Coterra Energy (CTRA) 10-Q 2005 Q2 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 June 30, 2005

¨ 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)

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 an accelerated filer (as defined in Rule 12b-2 of the Act).     Yes  x    No  ¨

As of July27, 2005, there were48,944,424 shares of Common Stock, Par Value $.10 Per Share, outstanding.

CABOT OIL & GAS CORPORATION

INDEX TO FINANCIAL STATEMENTS

Part I. Financial Information			Page
	Item 1. Financial Statements
		Condensed Consolidated Statement of Operations for the Three Months and Six Months Ended June 30, 2005 and 2004	3
		Condensed Consolidated Balance Sheet at June 30, 2005 and December 31, 2004	4
		Condensed Consolidated Statement of Cash Flows for the Six Months Ended June 30, 2005 and 2004	5
		Notes to the Condensed Consolidated Financial Statements	6
		Report of Independent Registered Public Accounting Firm on Review of Interim Financial Information	16
	Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		17
	Item 3. Quantitative and Qualitative Disclosures about Market Risk		30
	Item 4. Controls and Procedures		32
Part II. Other Information
	Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		32
	Item 4. Submission of Matters to a Vote of Security Holders		33
	Item 6. Exhibits		34
Signatures			35

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PART I. FINANCIAL INFORMATION

ITEM 1. Financial Statements

CABOT OIL & GAS CORPORATION

CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS (Unaudited)

(In thousands, except per share amounts)

	Three Months Ended June 30,					Six Months Ended June 30,
	2005		2004			2005		2004
OPERATING REVENUES
Natural Gas Production	$	111,817	$	90,028		$	216,089	$	180,407
Brokered Natural Gas		15,520		15,628			42,012		47,187
Crude Oil and Condensate		23,936		13,552			35,914		26,319
Other		611		534			1,943		2,433
		151,884		119,742			295,958		256,346
OPERATING EXPENSES
Brokered Natural Gas Cost		13,701		13,596			36,999		42,317
Direct Operations - Field and Pipeline		14,307		13,114			28,925		25,192
Exploration		11,362		9,568			30,731		25,712
Depreciation, Depletion and Amortization		26,112		24,622			52,768		48,851
Impairment of Unproved Properties		3,643		2,728			7,054		5,311
General and Administrative		8,700		9,582			17,660		16,298
Taxes Other Than Income		12,396		9,921			22,114		20,023
		90,221		83,131			196,251		183,704
Gain / (Loss) on Sale of Assets		59		(172	)		59		(113	)
INCOME FROM OPERATIONS		61,722		36,439			99,766		72,529
Interest Expense and Other		5,134		5,445			10,122		10,822
Income Before Income Taxes		56,588		30,994			89,644		61,707
Income Tax Expense		21,166		11,676			33,460		23,378
NET INCOME	$	35,422	$	19,318		$	56,184	$	38,329
Basic Earnings per Share	$	0.72	$	0.40		$	1.15	$	0.79
Diluted Earnings per Share	$	0.71	$	0.39		$	1.13	$	0.78
Average Common Shares Outstanding		48,917		48,789			48,821		48,693
Diluted Common Shares (Note 6)		49,578		49,393			49,515		49,292

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

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CABOT OIL & GAS CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEET (Unaudited)

(In thousands, except share amounts)

	June 30,			December 31,
	2005			2004
ASSETS
Current Assets
Cash and Cash Equivalents	$	51,946		$	10,026
Accounts Receivable		93,416			125,754
Inventories		23,825			24,049
Deferred Income Taxes		24,636			21,345
Other		13,577			13,505
Total Current Assets		207,400			194,679
Properties and Equipment, Net (Successful Efforts Method)		1,050,987			994,081
Deferred Income Taxes		14,680			14,855
Other Assets		7,351			7,341
	$	1,280,418		$	1,210,956
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Accounts Payable	$	98,672		$	104,969
Current Portion of Long-Term Debt		20,000			20,000
Deferred Income Taxes		404			944
Derivative Contracts		42,116			38,368
Accrued Liabilities		31,540			32,608
Total Current Liabilities		192,732			196,889
Long-Term Debt		250,000			250,000
Deferred Income Taxes		259,701			247,376
Other Liabilities		62,165			61,029
Commitments and Contingencies (Note 7)
Stockholders’ Equity
Common Stock:
Authorized — 80,000,000 Shares of $.10 Par Value Issued and Outstanding — 50,016,774 Shares and 49,680,915 Shares in 2005 and 2004, respectively		5,002			4,968
Additional Paid-in Capital		388,655			380,125
Retained Earnings		163,823			110,935
Accumulated Other Comprehensive Loss		(21,074	)		(20,351	)
Less Treasury Stock, at Cost:
1,081,250 and 1,061,550 Shares in 2005 and 2004		(20,586	)		(20,015	)
Total Stockholders’ Equity		515,820			455,662
	$	1,280,418		$	1,210,956

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)

(In thousands)

	Six Months Ended June 30,
	2005			2004
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income	$	56,184		$	38,329
Adjustments to Reconcile Net Income to Cash
Provided by Operating Activities:
Depletion, Depreciation and Amortization		52,768			48,851
Impairment of Unproved Properties		7,054			5,311
Deferred Income Tax Expense		9,078			7,181
(Gain) / Loss on Sale of Assets		(59	)		113
Exploration Expense		30,731			25,712
Change in Derivative Fair Value		3,681			6,272
Performance Share Compensation		114			—
Other		2,733			721
Changes in Assets and Liabilities:
Accounts Receivable		32,338			(2,070	)
Inventories		224			8,722
Other Current Assets		(2,858	)		(1,017	)
Other Assets		(134	)		178
Accounts Payable and Accrued Liabilities		(4,844	)		3,573
Other Liabilities		1,066			1,425
Net Cash Provided by Operating Activities		188,076			143,301
CASH FLOWS FROM INVESTING ACTIVITIES
Capital Expenditures		(115,848	)		(102,430	)
Proceeds from Sale of Assets		710			22
Exploration Expense		(30,731	)		(25,712	)
Net Cash Used by Investing Activities		(145,869	)		(128,120	)
CASH FLOWS FROM FINANCING ACTIVITIES
Increase in Debt		—			28,000
Decrease in Debt		—			(28,000	)
Sale of Common Stock Proceeds		3,580			13,468
Purchase of Treasury Stock		(571	)		(5,342	)
Dividends Paid		(3,296	)		(2,602	)
Net Cash Provided / (Used) by Financing Activities		(287	)		5,524
Net Increase in Cash and Cash Equivalents		41,920			20,705
Cash and Cash Equivalents, Beginning of Period		10,026			724
Cash and Cash Equivalents, End of Period	$	51,946		$	21,429

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 Report on Form 10-K for the year ended December 31, 2004 filed with the Securities and Exchange Commission. People using financial information produced for interim periods are encouraged to refer to the footnotes in the Annual Report on Form 10-K for the year ended December 31, 2004 when reviewing interim financial results. 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 of operations for any interim period are not necessarily indicative of the results of operations 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, this 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.

On February 28, 2005, the Company announced that the Board of Directors had declared a 3-for-2 split of the Company’s Common Stock in the form of a stock distribution. The stock dividend was distributed on March 31, 2005 to stockholders of record on March 18, 2005. In lieu of issuing fractional shares, the Company paid cash based on the closing price of the Common Stock on the record date. All common stock accounts and per share data have been retroactively adjusted to give effect to the 3-for-2 split of the Company’s Common Stock.

Recently Issued Accounting Pronouncements

In May 2005, the Financial Accounting Standard Board (FASB) issued Statement of Financial Accounting Standards (SFAS) No. 154, “Accounting Changes and Error Corrections-a replacement of APB Opinion No. 20 and FASB Statement No. 3.” In order to enhance financial reporting consistency between periods, SFAS 154 modifies the requirements for the accounting and reporting of the direct effects of changes in accounting principles. Under APB Opinion 20, the cumulative effect of voluntary changes in accounting principle was recognized in Net Income in the period of the change. Unlike the treatment previously prescribed by APB Opinion 20, retrospective application is now required, unless it is not practical to determine the specific effects in each period or the cumulative effect. If the period specific effects cannot be determined, it is required that the new accounting principle must be retrospectively applied in the earliest period possible to the balance sheet accounts and a corresponding adjustment be made to the opening balance of retained earnings or another equity account. If the cumulative effect cannot be determined, it is necessary to apply the new accounting principles prospectively at the earliest practical date. If it is not feasible to retrospectively apply the change in principle, the reason that this is not possible and the method used to report the change is required to be disclosed. The statement also provides that changes in accounting for depreciation, depletion or amortization should be treated as changes in accounting estimate inseparable from a change in accounting principle and that disclosure of the preferability of the change is required. SFAS 154 is effective for accounting changes made in fiscal years beginning after December 15, 2005.

