one extension wells) with a success rate of 98% compared to 100 gross wells (97 development, two exploratory and one extension wells) with a success rate of 99% for the comparable period of the prior year. For the full year of 2008, we plan to drill approximately the same number of wells as we drilled in 2007. In 2007, we drilled 461 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. In the current year we have allocated our planned program for capital and exploration expenditures among our various operating regions. 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.

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 quarter ended March 31, 2008 were from funds generated from the sale of natural gas and crude oil production and, to a lesser extent, borrowings under our revolving credit facility. Cash flows provided by operating activities were primarily used to fund development and, to a lesser extent, exploratory expenditures, 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.

	Three Months Ended March 31,
(In thousands)	2008			2007
Cash Flows Provided by Operating Activities	$	132,704		$	135,858
Cash Flows Used in Investing Activities		(133,162	)		(113,616	)
Cash Flows Provided by / (Used in) Financing Activities		23,952			(6,654	)
Net Increase in Cash and Cash Equivalents	$	23,494		$	15,588

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Operating Activities. Net cash provided by operating activities in the first three months of 2008 decreased by $3.2 million over the comparable period in 2007. This decrease is primarily due to the decrease 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 62% for the first quarter of 2008 versus the 2007 period and average realized natural gas prices increased by seven percent over the same period. Equivalent production volumes increased by approximately six percent in the first quarter of 2008 compared to the first quarter 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 $19.5 million from the first three months of 2007 compared to the first three months of 2008. The increase from 2007 to 2008 is due to an increase of $14.3 million in capital expenditures as well as $5.8 million of lower proceeds from the sale of assets, partially offset by reduced exploration expenditures of $0.6 million.

Financing Activities. Cash flows provided by financing activities were $24.0 million for the first quarter of 2008, and contained a net increase in borrowings under our revolving credit facility, the tax benefit received from stock-based compensation payments and proceeds from the exercise of stock options, partially offset by dividend payments. Cash flows used in financing activities were $6.7 million for the first quarter of 2007, and were comprised of payments made to decrease outstanding debt under our revolving credit facility and to pay dividends. Partially offsetting these cash uses in 2007 were inflows from the tax benefit received from stock-based compensation and proceeds from the exercise of stock options.

At March 31, 2008, we had $160 million of borrowings outstanding under our credit facility at a weighted-average interest rate of 5.9%. The credit facility provides for an available credit line of $250 million, which can be expanded up to $350 million, either with the existing banks or new banks. 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. We strive to manage our debt at a level below the available credit line in order to maintain excess borrowing capacity. Management believes that we have the ability to finance through new debt or equity offerings, if necessary, our capital requirements, including potential acquisitions.

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 quarter ended March 31, 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 March 31, 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.

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Capitalization

Information about our capitalization is as follows:

(Dollars in millions)	March 31, 2008			December 31, 2007
Debt(1)	$	370.0		$	350.0
Stockholders’ Equity		1,064.2			1,070.3
Total Capitalization	$	1,434.2		$	1,420.3
Debt to Capitalization		26	%		25	%
Cash and Cash Equivalents	$	42.0		$	18.5

⁽¹⁾ Includes $20.0 million of current portion of long-term debt at both March 31, 2008 and December 31, 2007. Includes $160 million and $140 million of borrowings outstanding under our revolving credit facility at March 31, 2008 and December 31, 2007, respectively.

During the quarter ended March 31, 2008, we paid dividends of $2.9 million on our common stock. A regular dividend has been declared for each quarter since we became a public company in 1990.

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 three months ended March 31, 2008 and 2007:

	Three Months Ended March 31,
(In millions)	2008		2007
Capital Expenditures
Drilling and Facilities	$	99.5	$	115.0
Leasehold Acquisitions		6.4		4.4
Pipeline and Gathering		1.8		3.7
Other		1.1		0.4
		108.8		123.5
Exploration Expense		5.1		5.7
Total	$	113.9	$	129.2

For the full year of 2008, we plan to drill approximately the same number of wells as we drilled in 2007. In 2007, we drilled 461 gross wells. This drilling program includes approximately $560 million in total capital and exploration expenditures, down 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.

