CABOT OIL & GAS CORP - 10-Q Quarterly Report

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, 2004

¨	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 August 5, 2004, there were 33,047,521 shares of Common Stock, Par Value $.10 Per Share, outstanding.

CABOT OIL & GAS CORPORATION

INDEX TO FINANCIAL STATEMENTS


		Page
Part I. Financial Information

Item 1. Financial Statements

Condensed Consolidated Statement of Operations for the Three-Months and Six-Months Ended June 30, 2004 and 2003		3

Condensed Consolidated Balance Sheet at June 30, 2004 and December 31, 2003		4

Condensed Consolidated Statement of Cash Flows for the Six-Months Ended June 30, 2004 and 2003		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		32

Item 4. Controls and Procedures		33

Part II. Other Information

Item 2. Changes in Securities, Use of Proceeds and Issuer Purchases of Equity Securities		34

Item 4. Submission of Matters to a Vote of Security Holders		35

Item 6. Exhibits and Reports on Form 8-K		36

Signatures		37

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,
	2004			2003		2004			2003
NET OPERATING REVENUES
Natural Gas Production	$	90,028		$	80,576	$	180,407		$	158,287
Brokered Natural Gas		15,628			23,370		47,187			55,220
Crude Oil and Condensate		13,552			20,550		26,319			43,642
Other		534			2,260		2,433			5,523

		119,742			126,756		256,346			262,672
OPERATING EXPENSES
Brokered Natural Gas Cost		13,596			21,539		42,317			49,800
Direct Operations - Field and Pipeline		13,114			13,825		25,192			24,751
Exploration		9,568			15,663		25,712			29,054
Depreciation, Depletion and Amortization		24,622			23,764		48,851			47,271
Impairment of Unproved Properties		2,728			2,337		5,311			4,674
Impairment of Long-Lived Assets (Note 2)		—			—		—			87,926
General and Administrative		9,582			6,172		16,298			12,767
Taxes Other Than Income		9,921			8,651		20,023			18,875

		83,131			91,951		183,704			275,118
Gain (Loss) on Sale of Assets		(172	)		45		(113	)		605

INCOME (LOSS) FROM OPERATIONS		36,439			34,850		72,529			(11,841	)
Interest Expense and Other		5,445			5,952		10,822			11,577

Income (Loss) Before Income Taxes and Cumulative Effect of Accounting Change		30,994			28,898		61,707			(23,418	)
Income Tax Expense (Benefit)		11,676			10,994		23,378			(8,946	)

NET INCOME (LOSS) BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE		19,318			17,904		38,329			(14,472	)
CUMULATIVE EFFECT OF ACCOUNTING CHANGE (Note 9)		—			—		—			(6,847	)

NET INCOME (LOSS)	$	19,318		$	17,904	$	38,329		$	(21,319	)

Basic Earnings (Loss) Per Share - Before Accounting Change	$	0.59		$	0.56	$	1.18		$	(0.45	)
Diluted Earnings (Loss) Per Share - Before Accounting Change	$	0.59		$	0.55	$	1.17		$	(0.45	)
Basic Earnings (Loss) Per Share - Accounting Change	$	—		$	—	$	—		$	(0.22	)
Diluted Earnings (Loss) Per Share - Accounting Change	$	—		$	—	$	—		$	(0.22	)
Basic Earnings (Loss) Per Share	$	0.59		$	0.56	$	1.18		$	(0.67	)
Diluted Earnings (Loss) Per Share	$	0.59		$	0.55	$	1.17		$	(0.67	)

Average Common Shares Outstanding		32,526			31,980		32,462			31,909
Diluted Common Shares (Note 5)		32,929			32,477		32,862			31,909

The accompanying notes are an intergral 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, 2004			December 31, 2003
ASSETS
Current Assets
Cash and Cash Equivalents	$	21,429		$	724
Accounts Receivable		89,495			87,425
Inventories		9,519			18,241
Deferred Income Taxes		30,709			21,935
Other		16,023			15,006

Total Current Assets		167,175			143,331
Properties and Equipment, Net (Successful Efforts Method)		949,310			895,955
Deferred Income Taxes		14,266			8,920
Other Assets		6,672			6,850

	$	1,137,423		$	1,055,056

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Accounts Payable	$	93,863		$	84,943
Accrued Liabilities		92,746			71,584

Total Current Liabilities		186,609			156,527
Long-Term Debt		270,000			270,000
Deferred Income Taxes		219,229			208,955
Other Liabilities		69,566			54,377
Commitments and Contingencies (Note 6)
Stockholders’ Equity
Common Stock:
Authorized – 80,000,000 Shares of $.10 Par Value Issued and Outstanding – 33,022,845 Shares and 32,538,255 Shares in 2004 and 2003, Respectively		3,303			3,254
Additional Paid-in Capital		376,076			361,699
Retained Earnings		63,490			27,763
Accumulated Other Comprehensive Loss		(41,124	)		(23,135	)
Less Treasury Stock, at Cost:
460,700 and 302,600 Shares in 2004 and 2003, Respectively		(9,726	)		(4,384	)