In December 2004, the FASB issued Statement SFAS No. 123R, “Share-Based Payment.” SFAS 123R revises SFAS 123, “Accounting for Stock-Based Compensation,” and focuses on accounting for share-based payments for services provided by employee to employer. The statement requires companies to expense the fair value of employee stock options and other equity-based compensation at the grant date. The statement does not require a certain type of valuation model, and either a binomial or Black-Scholes model may be used. During the first quarter of 2005, the Securities and Exchange Commission (SEC) approved a new rule for public companies to delay the adoption of this standard. In April 2005, the SEC took further action to amend Regulation S-X to state that the provisions of SFAS 123R are now effective beginning with the first annual or interim reporting period of the registrant’s first fiscal year beginning on or after June 15, 2005 for all non-small business issuers. As a result, the Company will not adopt this SFAS until the first quarter of 2006. The Company is currently evaluating the method of adoption and the impact on the Company’s operating results. Future cash flows of the Company will not be impacted by the adoption of this standard. See “Stock Based Compensation” below for further information.

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In March 2005, the FASB issued FASB Interpretation (FIN) No. 47, “Accounting for Conditional Asset Retirement Obligations.” This Interpretation clarifies the definition and treatment of conditional asset retirement obligations as discussed in FASB Statement No. 143, “Accounting for Asset Retirement Obligations.” A conditional asset retirement obligation is defined as an asset retirement activity in which the timing and/or method of settlement are dependent on future events that may be outside the control of the Company. FIN 47 states that a Company must record a liability when incurred for conditional asset retirement obligations if the fair value of the obligation is reasonably estimable. This Interpretation is intended to provide more information about long-lived assets, more information about future cash outflows for these obligations and more consistent recognition of these liabilities. FIN 47 is effective for fiscal years ending after December 15, 2005. The Company does not believe that its financial position, results of operations or cash flows will be impacted by this Interpretation.

Stock Based Compensation

The Company accounts for stock-based compensation in accordance with the intrinsic value based method prescribed by Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees.” Under the intrinsic value based method, compensation cost is the excess, if any, of the quoted market price of the stock at the grant date over the amount an employee must pay to acquire the stock.

SFAS 123, “Accounting for Stock-Based Compensation,” as amended by SFAS 148, “Accounting for Stock-Based Compensation – Transition and Disclosure,” outlines a fair value based method of accounting for stock options or similar equity instruments.

The following table illustrates the effect on Net Income and Earnings per Share if the Company had applied the fair value recognition provisions of SFAS 123 to stock-based employee compensation. The Earnings per Share amounts for prior periods have been retroactively adjusted to reflect the 3-for-2 split of the Company’s Common Stock effective March 31, 2005.

	Three Months Ended June 30,						Six Months Ended June 30,
(In thousands, except per share amounts)	2005			2004			2005			2004
Net Income, as reported	$	35,422		$	19,318		$	56,184		$	38,329
Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards, net of tax, previously not included in Net Income		(187	)		(479	)		(479	)		(954	)
Pro forma Net Income	$	35,235		$	18,839		$	55,705		$	37,375
Earnings per Share:
Basic - as reported	$	0.72		$	0.40		$	1.15		$	0.79
Basic - pro forma	$	0.72		$	0.39		$	1.14		$	0.77
Diluted - as reported	$	0.71		$	0.39		$	1.13		$	0.78
Diluted - pro forma	$	0.71		$	0.38		$	1.13		$	0.76

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The assumptions used in the fair value method calculation as well as additional stock-based compensation information are disclosed in the following table.

	Three Months Ended June 30,					Six Months Ended June 30,
(In thousands, except per share amounts)	2005		2004			2005		2004
Compensation Expense in Net Income, as reported(1)	$	948	$	1,638		$	1,588	$	1,930
Weighted Average Value per Option Granted
During the Period(2) (3)	$	—	$	11.31		$	—	$	11.31
Assumptions(3)
Stock Price Volatility		—		38.4	%		—		38.4	%
Risk Free Rate of Return		—		3.3	%		—		3.3	%
Dividend Rate (per year)	$	0.16	$	0.16		$	0.16	$	0.16
Expected Term (in years)		—		4			—		4

⁽¹⁾ Compensation expense is defined as expense related to the vesting of stock grants, net of tax. Compensation expense for the three months ended June 30, 2005and 2004 also includes $(0.2) million and $1.1 million, respectively, net of tax related to performance shares. Compensation expense for the six months endedJune 30, 2005 and 2004 also includes $0.1 million and $1.1 million, respectively, net of tax, related to performance shares.

⁽²⁾ Calculated using the Black-Scholes fair value based method.

⁽³⁾ There were no stock options issued in the first or second quarters of 2005.

2. PROPERTIES AND EQUIPMENT

Properties and equipment are comprised of the following:

	June 30, 2005			December 31, 2004
	(In thousands)
Unproved Oil and Gas Properties	$	96,926		$	94,795
Proved Oil and Gas Properties		1,747,518			1,646,841
Gathering and Pipeline Systems		168,294			160,951
Land, Building and Improvements		4,882			4,860
Other		32,210			31,261
		2,049,830			1,938,708
Accumulated Depreciation, Depletion and Amortization		(998,843	)		(944,627	)
	$	1,050,987		$	994,081

As of June 30, 2005, we did not have any significant changes from year end as defined in the FASB Staff Position FAS 19-1.

3. INVENTORIES

Inventories are comprised of the following:

	June 30, 2005		December 31, 2004
	(In thousands)
Natural Gas and Oil in Storage	$	14,660	$	17,631
Tubular Goods and Well Equipment		8,211		6,387
Pipeline Imbalances		954		31
	$	23,825	$	24,049

Natural gas and oil in storage is valued at average cost. Tubular goods and well equipment is valued at historical cost. All inventory balances are carried at the lower of cost or market.

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4. ADDITIONAL BALANCE SHEET INFORMATION

Certain balance sheet amounts are comprised of the following:

	June 30, 2005			December 31, 2004
	(In thousands)
Accounts Receivable
Trade Accounts	$	84,652		$	105,378
Joint Interest Accounts		13,192			13,554
Current Income Tax Receivable		463			10,796
Other Accounts		351			1,312
		98,658			131,040
Allowance for Doubtful Accounts		(5,242	)		(5,286	)
	$	93,416		$	125,754
Other Current Assets
Derivative Contracts	$	119		$	2,906
Drilling Advances		6,322			6,180
Prepaid Balances		6,889			4,173
Other Accounts		247			246
	$	13,577		$	13,505
Accounts Payable
Trade Accounts	$	9,371		$	12,808
Natural Gas Purchases		11,563			8,669
Royalty and Other Owners		31,972			35,369
Capital Costs		26,599			26,203
Taxes Other Than Income		4,426			5,634
Drilling Advances		5,878			7,102
Wellhead Gas Imbalances		2,271			1,991
Other Accounts		6,592			7,193
	$	98,672		$	104,969
Accrued Liabilities
Employee Benefits	$	5,006		$	10,123
Taxes Other Than Income		15,720			14,191
Interest Payable		6,321			6,569
Other Accounts		4,493			1,725
	$	31,540		$	32,608
Other Liabilities
Postretirement Benefits Other Than Pension	$	5,235		$	4,717
Accrued Pension Cost		4,898			5,089
Rabbi Trust Deferred Compensation Plan		4,593			4,199
Accrued Plugging and Abandonment Liability		41,444			40,375
Other Accounts		5,995			6,649
	$	62,165		$	61,029

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5. LONG-TERM DEBT

At June 30, 2005, the Company did not have any debt outstanding under its Revolving Credit Agreement (Credit Facility), which 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. To expand the credit line, the Company must seek prior approval from the administrative agent and the bank whose commitment is increasing. 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 to reduce its outstanding debt to the adjusted credit line available with a requirement to provide additional borrowing base assets or pay down one-sixth of the excess during each of the six months.