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Contractual Obligations

At March 31, 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.

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

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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 assets and liabilities were $0.4 million and $85.8 million, respectively, at March 31, 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.

Results of Operations

First Quarters of 2008 and 2007 Compared

We reported net income in the first quarter of 2008 of $46.0 million, or $0.47 per share. During the corresponding quarter of 2007, we reported net income of $48.5 million, or $0.50 per share. Net income decreased in the first quarter of 2008 by $2.5 million, primarily due to an increase in operating expenses and a decrease in gain on sale of assets, partially offset by increased operating revenues. Operating revenues increased by $28.1 million, largely due to increases in both natural gas production revenues and crude oil and condensate revenues. Operating expenses increased by $23.3 million between quarters largely due to increased general and administrative expenses resulting from higher stock compensation, higher DD&A and, to a lesser extent, higher taxes other than income and brokered natural gas costs. In addition, net income was impacted by a decrease in gain on sale of assets of $7.9 million as well as a decrease in expenses of $0.6 million resulting from a combination of lower income tax expense, partially offset by higher interest and other expenses. Income tax expense was lower in the 2008 period as a result of lower income before income taxes in the first quarter of 2008 period compared to the first quarter of 2007 combined with a 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 $7.92 per Mcf for the three months ended March 31, 2008 compared to $7.42 per Mcf for the comparable period of the prior year. These prices include the realized impact of derivative instrument settlements which increased the price by $0.03 per Mcf in 2008 and $0.89 per Mcf in 2007. There was no revenue impact from the unrealized change in natural gas derivative fair value for the three months ended March 31, 2008 or 2007.

	Three Months Ended March 31,					Variance
	2008			2007		Amount			Percent
Natural Gas Production(Mmcf)
East		6,000			5,757		243		4	%
Gulf Coast		7,405			6,479		926		14	%
West		6,366			6,458		(92	)	(1	)%
Canada		1,246			1,072		174		16	%
Total Company		21,017			19,766		1,251		6	%
Natural Gas Production Sales Price ($/Mcf)
East	$	8.28		$	8.08	$	0.20		2	%
Gulf Coast	$	8.30		$	7.75	$	0.55		7	%
West	$	7.26		$	6.51	$	0.75		12	%
Canada	$	7.38		$	7.46	$	(0.08	)	(1	)%
Total Company	$	7.92		$	7.42	$	0.50		7	%
Natural Gas Production Revenue(In thousands)
East	$	49,709		$	46,498	$	3,211		7	%
Gulf Coast		61,437			50,240		11,197		22	%
West		46,220			42,020		4,200		10	%
Canada		9,193			7,992		1,201		15	%
Total Company	$	166,559		$	146,750	$	19,809		13	%
Price Variance Impact on Natural Gas Production Revenue(In thousands)
East	$	1,252
Gulf Coast		4,096
West		4,799
Canada		(98	)
Total Company	$	10,049
Volume Variance Impact on Natural Gas Production Revenue(In thousands)
East	$	1,959
Gulf Coast		7,101
West		(599	)
Canada		1,299
Total Company	$	9,760

The increase in Natural Gas Production Revenue of $19.8 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 East region associated with an increase in the drilling program and increased in Canada due to increased pipeline capacity in the Hinton field. These increases were partially offset by a decline in natural gas production in the West region due to natural decline and, to a lesser extent, lease access issues due to weather conditions in the Rocky Mountains.