Total Stockholders’ Equity		392,019			365,197

	$	1,137,423		$	1,055,056

The accompanying notes are an integral part of these 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,
	2004			2003
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income (Loss)	$	38,329		$	(21,319	)
Adjustments to Reconcile Net Income (Loss) to Cash Provided by Operating Activities:
Cumulative Effect of Accounting Change		—			6,847
Depletion, Depreciation and Amortization		48,851			47,271
Impairment of Unproved Properties		5,311			4,674
Impairment of Long-Lived Assets		—			87,926
Deferred Income Taxes		7,181			(25,248	)
(Gain) Loss on Sale of Assets		113			(605	)
Exploration Expense		25,712			29,054
Change in Derivative Fair Value		6,272			1,194
Other		721			333
Changes in Assets and Liabilities:
Accounts Receivable		(2,070	)		(15,130	)
Inventories		8,722			5,292
Other Current Assets		(1,017	)		(5,612	)
Other Assets		178			214
Accounts Payable and Accrued Liabilities		3,573			25,110
Other Liabilities		1,425			(197	)

Net Cash Provided by Operating Activities		143,301			139,804

CASH FLOWS FROM INVESTING ACTIVITIES
Capital Expenditures		(102,430	)		(51,399	)
Proceeds from Sale of Assets		22			2,360
Exploration Expense		(25,712	)		(29,054	)

Net Cash Used by Investing Activities		(128,120	)		(78,093	)

CASH FLOWS FROM FINANCING ACTIVITIES
Increase in Debt		28,000			131,000
Decrease in Debt		(28,000	)		(192,000	)
Sale of Common Stock Proceeds		13,468			2,458
Purchase of Treasury Stock		(5,342	)		—
Dividends Paid		(2,602	)		(2,468	)

Net Cash Provided (Used) by Financing Activities		5,524			(61,010	)

Net Increase in Cash and Cash Equivalents		20,705			701
Cash and Cash Equivalents, Beginning of Period		724			2,561

Cash and Cash Equivalents, End of Period	$	21,429		$	3,262

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/A 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 to Stockholders 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 accountants have 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.

Certain prior year amounts have been reclassified to conform to the current year presentation. These reclassifications had no effect on the Company’s financial position, results of operations or cash flows.

Recently Issued Accounting Pronouncements

We have been made aware of an issue regarding the application of provisions of Statement of Financial Accounting Standards (SFAS) 141, “Business Combinations” and SFAS 142, “Goodwill and Other Intangible Assets,” to companies in the extractive industries, including oil and gas companies. The issue was whether SFAS 142 requires registrants to reclassify costs associated with mineral rights, including both proved and unproved leasehold acquisition costs, as intangible assets in the balance sheet, apart from other capitalized oil and gas property costs. Historically, the Company and other oil and gas companies have included the cost of these oil and gas leasehold interests as part of oil and gas properties and provided the disclosures required by SFAS 69, “Disclosures about Oil and Gas Producing Activities.”

Also under consideration was whether SFAS 142 requires registrants to provide the additional disclosures for intangible assets for costs associated with mineral rights. This issue as it pertains to oil and gas companies was referred to the FASB staff, and the staff issued a proposed FASB Staff Position (“FSP”) on the matter on July 19, 2004. The deadline for commenting on the FSP is August 17, 2004 and the guidance in this FSP will be applied to the first reporting period beginning after the date the FSP is finalized. The Company will continue to monitor this issue and classify its oil and gas mineral rights held under lease and other contractual rights representing the right to extract such reserves as oil and gas properties until further guidance is provided.

On May 2004, the FASB issued FSP No. FAS 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003.” This Board directed FSP provides guidance on the accounting for the effects of the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the Act) for employers that sponsor postretirement health care plans that provide prescription drug benefits. This FSP also requires those employers to provide certain disclosures regarding the effect of the federal subsidy provided by the Act (the subsidy). This FSP supersedes FSP 106-1, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003” and is effective for the first interim period beginning after June 15, 2004. The Company is currently evaluating the impact of the FSP but management does not expect the adoption of the FSP to have a material impact on operating results, financial position or cash flows of the Company.

Stock Based Compensation

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 Company has opted to continue using the intrinsic value based method, as recommended by Accounting Principles Board (APB) Opinion 25, to measure compensation cost for its stock option plans.

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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.