The Company has the following debt outstanding at June 30, 2005:

• $100 million of 12-year 7.19% Notes to be repaid in five annual installments of $20 million beginning in November 2005

• $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

6. EARNINGS PER SHARE

Basic Earnings per 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 using the treasury stock method except that the denominator is increased to reflect the potential dilution that could occur if outstanding 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 and six months ended June 30, 2005 and 2004.

	Three Months Ended June 30,		Six Months Ended June 30,
	2005	2004	2005	2004
Shares - basic	48,917,430	48,788,870	48,821,369	48,692,803
Dilution effect of stock options and awards at end of period	660,958	604,139	693,713	599,687
Shares - diluted	49,578,388	49,393,009	49,515,082	49,292,490
Stock awards and shares excluded from diluted earnings per share due to the anti-dilutive effect	—	—	—	—

7. COMMITMENTS AND CONTINGENCIES

Contingencies

The Company is a defendant in various legal proceedings arising in the normal course of our 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 consolidated financial position. Operating results and cash flow, however, could be significantly impacted in the reporting periods in which such matters are resolved.

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Wyoming Royalty Litigation

In June 2000, the Company was sued by two overriding royalty owners in Wyoming state court for unspecified damages. The plaintiffs requested class certification. The plaintiffs alleged that the Company improperly deducted costs from their overriding royalty interests. Further, the suit alleged the Company had failed to properly report information required to be reported by a Wyoming statute. At a mediation held in April 2003, the plaintiffs in this case claimed total damages of $9.5 million plus attorney fees. The Company settled the case on a class basis for a total of $2.25 million. The State District Court Judge entered his order approving the settlement in the fourth quarter of 2003. The class included all private fee royalty and overriding royalty owners of the Company in the State of Wyoming except those in the suit discussed below and one owner who opted out of the settlement. The settlement included provisions for the method of valuation of gas for royalty payment purposes going forward and for reporting of royalty payments, which should prevent further litigation of these issues by the class members.

In January 2002, 13 overriding royalty owners sued the Company in Wyoming federal district court. The plaintiffs in that case made the same general claims pertaining to deductions from their overriding royalty as the plaintiffs in the Wyoming state court. The judge has recently issued an order requested by the Company striking plaintiffs’ expert witness on damages. In a related case with the same plaintiffs, but different oil and gas company defendants, the same federal district court judge then granted the oil and gas company defendants summary judgment on a legal issue that if applied to the Company’s case would result in judgment for the Company. As a result of these decisions, the Company and the plaintiffs have reached an oral settlement, and settlement documents are being prepared. Management has a reserve it believes is adequate based on its estimate of the probable outcome of this case.

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 have requested class certification and allege that the Company failed to pay royalty based upon the wholesale market value of the gas, that it had taken improper deductions from the royalty and failed to properly inform royalty owners of the deductions. The plaintiffs have 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.

Discovery and pleadings necessary to place the class certification issue before the state court have been ongoing. The court entered an order on June 1, 2005 granting the motion for class certification. Trial has been set for April 17, 2006. The Company intends to challenge the class certification order by filing a Petition for Writ of Prohibition with the West Virginia Supreme Court of Appeals.

The Company is vigorously defending the case. It has a reserve that management believes is adequate based on its estimate of the probable outcome of this case.

Texas Title Litigation

On January 6, 2003, the Company was served with Plaintiffs’ Second Amended Original Petition in Romeo Longoria, et al. v. Exxon Mobil Corporation, et al. in the 79th Judicial District Court of Brooks County, Texas. Plaintiffs filed their Second Supplemental Original Petition on November 12, 2004. Plaintiffs allege that they are the owners of a one-half undivided mineral interest in and to certain lands in Brooks County, Texas. Cody Energy, LLC, a subsidiary of the Company, acquired certain leases and wells in 1997 and 1998.

The plaintiffs allege that they are entitled to be declared the rightful owners of an undivided interest in minerals and all improvements on the lands on which the Company acquired these leases. The plaintiffs also assert claims for trespass to try title, action to remove a cloud on the title, failure to properly account for royalty, fraud, trespass, conversion, all for unspecified actual and exemplary damages. Plaintiffs claim that

–  11  –

they acquired title to the property by adverse possession. Plaintiffs also assert the discovery rule and a claim of fraudulent concealment to avoid the affirmative defense of limitations. The Company has not had the opportunity to conduct discovery in this matter. The Company estimates that production revenue from this field since its predecessor, Cody Energy, LLC, acquired title and since the Company acquired its lease is approximately $14.8 million, and that the carrying value of this property is approximately $33.8 million.

Although the investigation into this claim continues, the Company intends to vigorously defend the case. Should the Company receive an adverse ruling in this case, an impairment review would be assessed to determine whether the carrying value of the property is recoverable. Management cannot currently determine the likelihood of an unfavorable outcome or range of any potential loss should the outcome be unfavorable. Accordingly, there has been no reserve established for this matter.

Raymondville Area

In April 2004, the Company’s wholly owned subsidiary, Cody Energy, LLC, filed suit in state court in Willacy County, Texas against certain of its co-working interest owners in the Raymondville Area, located in Kenedy and Willacy Counties. In early 2003, Cody proposed a new prospect under the terms of the Joint Operating Agreement. Some of the co-working interest owners elected not to participate. The initial well was successful and subsequent wells have been drilled to exploit the discovery made in the first well.

The working interest owners who elected not to participate notified Cody that they believed that they had the right to participate in wells drilled after the initial well. Cody contends that the working interest owners that elected not to participate are required to assign their interest in the prospect to those who elected to participate. Alternatively, Cody contends that such owners lost their right to participate in subsequent wells within a 1,200 foot radius of the initial well. The defendants have filed a counter claim against the Company and one of the defendants has filed a lien against Cody’s interest in the leases in the Raymondville area.

Cody has signed a settlement agreement with certain of the defendants representing approximately 3% of the interest in the area. Cody and the remaining defendant filed cross motions for summary judgment. The Company is awaiting a ruling by the Court. Trial has been set for mid-November 2005.

The Company is vigorously defending the case. It has a reserve that management believes is adequate based on its estimate of the probable outcome of this case.

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 $13 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 consolidated financial position of the Company. Operating results and cash flow, however, could be significantly impacted in the reporting periods in which such matters are resolved.

–  12  –

8.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. At June 30, 2005, the Company had 14 cash flow hedges open: 5 natural gas price collar arrangements, 2 crude oil price collars and 7 natural gas price swap arrangements. Additionally, the Company had 2 crude oil financial instruments open at June 30, 2005, that did not qualify for hedge accounting. At June 30, 2005, a $31.5 million ($19.5 million net of tax) unrealized loss was recorded to Accumulated Other Comprehensive Income, along with a $42.1 million short term derivative liability, a $0.1 million short term derivative receivable, which is included in other current assets on the balance sheet, and a $0.2 million long term derivative receivable, which is included in other non-current assets on the 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.

	Three Months Ended June 30,
	2005						2004
	Realized			Unrealized			Realized			Unrealized
	(In thousands)
Operating Revenues - Increase/(Decrease) to Revenue
Natural Gas Production	$	(11,266	)	$	782		$	(13,262	)	$	1,306
Crude Oil		(3,328	)		3,049			(3,326	)		(1,959	)
Total	$	(14,594	)	$	3,831		$	(16,588	)	$	(653	)
	Six Months Ended June 30,
	2005						2004
	Realized			Unrealized			Realized			Unrealized
	(In thousands)
Operating Revenues - Increase/(Decrease) to Revenue
Natural Gas Production	$	(17,488	)	$	222		$	(19,930	)	$	(418	)
Crude Oil		(5,909	)		(3,903	)		(5,496	)		(5,854	)
Total	$	(23,397	)	$	(3,681	)	$	(25,426	)	$	(6,272	)

Assuming no change in commodity prices, after June 30, 2005 the Company would reclassify to earnings, over the next 12 months, $19.6 million in after-tax expenditures associated with commodity derivatives. This reclassification represents the net liability associated with open positions currently not reflected in earnings at June 30, 2005 related to remaining anticipated 2005 production.

From time to time, the Company enters into natural gas and crude oil swap arrangements that do not qualify for hedge accounting in accordance with SFAS 133. These financial instruments are recorded at fair value at the balance sheet date. At June 30, 2005, the fair value of the Company’s 2 open crude oil swap arrangements was $9.3 million, and is reported as a component of Derivative Contracts in the liability section of the accompanying Condensed Consolidated Balance Sheet. The change in fair value of these oil swaps, which were an increase of $3.0 million and a decrease of $3.9 million for the three months and six months ended June 30, 2005, respectively, has been reported as a component of Operating Revenues in the accompanying Condensed Consolidated Statement of Operations.