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Brokered Natural Gas Revenue and Cost

	Three Months Ended March 31,					Variance
	2008			2007		Amount		Percent
Sales Price($/Mcf)	$	9.49		$	8.96	$	0.53	6	%
Volume Brokered(Mmcf)		3,753			3,703		50	1	%
Brokered Natural Gas Revenues(In thousands)	$	35,620		$	33,177
Purchase Price($/Mcf)	$	8.07		$	7.75	$	0.32	4	%
Volume Brokered(Mmcf)		3,753			3,703		50	1	%
Brokered Natural Gas Cost(In thousands)	$	30,290		$	28,699
Brokered Natural Gas Margin(In thousands)	$	5,330		$	4,478	$	852	19	%
(In thousands)
Sales Price Variance Impact on Revenue	$	1,995
Volume Variance Impact on Revenue		448
	$	2,443
(In thousands)
Purchase Price Variance Impact on Purchases	$	(1,203	)
Volume Variance Impact on Purchases		(388	)
	$	(1,591	)

The increased brokered natural gas margin of $0.8 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 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 $86.55 per Bbl for the first quarter of 2008 compared to $53.36 per Bbl for the first quarter of 2007. These prices include the realized impact of derivative instrument settlements which decreased the price by $8.60 per Bbl in 2008 and increased the price by $0.89 per Bbl in 2007. There was no revenue impact from the unrealized change in crude oil and condensate derivative fair value for the three months ended March 31, 2008 or 2007.

	Three Months Ended March 31,					Variance
	2008			2007		Amount			Percent
Crude Oil Production(Mbbl)
East		6			6		—		—
Gulf Coast		144			148		(4	)	(3	)%
West		34			45		(11	)	(24	)%
Canada		6			6		—		—
Total Company		190			205		(15	)	(7	)%
Crude Oil Sales Price($/Bbl)
East	$	90.04		$	53.49	$	36.55		68	%
Gulf Coast	$	84.58		$	53.07	$	31.51		59	%
West	$	95.66		$	54.17	$	41.49		77	%
Canada	$	79.38		$	54.44	$	24.94		46	%
Total Company	$	86.55		$	53.36	$	33.19		62	%
Crude Oil Revenue(In thousands)
East	$	543		$	324	$	219		68	%
Gulf Coast		12,201			7,872		4,329		55	%
West		3,243			2,434		809		33	%
Canada		500			312		188		60	%
Total Company	$	16,487		$	10,942	$	5,545		51	%
Price Variance Impact on Crude Oil Revenue(In thousands)
East	$	219
Gulf Coast		4,545
West		1,406
Canada		188
Total Company	$	6,358
Volume Variance Impact on Crude Oil Revenue(In thousands)
East	$	—
Gulf Coast		(216	)
West		(597	)
Canada		—
Total Company	$	(813	)

The increase in realized crude oil prices, partially offset by a decrease in production, resulted in a net revenue increase of $5.6 million. The decrease in oil production is mainly the result of decreased crude oil production in the West region due to natural decline in Oklahoma.

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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 March 31,
	2008					2007
(In thousands)	Realized			Unrealized		Realized		Unrealized
Operating Revenues - Increase / (Decrease) to Revenue
Cash Flow Hedges
Natural Gas Production	$	612		$	—	$	17,593	$	—
Crude Oil		(1,634	)		—		182		—
Total Cash Flow Hedges	$	(1,022	)	$	—	$	17,775	$	—

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 $23.3 million in the first 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 $9.3 million in the first quarter of 2008 compared with the first quarter of 2007. This is primarily due to increased stock compensation expense related to our performance shares as well as our supplemental employee incentive plan that commenced in January 2008.

• Depreciation, Depletion and Amortization increased by $8.1 million in the first quarter 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.

• Taxes Other Than Income increased by $3.8 million from the first quarter of 2007 to the first quarter of 2008 due to higher production taxes as a result of higher operating revenues and, to a lesser extent, higher ad valorem taxes.

• Brokered Natural Gas Cost increased by $1.6 million from the first quarter of 2007 to the first quarter of 2008. See the preceding table titled “Brokered Natural Gas Revenue and Cost” for further analysis.