	Three-Months Ended June 30,						Six-Months Ended June 30,
*(In Thousands, Except Per Share Amounts)*	2004			2003			2004			2003
Net Income (Loss), as reported	$	19,318		$	17,904		$	38,329		$	(21,319	)
Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards, net of tax		(479	)		(152	)		(954	)		(1,954	)

Pro-Forma Net Income (Loss)	$	18,839		$	17,752		$	37,375		$	(23,273	)

Earnings Per Share:
Basic - as reported	$	0.59		$	0.56		$	1.18		$	(0.67	)
Basic - pro forma	$	0.58		$	0.56		$	1.15		$	(0.73	)
Diluted - as reported	$	0.59		$	0.55		$	1.17		$	(0.67	)
Diluted - pro forma	$	0.57		$	0.55		$	1.14		$	(0.73	)

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)*	2004			2003			2004			2003
Compensation Expense in Net Income, as reported⁽¹⁾	$	1,638		$	278		$	1,930		$	525
Weighted Average Value per Option Granted During the Period⁽²⁾	$	11.31		$	7.03		$	11.31		$	6.77

Assumptions
Stock Price Volatility		38.4	%		34.1	%		38.4	%		35.3	%
Risk Free Rate of Return		3.3	%		2.5	%		3.3	%		2.5	%
Dividend Rate (per year)	$	0.16		$	0.16		$	0.16		$	0.16
Expected Term (in years)		4			4			4			4

⁽¹⁾

Compensation expense is defined as expense related to the vesting of stock grants and performance shares, net of tax.

⁽²⁾

Calculated using the Black Scholes fair value based method.

The fair value of stock options included in the pro forma results for each of the periods presented is not necessarily indicative of future effects on Net Income and Earnings Per Share.

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2. PROPERTIES AND EQUIPMENT

Properties and equipment are comprised of the following:


	June 30, 2004			December 31, 2003
	(In thousands)
Unproved Oil and Gas Properties	$	91,919		$	86,918
Proved Oil and Gas Properties		1,559,112			1,469,751
Gathering and Pipeline Systems		154,091			146,909
Land, Building and Improvements		4,840			4,758
Other		30,150			28,658

		1,840,112			1,736,994
Accumulated Depreciation, Depletion and Amortization		(890,802	)		(841,039	)

	$	949,310		$	895,955

As part of the Cody acquisition, the Company acquired an interest in certain oil and gas properties in the Kurten field, as general partner of a partnership and as an operator. Prior to the liquidation of the partnership and the divestiture of the Company’s interest in the field, it had an interest of approximately 25%, including a one percent interest in the partnership. The liquidation and divestiture was effective July 31 and November 1, 2003, respectively. The divestiture yielded proceeds of $7.6 million and resulted in a pre-tax gain of $1.8 million. Under the partnership agreement, the Company had the right to a reversionary working interest that would have brought its ultimate interest to 50% upon the limited partner reaching payout. Under the partnership agreement, the limited partner had the option to trigger a liquidation of the partnership. Effective February 13, 2003, the Kurten partnership commenced liquidation at the limited partner’s election. In connection with the liquidation, an appraisal was obtained to allocate the interest in the partnership assets. Based on the receipt of the appraisal in February 2003, the Company would not receive the reversionary interest as part of the liquidation. Due to the impact of the loss of the reversionary interest on future estimated net cash flows of the Kurten field, the limited partner’s decision and the Company’s decision to proceed with the liquidation, it performed an impairment review which resulted in a charge of approximately $87.9 million. This impairment charge is reflected in the first quarter 2003 Statement of Operations as an operating expense but did not impact the Company’s cash flows.

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3. ADDITIONAL BALANCE SHEET INFORMATION

Certain balance sheet amounts are comprised of the following:


	June 30, 2004			December 31, 2003
	June 30, 2004			December 31, 2003
	(In thousands)
Accounts Receivable
Trade Accounts	$	83,533		$	79,439
Joint Interest Accounts		9,776			13,312
Other Accounts		1,593			81

		94,902			92,832
Allowance for Doubtful Accounts		(5,407	)		(5,407	)

	$	89,495		$	87,425

Inventories
Natural Gas in Storage⁽¹⁾	$	4,578		$	14,950
Oil in Storage		206			241
Tublar Goods and Well Equipment		4,138			3,367
Pipeline Exchange Balances		597			(317	)

	$	9,519		$	18,241

⁽¹⁾ The decline in natural gas inventory is due to an increase in gas sales from storage to meet contractual demands.