–  13  –

9. COMPREHENSIVE INCOME

Comprehensive Income includes Net Income and certain items recorded directly to Stockholders’ Equity and classified as Accumulated Other Comprehensive Income. The following table illustrates the calculation of Comprehensive Income for the six month periods ended June 30, 2005 and 2004.

	Six Months Ended June 30,
	2005						2004
	(In thousands)
Accumulated Other Comprehensive Loss - Beginning of Period				$	(20,351	)				$	(23,135	)
Net Income	$	56,184					$	38,329
Other Comprehensive Loss
Reclassification Adjustment for Settled Contracts		17,395						22,611
Changes in Fair Value of Hedge Positions		(20,085	)					(51,683	)
Minimum Pension Liability		2,081						—
Foreign Currency Translation Adjustment		(370	)					(11	)
Deferred Income Tax		256						11,094
Total Other Comprehensive Loss	$	(723	)	$	(723	)	$	(17,989	)	$	(17,989	)
Comprehensive Income	$	55,461					$	20,340
Accumulated Other Comprehensive Loss -
End of Period				$	(21,074	)				$	(41,124	)

Deferred income tax of $0.3 million at June 30, 2005 represents the net deferred tax liability of ($6.6) million on the Reclassification Adjustment for Settled Contracts, $7.7 million on the Changes in Fair Value of Hedge Positions, ($0.8) million on the Minimum Pension Liability Adjustment and less than $0.1 million on the Foreign Currency Translation Adjustment.

Deferred income tax of $11.1 million at June 30, 2004 represents the net deferred tax liability of ($8.8) million on the Reclassification Adjustment for Settled Contracts, $19.5 million on the Changes in Fair Value of Hedge Positions and less than $0.4 million on the Foreign Currency Translation Adjustment.

–  14  –

10. ASSET RETIREMENT OBLIGATIONS

The following table reflects the changes of the asset retirement obligations during the six months ended June 30, 2005.

(In thousands)
Carrying amount of asset retirement obligations at December 31, 2004	$	40,375
Liabilities added during the current period		395
Liabilities settled during the current period		(65	)
Current period accretion expense		739
Revisions to estimated cash flows		—
Carrying amount of asset retirement obligations at June 30, 2005	$	41,444

Accretion expense was $0.7 million and $1.1 million for the six months ended June 30, 2005 and 2004, respectively, and is included within Depletion, Depreciation and Amortization expense.

11. PENSION AND OTHER POSTRETIREMENT BENEFITS

The components of net periodic benefit costs for the three months and six months ended June 30, 2005 and 2004 are as follows:

	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2005			2004			2005			2004
Qualified and Non-Qualified Pension Plans	(In thousands)
Current Period Service Cost	$	558		$	504		$	1,116		$	1,007
Interest Accrued on Pension Obligation		495			520			990			1,039
Expected Return on Plan Assets		(355	)		(369	)		(710	)		(737	)
Net Amortization and Deferral		44			41			88			83
Recognized Loss		225			203			450			406
Net Periodic Benefit Costs	$	967		$	899		$	1,934		$	1,798
Postretirement Benefits Other than Pension Plans
Service Cost of Benefits Earned During the Period	$	169		$	71		$	338		$	142
Interest Cost on the Accumulated Postretirement Benefit Obligation		151			93			302			185
Plan Termination Loss		80			—			160			—
Amortization Benefit of the Unrecognized Gain		(20	)		(31	)		(40	)		(61	)
Amortization of Prior Service Cost		227			—			454			—
Amortization Benefit of the Unrecognized Transition Obligation		162			165			324			331
Total Postretirement Benefit Cost	$	769		$	298		$	1,538		$	597

In 2005, the Company does not have any required minimum funding obligations for its qualified pension plan. Currently, management has not determined if a discretionary funding will be made in 2005.

–  15  –

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Stockholders of

Cabot Oil & Gas Corporation:

We have reviewed the accompanying condensed consolidated balance sheet of Cabot Oil & Gas Corporation and its subsidiaries (the Company) as of June 30, 2005, and the related condensed consolidated statement of operations for each of the three and six month periods ended June 30, 2005 and 2004 and the condensed consolidated statement of cash flows for the six month periods ended June 30, 2005 and 2004. 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, 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, 2004 and the related consolidated statements of operations, comprehensive income, stockholders’ equity, and cash flows for the year then ended, management’s assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2004 and the effectiveness of the Company’s internal control over financial reporting as of December 31, 2004; and in our report dated March 2, 2005, which included an explanatory paragraph related to the adoption of Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations, we expressed unqualified opinions thereon. The consolidated financial statements and management’s assessment of the effectiveness of internal control over financial reporting referred to above are not presented herein. In our opinion, the information set forth in the accompanying consolidated balance sheet information as of December 31, 2004, 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

July29, 2005

–  16  –

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

The following review of operations for the three and six month periods ended June 30, 2005 and 2004 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 Form 10-K for the year ended December 31, 2004.

Overview

For the six months ended June 30, 2005, we produced 42.4 Bcfe compared to production of 41.6 Bcfe for the comparable period of the prior year. Natural gas production was 36.8 Bcf and oil production was 927 Mbbls. Natural gas production increased slightly when compared to the comparable period of the prior year, which had production of 35.3 Bcf. The increase in our natural gas production is attributable to successful drilling efforts in our East region, where we had a large 2004 drilling program. In addition, production in the first half of 2005 included the first production from our drilling activity in Canada along with improvement in the West region production profile due to a successful drilling and recompletion program. These increases are partially offset by reduced production in our Gulf Coast region due to the natural decline of gas production in south Louisiana. Oil production decreased by 109 Mbbls from 1,036 Mbbls in the first six months of 2004 to 927 Mbbls produced in the first six months of 2005. The decrease in oil production is primarily the result of the continued natural decline of the CL&F lease in south Louisiana, partially offset by new production of the Breton Sound offshore lease.

Natural gas revenues increased by $35.7 million for the six months ended June 30, 2005 as compared to the six months ended June 30, 2004. This is due to increased realized natural gas prices as well as increased production, primarily in the East and Canada, as discussed above. Oil revenues increased by $9.6 million for the first half of 2005 as compared to the first half of 2004. This increase is primarily due to an increase in oil prices of 38% in the first half of 2005 as compared to the first half of 2004. Additionally, the unrealized loss on crude oil derivatives decreased by $2.0 million in the first half of 2005 from the comparable prior year period. Partially offsetting the increase in prices was the decrease in crude oil production in the first six months of 2005.

During the six months ended June 30, 2005, we drilled 141 gross wells (123 development, 15 exploratory and 3 extension wells) with a success rate of 94% compared to 130 gross wells (118 development and 12 exploratory wells) with a success rate of 98% for the comparable period of the prior year. For the full year, we plan to drill approximately 330 gross wells compared to 256 gross wells in 2004.

On February 28, 2005, we announced that the Board of Directors had declared a 3-for-2 split of the Company’s Common Stock in the form of a stock distribution, distributed on March 31, 2005 to stockholders of record on March 18, 2005. All common stock accounts and per share data have been retroactively adjusted to give effect to the 3-for-2 split of our Common Stock.

We had net income of $56.2 million, or $1.15 per share, for the six months ended June 30, 2005 compared to net income of $38.3 million, or $0.79 per share, for the comparable period of the prior year. The increase in net income is primarily due to increased natural gas and oil production revenues, as discussed above. This increase is partially offset by an increase in total operating expenses of $12.5 million and an increase in income tax expense of $10.1 million in the first half of 2005 as compared to the first half of 2004.

In the first six months of 2005, natural gas prices were higher than the comparable period of the prior year and our financial results reflect their impact. Our realized natural gas price was $5.86 per Mcf, or 14% higher, than the $5.12 per Mcf price realized in the same period of the prior year. These realized prices are impacted by realized losses resulting from commodity derivatives. For information about the impact of these derivatives on realized prices, refer to the “Results of Operations” sections. Commodity prices are determined by 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 demands, overall economic activity, weather, pipeline capacity constraints, storage levels, basis differentials and other factors. As a result, we cannot accurately predict future natural gas, NGLs and crude oil prices, and therefore, cannot accurately predict revenues.