Interest Expense, Net

Interest expense, net increased by $2.1 million in the first quarter of 2008 primarily due to higher average credit facility borrowings, 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 $157 million during the first quarter of 2008 compared to approximately $3 million during the first quarter of 2007. In addition, the weighted-average effective interest rate on the credit facility decreased to 5.9% in the first quarter of 2008 from 8.3% in the first quarter of 2007.

Income Tax Expense

Income tax expense decreased by $2.6 million due to a comparable decrease in our pre-tax income. The effective tax rate for the first quarter of 2008 and 2007 was 34.4% and 35.5%, respectively. The decrease in the effective tax rate is primarily due to a reduction in our overall state income tax liability relating to the 2006 south Louisiana and offshore properties sale.

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Recently Issued Accounting Pronouncements

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 the 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, 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.

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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.

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 three months of 2008, natural gas price swaps covered 1,233 Mmcf of our gas production, or six percent of our first quarter 2008 gas production at an average price of $7.44 per Mcf. We did not enter into any natural gas price swaps covering our 2009 production.

At March 31, 2008, we had open natural gas price swap contracts covering a portion of our 2008 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 March 31, 2008
Second Quarter 2008	1,233	$	7.44
Third Quarter 2008	1,246		7.44
Fourth Quarter 2008	1,246		7.44
Nine Months Ended December 31, 2008	3,725	$	7.44	$	(8,171	)

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 three months of 2008, natural gas price collars covered 10,009 Mmcf, or 48%, of our first quarter 2008 gas production, with a weighted-average floor of $8.25 per Mcf and a weighted-average ceiling of $10.14 per Mcf.

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At March 31, 2008, we had open natural gas price collar contracts covering a portion of our 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 March 31, 2008
Second Quarter 2008	14,614	$	10.83 / $8.59
Third Quarter 2008	14,775		10.83 / 8.59
Fourth Quarter 2008	14,775		10.83 / 8.59
Nine Months Ended December 31, 2008	44,164	$	10.83 / $8.59	$	(51,180	)
First Quarter 2009	5,585	$	9.88 / $8.14
Second Quarter 2009	5,648		9.88 / 8.14
Third Quarter 2009	5,710		9.88 / 8.14
Fourth Quarter 2009	5,710		9.88 / 8.14
Full Year 2009	22,653	$	9.88 / $8.14	$	(19,692	)

During the first three months of 2008, a crude oil price collar covered 91 Mbbls, or 48%, of our first quarter 2008 crude oil production, with a floor of $60.00 per Bbl and a ceiling of $80.00 per Bbl.

At March 31, 2008 we had one open crude oil price collar contract covering a portion of 2008 production as follows:

	Crude Oil Price Collar
Contract Period	Volume in Mbbl	Ceiling / Floor (per Bbl)		Net Unrealized Loss (In thousands)
As of March 31, 2008
Second Quarter 2008	91	$	80.00 / $60.00
Third Quarter 2008	92		80.00 / 60.00
Fourth Quarter 2008	92		80.00 / 60.00
Nine Months Ended December 31, 2008	275	$	80.00 / $60.00	$	(6,343	)

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 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.

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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 first 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.

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.

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 three months ended March 31, 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 March 31, 2008 was 4,795,300.

ITEM 6. Exhibits

10.1	Second Amendment to the Savings Investment Plan of the Company effective April 23, 2008
10.2	Second Amendment to the Pension Plan of the Company effective April 23, 2008
10.3	Supplemental Employee Incentive Plan of the Company, as amended and restated, effective January 16, 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

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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)
May 5, 2008	By:	/s/ Dan O. Dinges
		Dan O. Dinges
		Chairman, President and Chief Executive Officer
		(Principal Executive Officer)
May 5, 2008	By:	/s/ Scott C. Schroeder
		Scott C. Schroeder
		Vice President and Chief Financial Officer
		(Principal Financial Officer)
May 5, 2008	By:	/s/ Henry C. Smyth
		Henry C. Smyth
		Vice President, Controller and Treasurer
		(Principal Accounting Officer)

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