–  17  –

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 2005, we expect to spend approximately $330 million in capital and exploration expenditures, which includes a layer of investment for new projects or property acquisitions that may arise during 2005. This figure has increased by $50 million from $280 million previously reported primarily as a result of recent leasehold acquisitions expected to close in the third quarter of 2005. For the six months ended June 30, 2005, $147.0 million of capital and exploration expenditures have been invested in our exploration and development efforts.

We remain focused on our strategies of balancing our capital investments between acceptable risk and strongest economics, along with balancing longer life investments with impact exploration 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 in the current industry environment and will continue to add shareholder value over the long term.

The preceding paragraphs, discussing our strategic pursuits and goals, contain forward-looking information. See “Forward-Looking Information” on page 29.

Financial Condition

Capital Resources and Liquidity

Our primary source of cash for the six months ended June 30, 2005 was from funds generated from operations and proceeds from the sale of common stock under stock option plans. The Company generates 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 subject to 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 the Annual Report on Form 10-K, have influenced prices throughout the recent years. Working capital is substantially influenced by these variables. Fluctuation 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. Cash flows provided by operating activities were primarily used to fund exploration and development expenditures, pay dividends and purchase treasury stock. During the six months ended June 30, 2005 we purchased 19,700 treasury shares of Cabot stock at a weighted average purchase price of $28.99. See below for additional discussion and analysis of cash flow.

	Six Months Ended June 30,
(In thousands)	2005			2004			Variance
Cash Flows Provided by Operating Activities	$	188,076		$	143,301		$	44,775
Cash Flows Used by Investing Activities		(145,869	)		(128,120	)		(17,749	)
Cash Flows Used by Financing Activities		(287	)		5,524			(5,811	)
Net Increase in Cash and Cash Equivalents	$	41,920		$	20,705		$	21,215

Operating Activities. Net cash provided by operating activities in 2005 increased $44.8 million over 2004. This increase is primarily due to higher commodity prices. Key drivers of net operating cash flows are commodity prices, production volumes and operating costs. Average realized natural gas prices increased 14% over 2004, while crude oil realized prices increased 38% over the same period. Production volumes increased slightly with a 2% rise in equivalent production in 2005 compared to 2004. 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 driver of cash used by investing activities is capital spending and exploration expense. We establish the budget for these amounts based on our current estimate of future commodity prices. Due to the volatility of commodity prices our budget may be periodically adjusted during any given year. Cash flows used in investing activities increased by $17.7 million for the six months ended June 30, 2005, compared to the same period in 2004. The increase from 2004 to 2005 is primarily due to an increase in drilling activity as a result of higher commodity prices. This increase largely occurred in our West region along with an increase in the East region and drilling activity in Canada.

–  18  –

Financing Activities. Cash flows used by financing activities were $0.3 million for the six months ended June 30, 2005 and cash flows provided by financing activities were $5.5 million for the six months ended June 30, 2004. Cash flows used by financing activities in the first half of 2005 were the result of dividend payments and the purchases of treasury stock, partially offset by proceeds from the exercise of stock options.

The available credit line under our revolving Credit Facility, which was $250 million at June 30, 2005, can be expanded up to $350 million. It 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. At June 30, 2005, we had no outstanding balance on the Credit Facility. 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.

On August 13, 1998, we announced that our Board of Directors authorized the repurchase of two million shares of our Common Stock in the open market or in negotiated transactions. Subsequent to this announcement, there was a 3-for-2 split of the Company’s Common Stock. As a result of this stock split, this figure has been adjusted to three million shares. During the first six months of 2005, we repurchased 19,700 shares of our Common Stock. All purchases executed to date have been through open market transactions. There is no expiration date associated with the authorization to repurchase our securities. The approximate number of shares that may yet be purchased under the plan is 1,918,750. See “Issuer Purchases of Equity Securities” in Item 2 “Unregistered Sales of Equity Securities and Use of Proceeds” for additional information.

Capitalization

Our capitalization information is as follows:

	June 30, 2005			December 31, 2004
	(In millions)
Debt(1)	$	270.0		$	270.0
Stockholders’ Equity(2) (3)		515.8			455.7
Total Capitalization	$	785.8		$	725.7
Debt to Capitalization(3)		34	%		37	%
Cash and Cash Equivalents	$	51.9		$	10.0

⁽¹⁾ Includes $20.0 million of current portion of long-term debt.

⁽²⁾ Includes common stock, net of treasury stock.

⁽³⁾ Includes the impact of the Accumulated Other Comprehensive Loss at June 30, 2005 and December 31, 2004 of $21.1 millionand $20.4 million, respectively.

During the six months ended June 30, 2005, we paid dividends of $3.3 million on our Common Stock. A regular dividend of $0.04 per share of Common Stock has been declared for each quarter since we became a public company in 1990. We expect to pay additional incremental dividends of approximately $2.0 million in 2005 as a result of the 3-for-2 stock split.

–  19  –

Capital and Exploration Expenditures

On an annual basis, we generally fund most of our capital and exploration activities, excluding major 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:

	Six Months Ended June 30,
	2005		2004
	(In millions)
Capital Expenditures
Drilling and Facilities	$	99.4	$	87.3
Leasehold Acquisitions		8.0		9.5
Pipeline and Gathering		7.3		6.8
Other		0.7		1.0
		115.4		104.6
Proved Property Acquisitions		0.9		1.4
Exploration Expense		30.7		25.7
Total	$	147.0	$	131.7

We plan to drill approximately 330 gross wells in 2005. This drilling program includes approximately $330 million in total capital and exploration expenditures. See the “Overview” discussion for additional information regarding the current year drilling program. We will continue to assess the natural gas price environment and may increase or decrease the capital and exploration expenditures accordingly.

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. There have been no changes to our critical accounting policies from those described in the 2004 Form 10-K. See the Company’s Annual Report on Form 10-K for the year ended December 31, 2004, for further discussion.

Results of Operations

Second Quarters of 2005 and 2004 Compared

We reported Net Income in the second quarter of 2005 of $35.4 million, or $0.72 per share. During the corresponding quarter of 2004, we reported Net Income of $19.3 million, or $0.40 per share. Operating Income increased $25.3 million compared to the prior year, from $36.4 million in the second quarter of 2004 to $61.7 million in the second quarter of 2005. The increase in current year Operating Income was substantially due to an increase in natural gas and oil production revenues partially offset by an increase in total Operating Expenses. Net Income increased in the current quarter by $16.1 million due to an increase in Operating Income partially offset by an increase of $9.5 million in Income Tax Expense.

–  20  –

Natural Gas Production Revenues

Our average total company realized natural gas production sales price, including the realized impact of derivative instruments, was $6.02 per Mcf for the three months ended June 30, 2005 compared to $5.02 per Mcf for the comparable period of the prior year. These prices include the realized impact of derivative instruments which reduced these prices by $0.61 per Mcf in 2005 and $0.75 per Mcf in 2004. The following table excludes the unrealized gain from the change in derivative fair value of $0.8 million and $1.3 million for the three months ended June 30, 2005 and 2004, respectively. These unrealized changes in fair value have been included in the Natural Gas Production Revenues line item in the Statement of Operations.

	Three Months Ended June 30,					Variance
	2005			2004		Amount			Percent
Natural Gas Production(Mmcf)
Gulf Coast		7,353			7,600		(247	)	(3	)%
West		5,690			5,216		474		9	%
East		5,083			4,841		242		5	%
Canada		332			—		332		—
Total Company		18,458			17,657		801		5	%
Natural Gas Production Sales Price($/Mcf)
Gulf Coast	$	6.14		$	5.12	$	1.02		20	%
West	$	5.47		$	4.64	$	0.83		18	%
East	$	6.54		$	5.29	$	1.25		24	%
Canada	$	4.53		$	—	$	4.53		—
Total Company	$	6.02		$	5.02	$	1.00		20	%
Natural Gas Production Revenue(in thousands)
Gulf Coast	$	45,178		$	38,889	$	6,289		16	%
West		31,108			24,208		6,900		29	%
East		33,241			25,625		7,616		30	%
Canada		1,508			—		1,508		—
Total Company	$	111,035		$	88,722	$	22,313		25	%
(in thousands)
Price Variance Impact on Natural Gas Production Revenue
Gulf Coast	$	7,552
West		4,664
East		6,470
Canada		—
Total Company	$	18,686
(in thousands)
Volume Variance Impact on Natural Gas Production Revenue
Gulf Coast	$	(1,263	)
West		2,236
East		1,146
Canada		1,508
Total Company	$	3,627

The increase in Natural Gas Production Revenue is due substantially to the increase in natural gas sales prices. In addition, the increase in production was due to the successful drilling and recompletion program in the West coupled with the 2004 successful drilling efforts in the East. The commencement of Canada natural gas production late in 2004 also contributed to the increase. The increase in the realized natural gas price combined with the increase in production resulted in a net revenue increase of $22.3 million, excluding the unrealized impact of derivative instruments.

–  21  –

Brokered Natural Gas Revenue and Cost

	Three Months Ended June 30,					Variance
	2005			2004		Amount			Percent
Sales Price($/Mcf)	$	7.60		$	7.19	$	0.41		6	%
Volume Brokered(Mmcf)		2,041			2,173		(132	)	(6	)%
Brokered Natural Gas Revenues(in thousands)	$	15,520		$	15,628
Purchase Price($/Mcf)	$	6.71		$	6.26	$	0.45		7	%
Volume Brokered(Mmcf)		2,041			2,173		(132	)	(6	)%
Brokered Natural Gas Cost(in thousands)	$	13,701		$	13,596
Brokered Natural Gas Margin(in thousands)	$	1,819		$	2,032	$	(213	)	(10	)%
(in thousands)
Sales Price Variance Impact on Revenue	$	1,189
Volume Variance Impact on Revenue		(1,297	)
	$	(108	)
(in thousands)
Purchase Price Variance Impact on Purchases	$	(1,300	)
Volume Variance Impact on Purchases		1,195
	$	(105	)

The decrease in brokered natural gas revenues of $0.1 million combined with the increase in brokered natural gas cost of $0.1 million resulted in a decrease to the brokered natural gas margin of $0.2 million.

–  22  –

Crude Oil and Condensate Revenues

Our average total company realized Crude Oil Sales Price, including the realized impact of derivative instruments, was $43.76 per Bbl for the second quarter of 2005 and $31.10 per Bbl for the comparable period of the prior year. These prices include the realized impact of derivative instruments which reduced these prices by $6.98 per Bbl in 2005 and $6.67 per Bbl in 2004. The following table excludes the unrealized gain from the change in derivative fair value of $3.0 million and the unrealized loss from the change in derivative fair value of $2.0 million for the three months ended June 30, 2005 and 2004, respectively. These unrealized changes in fair value have been included in the Crude Oil and Condensate Revenues line item in the Statement of Operations.

	Three Months Ended June 30,					Variance
	2005			2004		Amount			Percent
Crude Oil Production(Mbbl)
Gulf Coast		421			450		(29	)	(6	)%
West		43			42		1		2	%
East		8			7		1		14	%
Canada		5			—		5		—
Total Company		477			499		(22	)	(4	)%
Crude Oil Sales Price ($/Bbl)
Gulf Coast	$	42.86		$	30.43	$	12.43		41	%
West	$	52.27		$	37.37	$	14.90		40	%
East	$	50.32		$	36.41	$	13.91		38	%
Canada	$	35.43		$	—	$	35.43		—
Total Company	$	43.76		$	31.10	$	12.66		41	%
Crude Oil Revenue (in thousands)
Gulf Coast	$	18,045		$	13,686	$	4,359		32	%
West		2,284			1,574		710		45	%
East		373			251		122		49	%
Canada		185			—		185		—
Total Company	$	20,887		$	15,511	$	5,376		35	%
(in thousands)
Price Variance Impact on Crude Oil Revenue
Gulf Coast	$	5,196
West		731
East		41
Canada		—
Total Company	$	5,968
(in thousands)
Volume Variance Impact on Crude Oil Revenue
Gulf Coast	$	(837	)
West		(21	)
East		81
Canada		185
Total Company	$	(592	)

The decrease in oil production is primarily the result of the continued natural decline of the CL&F lease in south Louisiana, partially offset by new production of the Breton Sound offshore lease. The increase in the realized crude oil price combined with the decline in production resulted in a net revenue increase of $5.4 million, excluding the unrealized impact of derivative instruments.

–  23  –

Other Operating Revenues

Other operating revenues remained fairly consistent between the second quarter of 2005 and the second quarter of 2004, with a $0.1 million increase between the two periods.

Operating Expenses

Total costs and expenses from operations increased $7.1 million in the second quarter of 2005 compared to the same quarter of 2004. The primary reasons for this fluctuation are as follows:

• Taxes Other Than Income expense increased by $2.5 million, or 25%, from the second quarter of 2004 compared to the second quarter of 2005, primarily due to increased production taxes as a result of increased commodity prices.

• Exploration expense increased by $1.8 million in the second quarter of 2005, primarily as a result of increased dry hole expense, partially offset by decreased spending related to administrative and contract services. During the second quarter of 2005, we incurred $2.4 million more dry hole expense, mainly as a result of an increase in the Gulf Coast, compared to the second quarter of 2004.

• Direct Operations expense increased by $1.2 million over the second quarter of 2004. This is primarily the result of an increase over the prior year quarter in employee related expenses as well as increased maintenance and workover expenses and expenses for outside operated properties.

• Depreciation, Depletion and Amortization increased by $1.5 million in the second quarter of 2005. This is primarily due to an increase in offshore DD&A rates associated with the commencement of offshore production in late 2004 and increased production period over period.

• Impairment of Unproved Properties increased by $0.9 million over the comparable six months of 2004. This is due to increased amortization related to unproved property additions both onshore and offshore.

• General and Administrative expense decreased by $0.9 million in the second quarter of 2005. This decrease is primarily due to decreased stock compensation costs of $1.1 million, mainly related to performance shares, since our ranking in our peer group dropped in the second quarter, causing a reduction to expense. Partially offsetting this decrease was an increase in professional services, primarily legal services.

Interest Expense

Interest expense decreased $0.5 million in the second quarter of 2005. This decrease is mainly a result of increased interest income on our short term investments. In addition, no borrowings were made on the Credit Facility during the second quarter of 2005.

Income Tax Expense

Income tax expense increased by $9.5 million due to a comparable increase in our pre-tax income.

Six Months of 2005 and 2004 Compared

We reported Net Income in the first half of 2005 of $56.2 million, or $1.15 per share. During the corresponding period of 2004, we reported Net Income of $38.3 million, or $0.79 per share. Operating Income increased by $27.2 million in the first half of 2005 compared to the prior year. The increase in current year Operating Income was substantially due to an increase in natural gas and oil production revenues partially offset by an increase in total Operating Expenses. Net Income increased in the first six months of 2005 by $17.9 million due to an increase in Operating Income partially offset by an increase of $10.1 million in Income Tax Expense.

–  24  –

Natural Gas Production Revenues

Our average total company realized natural gas production sales price, including the realized impact of derivative instruments, was $5.86 per Mcf for the six months ended June 30, 2005 compared to $5.12 per Mcf for the comparable period of the prior year. These prices include the realized impact of derivative instruments which reduced these prices by $0.47 per Mcf in 2005 and $0.56 per Mcf in 2004. The following table excludes the unrealized gain from the change in derivative fair value of $0.2 million and the unrealized loss from the change in derivative fair value of $0.4 million for the six months ended June 30, 2005 and 2004, respectively. These unrealized changes in fair value have been included in the Natural Gas Production Revenues line item in the Statement of Operations.

	Six Months Ended June 30,					Variance
	2005			2004		Amount			Percent
Natural Gas Production(Mmcf)
Gulf Coast		14,674			15,275		(601	)	(4	)%
West		11,375			10,782		593		5	%
East		10,216			9,280		936		10	%
Canada		554			—		554		—
Total Company		36,819			35,337		1,482		4	%
Natural Gas Production Sales Price($/Mcf)
Gulf Coast	$	6.09		$	5.13	$	0.96		19	%
West	$	5.10		$	4.74	$	0.36		8	%
East	$	6.44		$	5.53	$	0.91		16	%
Canada	$	4.95		$	—	$	4.95		—
Total Company	$	5.86		$	5.12	$	0.74		14	%
Natural Gas Production Revenue(in thousands)
Gulf Coast	$	89,295		$	78,355	$	10,940		14	%
West		58,000			51,121		6,879		13	%
East		65,829			51,349		14,480		28	%
Canada		2,743			—		2,743		—
Total Company	$	215,867		$	180,825	$	35,042		19	%
(in thousands)
Price Variance Impact on Natural Gas Production Revenue
Gulf Coast	$	14,023
West		4,068
East		9,303
Canada		—
Total Company	$	27,394
(in thousands)
Volume Variance Impact on Natural Gas Production Revenue
Gulf Coast	$	(3,083	)
West		2,811
East		5,177
Canada		2,743
Total Company	$	7,648

The increase in Natural Gas Production Revenue is due substantially to the increase in natural gas sales prices. In addition, the increase in production was due to the successful drilling and recompletion program in the West coupled with the 2004 successful drilling efforts in the East. The commencement of Canada natural gas production late in 2004 also contributed to the increase. The increase in the realized natural gas price combined with the increase in production resulted in a net revenue increase of $35.0 million, excluding the unrealized impact of derivative instruments.

–  25  –

Brokered Natural Gas Revenue and Cost

	Six Months Ended June 30,					Variance
	2005			2004		Amount			Percent
Sales Price($/Mcf)	$	7.27		$	8.35	$	(1.08	)	(13	)%
Volume Brokered(Mmcf)		5,779			5,655		124		2	%
Brokered Natural Gas Revenues(in thousands)	$	42,012		$	47,187
Purchase Price($/Mcf)	$	6.40		$	7.48	$	(1.08	)	(14	)%
Volume Brokered(Mmcf)		5,779			5,655		124		2	%
Brokered Natural Gas Cost(in thousands)	$	36,999		$	42,317
Brokered Natural Gas Margin(in thousands)	$	5,013		$	4,870	$	143		3	%
(in thousands)
Sales Price Variance Impact on Revenue	$	(6,210	)
Volume Variance Impact on Revenue		1,035
	$	(5,175	)
(in thousands)
Purchase Price Variance Impact on Purchases	$	6,246
Volume Variance Impact on Purchases		(928	)
	$	5,318

The decrease in brokered natural gas revenues of $5.2 million combined with the decline in brokered natural gas cost of $5.3 million resulted in an increase to the brokered natural gas margin of $0.1 million.

–  26  –

Crude Oil and Condensate Revenues

Our average total company realized Crude Oil Sales Price, including the realized impact of derivative instruments, was $42.96 per Bbl for first half of 2005 and $31.04 per Bbl for the comparable period of the prior year. These prices include the realized impact of derivative instruments which reduced these prices by $6.37 per Bbl in 2005 and $5.31 per Bbl in 2004. The following table excludes the unrealized loss from the change in derivative fair value of $3.9 million and $5.9 million for the six months ended June 30, 2005 and 2004, respectively. These unrealized changes in fair value have been included in the Crude Oil and Condensate Revenues line item in the Statement of Operations.

	Six Months Ended June 30,					Variance
	2005			2004		Amount			Percent
Crude Oil Production(Mbbl)
Gulf Coast		826			940		(114	)	(12	)%
West		79			83		(4	)	(5	)%
East		13			13		0		0	%
Canada		9			—		9		—
Total Company		927			1,036		(109	)	(10	)%
Crude Oil Sales Price($/Bbl)
Gulf Coast	$	42.19		$	30.57	$	11.62		38	%
West	$	50.61		$	35.89	$	14.72		41	%
East	$	49.37		$	34.17	$	15.20		44	%
Canada	$	36.83		$	—	$	36.83		—
Total Company	$	42.96		$	31.04	$	11.92		38	%
Crude Oil Revenue(in thousands)
Gulf Coast	$	34,833		$	28,745	$	6,088		21	%
West		4,010			2,964		1,046		35	%
East		634			464		170		37	%
Canada		340			—		340		—
Total Company	$	39,817		$	32,173	$	7,644		24	%
(in thousands)
Price Variance Impact on Crude Oil Revenue
Gulf Coast	$	9,565
West		1,202
East		162
Canada		—
Total Company	$	10,929
(in thousands)
Volume Variance Impact on Crude Oil Revenue
Gulf Coast	$	(3,477	)
West		(157	)
East		9
Canada		340
Total Company	$	(3,285	)

The decrease in oil production is primarily the result of the continued natural decline of the CL&F lease in south Louisiana, partially offset by new production of the Breton Sound offshore lease. The increase in the realized crude oil price combined with the decline in production resulted in a net revenue increase of $7.6 million, excluding the unrealized impact of derivative instruments.

–  27  –

Other Operating Revenues

Other operating revenues decreased $0.5 million from the first half of 2004 to the first half of 2005. This change was primarily a result of an increase in our payout liability accrual which correspondingly decreased other revenues. Also, this variance results, to a lesser extent, from changes in our wellhead gas imbalances over the prior year period.

Operating Expenses

Total costs and expenses from operations increased $12.5 million in the first half of 2005 compared to the comparable period of 2004. The primary reasons for this fluctuation are as follows:

• Brokered Natural Gas Cost declined in the amount of $5.3 million in the first half of 2005. See the Brokered Natural Gas Revenue and Cost analysis for additional discussion.

• Exploration expense increased $5.0 million in 2005, primarily as a result of increased dry hole expense partially offset by decreased spending on geological and geophysical expenses. During the first half of 2005, we spent $6.4 million less on geological and geophysical activities and incurred an additional $11.1 million in dry hole expense. The increase in dry hole expense is mainly due to expenses incurred in Canada for two dry holes as well as four dry holes in the Gulf Coast.

• Depreciation, Depletion and Amortization increased by $3.9 million in the first half of 2005. This is primarily due to an increase in offshore DD&A rates associated with the commencement of offshore production in late 2004 and increased production period over period.

• Direct Operations expense increased by $3.7 million over the first six months of 2004. This is primarily the result of increased workover expenses and expenses for outside operated properties. In addition, there was an increase over the prior year in employee related expenses.

• Impairment of Unproved Properties increased $1.7 million over the comparable quarter of 2004. This is due to increased amortization related to unproved property additions both onshore and offshore.

• General and Administrative expense increased by $1.4 million in the first half of 2005. This increase is primarily due to increased legal expenses in the first half of 2005 over the first half of 2004 as well as increased employee related expenses. Partially offsetting this increase are decreased stock compensation costs mainly related to performance shares, since our ranking dropped as compared to our peer group in the second quarter of 2005.

Interest Expense

Interest expense decreased $0.9 million in the first half of 2005. This variance is mainly a result of increased income on our short term investments. In addition, interest expense on the revolver was lower than in the prior year period due to the fact that there were no borrowings in the first half of 2005 on our Credit Facility. In addition, commitment fee expenses declined from the first half of 2004 due to the amendment of our Credit Facility in December 2004.

Income Tax Expense

Income tax expense increased $10.1 million due to a comparable increase in our pre-tax income.

Recently Issued Accounting Pronouncements

In May 2005, the Financial Accounting Standard Board (FASB) issued Statement of Financial Accounting Standards (SFAS) No. 154, “Accounting Changes and Error Corrections-a replacement of APB Opinion No. 20 and FASB Statement No. 3.” In order to enhance financial reporting consistency between periods, SFAS 154 modifies the requirements for the accounting and reporting of the direct effects of changes in accounting principles. Under APB Opinion 20, the cumulative effect of voluntary changes in accounting principle was recognized in Net Income in the period of the change. Unlike the treatment previously prescribed by APB Opinion 20, retrospective application is now required, unless it is not practical to determine the specific effects in each period or the cumulative effect. If the period specific effects cannot be determined, it is required that the new accounting principle must be retrospectively

–  28  –

applied in the earliest period possible to the balance sheet accounts and a corresponding adjustment be made to the opening balance of retained earnings or another equity account. If the cumulative effect cannot be determined, it is necessary to apply the new accounting principles prospectively at the earliest practical date. If it is not feasible to retrospectively apply the change in principle, the reason that this is not possible and the method used to report the change is required to be disclosed. The statement also provides that changes in accounting for depreciation, depletion or amortization should be treated as changes in accounting estimate inseparable from a change in accounting principle and that disclosure of the preferability of the change is required. SFAS 154 is effective for accounting changes made in fiscal years beginning after December 15, 2005.

In December 2004, the FASB issued Statement SFAS No. 123R, “Share-Based Payment.” SFAS 123R revises SFAS 123, “Accounting for Stock-Based Compensation,” and focuses on accounting for share-based payments for services provided by employee to employer. The statement requires companies to expense the fair value of employee stock options and other equity-based compensation at the grant date. The statement does not require a certain type of valuation model, and either a binomial or Black-Scholes model may be used. During the first quarter of 2005, the Securities and Exchange Commission (SEC) approved a new rule for public companies to delay the adoption of this standard. In April 2005, the SEC took further action to amend Regulation S-X to state that the provisions of SFAS 123R are now effective beginning with the first annual or interim reporting period of the registrant’s first fiscal year beginning on or after June 15, 2005 for all non-small business issuers. As a result, we will not adopt this SFAS until the first quarter of 2006. We are currently evaluating the method of adoption and the impact on our operating results. Our future cash flows will not be impacted by the adoption of this standard. See “Stock Based Compensation” below for further information.

In March 2005, the FASB issued FASB Interpretation (FIN) No. 47, “Accounting for Conditional Asset Retirement Obligations.” This Interpretation clarifies the definition and treatment of conditional asset retirement obligations as discussed in FASB Statement No. 143, “Accounting for Asset Retirement Obligations.” A conditional asset retirement obligation is defined as an asset retirement activity in which the timing and/or method of settlement are dependent on future events that may be outside the control of the Company. FIN 47 states that a Company must record a liability when incurred for conditional asset retirement obligations if the fair value of the obligation is reasonably estimable. This Interpretation is intended to provide more information about long-lived assets, more information about future cash outflows for these obligations and more consistent recognition of these liabilities. FIN 47 is effective for fiscal years ending after December 15, 2005. We do not believe that our financial position, results of operations or cash flows will be impacted by this Interpretation.

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.

–  29  –

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. Further, if our counterparties defaulted, we might not receive the benefits of the hedges in the event prices decline. Please read the discussion below related to commodity price swaps and Note 8 of the Notes to the Interim 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 derivatives are not held for trading purposes. Under these price swaps, we receive a fixed price on a notional quantity of natural gas and crude oil in exchange for paying a variable price based on a market-based index, such as the NYMEX gas and crude oil futures. Under our Revolving Credit Agreement, which had no borrowings outstanding at June 30, 2005, 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. During the first six months of 2005, natural gas price swaps covered 10,194 Mmcf, or 28%, of our gas production, fixing the sales price of this gas at an average of $5.14 per Mcf.

At June 30, 2005, we had open natural gas price swap contracts covering our 2005 production as follows:

	Natural Gas Price Swaps
Contract Period	Volume in Mmcf	Weighted Average Contract Price		Unrealized Loss (In thousands)
As of June 30, 2005
Natural Gas Price Swaps on Production in:
Third Quarter 2005	5,181	$	5.14
Fourth Quarter 2005	5,181		5.14
Six Months Ended December 31, 2005	10,362	$	5.14	$	(25,566	)

From time to time, we enter into natural gas and crude oil swap arrangements that do not qualify for hedge accounting in accordance with SFAS 133. These financial instruments are recorded at fair value at the balance sheet date. At June 30, 2005, the fair value of our two open crude oil swap arrangements was $9.3 million, and is reported as a component of Derivative Contracts in the liability section of the accompanying Condensed Consolidated Balance Sheet. The change in fair value of these oil swaps which were an increase of $3.0 million and a decrease of $3.9 million for the three months and six months ended June 30, 2005, respectively, has been reported as a component of Operating Revenues in the accompanying Condensed Consolidated Statement of Operations.

–  30  –

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 falls below the floor price, the counterparty pays us. During the first six months of 2005, natural gas price collars covered 8,349 Mmcf, or 23%, of our gas production, with a weighted average floor of $5.82 per Mcf and a weighted average ceiling of $8.81 per Mcf.

At June 30, 2005, we had open natural gas price collar contracts covering our 2005 production as follows:

	Natural Gas Price Collars
Contract Period	Volume in Mmcf	Weighted Average Ceiling /Floor		Unrealized Loss (In thousands)
As of June 30, 2005
Third Quarter 2005	3,404	$	8.38 /$5.30
Fourth Quarter 2005	3,404		8.38 / 5.30
Six Months Ended December 31, 2005	6,808	$	8.38 /$5.30	$	(5,434	)

At June 30, 2005, we had two open crude oil price collar contracts covering our 2005 and 2006 production as follows:

	Crude Oil Price Collar
Contract Period	Volume in Mbbl	Weighted Average Ceiling /Floor		Unrealized Gain /(Loss) (In thousands)
As of June 30, 2005
Third Quarter 2005	92	$	50.50 /$40.00
Fourth Quarter 2005	92		50.50 / 40.00
Six Months Ended December 31, 2005	184	$	50.50 /$40.00	$	(1,773	)
First Quarter 2006	90	$	76.00 /$50.00
Second Quarter 2006	91		76.00 / 50.00
Third Quarter 2006	92		76.00 / 50.00
Fourth Quarter 2006	92		76.00 / 50.00
Full Year 2006	365	$	76.00 /$50.00	$	284

We are exposed to market risk on these open contracts, to the extent of changes in market prices of natural gas and 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” on page 29.

–  31  –

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 Rule 13a-15 of 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 have been no significant changes in the Company’s internal controls or in other factors that could significantly affect internal controls subsequent to the date the Company carried out its evaluation.

PART II. OTHER INFORMATION

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

Issuer Purchases of Equity Securities

Period	Total Number of Shares Purchased	Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Approximate Number of Shares that May Yet Be Purchased Under the Plans or Programs
April 2005	—	$	—	—	1,938,450
May 2005	19,700	$	28.99	19,700	1,918,750
June 2005	—	$	—	—	1,918,750
Total	19,700	$	28.99

On August 13, 1998, the Company announced that its Board of Directors authorized the repurchase of two million shares of the Company’s Common Stock in the open market or in negotiated transactions. Subsequent to this announcement, on February 28, 2005, the Company announced that the Board of Directors had declared a 3-for-2 split of the Company’s Common Stock. As a result of this stock split, this figure has been adjusted to three million shares. All purchases executed have been through open market transactions. There is no expiration date associated with the authorization to repurchase securities of the Company.

The 3-for-2 split of the Company’s Common Stock was consummated in the form of a stock distribution. The stock dividend was distributed on March 31, 2005 to stockholders of record on March 18, 2005. In lieu of issuing fractional shares, the Company paid cash based on the closing price of the Common Stock on the record date. As a result of the stock split, each share of common stock continues to include one right under the Company’s Preferred Stock Purchase Rights Plan, and each right now provides for the purchase, upon the occurrence of the conditions set forth in the plan and disclosed in the Company’s 2004 Annual Report on Form 10-K, of two-thirds of one one-hundredth of a share of preferred stock at a purchase price of approximately $36.67 per two-thirds of one one-hundredth of a share. All common stock accounts and per share data have been retroactively adjusted to give effect to the 3-for-2 split of the Company’s Common Stock.

–  32  –

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

On April 28, 2005, the Company held its Annual Meeting of Stockholders. At this meeting, the Company’s stockholders voted on the following matters:

• the election of three directors, and

• the ratification of the appointment of PricewaterhouseCoopers LLP, as the independent registered public accounting firm for the Company for its 2005 fiscal year.

Of the 32,601,884 shares entitled to vote, 30,333,478 were voted.

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

Dan O. Dinges
For:	27,705,676
Withheld:	2,627,802
C. Wayne Nance
For:	27,714,140
Withheld:	2,619,338
William P. Vititoe
For:	27,721,259
Withheld:	2,612,219

The terms of office of directors, Robert F. Bailey, John G.L. Cabot, James G. Floyd, Robert Kelley and P. Dexter Peacock continued beyond the meeting date.

Shareholders voted to ratify the appointment of PricewaterhouseCoopers LLP, as the independent registered public accounting firm for the Company for its 2005 fiscal year by the following vote:

For	30,138,658
Against	191,079
Abstain	3,741

–  33  –

ITEM 6. Exhibits

14.1- Amendment of Code of Business Conduct (as amended on July 28, 2005 to revise Section III. F. relating to Transactions in Securities and Article V. relating to Safety, Health and the Environment)

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

–  34  –

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)
July29, 2005	By:	/s/ Dan O. Dinges
		Dan O. Dinges
		Chairman, President and
		Chief Executive Officer
		(Principal Executive Officer)
July29, 2005	By:	/s/ Scott C. Schroeder
		Scott C. Schroeder
		Vice President and Chief Financial Officer
		(Principal Financial Officer)
July29, 2005	By:	/s/ Henry C. Smyth
		Henry C. Smyth
		Vice President, Controller and Treasurer
		(Principal Accounting Officer)

–  35  –