Other Current Assets
Commodity Hedging Contracts - SFAS 133	$	—		$	1,152
Drilling Advances		8,797			6,443
Prepaid Balances		7,020			4,325
Other Accounts		206			3,086

	$	16,023		$	15,006

Accounts Payable
Trade Accounts	$	12,913		$	11,872
Natural Gas Purchases		5,295			5,751
Royalty and Other Owners		31,467			28,001
Capital Costs		25,674			21,964
Taxes Other Than Income		4,564			3,280
Drilling Advances		6,737			5,721
Wellhead Gas Imbalances		1,952			2,085
Other Accounts		5,261			6,269

	$	93,863		$	84,943

Accrued Liabilities
Employee Benefits	$	8,166		$	9,105
Taxes Other Than Income		15,925			13,359
Interest Payable		6,400			6,368
Commodity Hedging Contracts - SFAS 133		59,754			36,582
Deferred Income Taxes		1,690			1,826
Other Accounts		811			4,344

	$	92,746		$	71,584

Other Liabilities
Postretirement Benefits Other Than Pension	$	2,327		$	2,132
Accrued Pension Cost		7,756			6,232
Commodity Hedging Contracts - FAS 133		14,072			3,051
Accrued Plugging and Abandonment Liability		38,290			36,848
Other		7,121			6,114

	$	69,566		$	54,377

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4. LONG-TERM DEBT

At June 30, 2004, the Company did not have any debt outstanding under its credit facility, which provides for an available credit line of $250 million. The available credit line is subject to adjustment from time to time on the basis of the projected present value (as determined by the bank’s petroleum engineer) of estimated future net cash flows from certain proved oil and gas reserves and other assets of the Company. The revolving term under this credit facility presently ends in October 2006 and is subject to renewal.

The Company has the following debt outstanding at June 30, 2004:

•	$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

5. 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. There was no dilution effect of stock options and awards for the six months ended June 30, 2003 because the effect would be anti-dilutive.

The following is a calculation of basic and diluted weighted average shares outstanding for the three-months and six-months ended June 30, 2004 and 2003:


	Three-Months Ended June 30,		Six-Months Ended June 30,
	2004	2003	2004	2003
Shares - basic	32,525,914	31,980,279	32,461,869	31,908,789
Dilution effect of stock options and awards at end of period	402,759	496,746	399,791	—

Shares - diluted	32,928,673	32,477,025	32,861,660	31,908,789

Stock awards and shares excluded from diluted earnings per share due to the anti-dilutive effect	—	1,226,401	—	1,706,346

6. COMMITMENTS AND CONTINGENCIES

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 and alleged that the Company had improperly deducted costs of production from royalty payments to the plaintiffs and other similarly situated persons. Additionally, the suit claimed that the Company had failed to properly inform the plaintiffs and other similarly situated persons of the deductions taken from royalties. 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 for a total of $2.25 million and 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. It also includes 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.

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In January 2002, 13 overriding royalty owners sued the Company in Wyoming federal district court. The plaintiffs in the federal case have made the same general claims pertaining to deductions from their overriding royalty as the plaintiffs in the Wyoming state court case but have not asked for class certification.

The federal district court judge certified two questions of state law for decision by the Wyoming State Supreme Court, which recently answered both questions. The Wyoming Supreme Court ruled that certain deductions taken by the Company from the plaintiffs were not proper and that the statutes of limitations advanced by the Company are discovery statutes and accordingly do not begin to run until the plaintiffs knew, or had reason to know, of the violation. The Company believes it has properly reported to the plaintiffs and that if it did not the plaintiffs knew or should have known the reporting was improper and the nature of the deductions, thus triggering the statutes of limitations. The Company still intends to raise defenses to the alleged failure to report claims. There is also a dispute as to how the interest should be calculated.

The federal judge refused to certify a question relating to the issue of the proper calculation of damages for failure to provide certain information required by statute on overriding royalty owner check stubs that had been decided adversely to our position in a state district court letter decision in a separate case. After the federal judge’s refusal to certify this issue, the plaintiffs reduced the damages they were claiming. Based upon the plaintiffs expert witness report filed in March 2003, the plaintiffs are now claiming $21 million in total damages which consists of $15.7 million for alleged violations of the check stub reporting statute and $5.3 million for all other damages. In the opinion of our outside counsel, Brown, Drew & Massey, LLP, the likelihood of the plaintiffs recovering $15.7 million for the check stub reporting statute is remote. However, a reserve that management believes is adequate to provide for the check stub reporting statute and all other damages has been established based on managements 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 under the West Virginia Rules of Civil Procedure and allege that the Company failed to pay royalty based upon the wholesale market value of the gas produced, that it had taken improper deductions from the royalty and failed to properly inform the plaintiffs and other similarly situated persons of deductions taken from the royalty. 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 the 1995 Columbia Gas Transmission Corporation bankruptcy proceeding.

Discovery and pleadings necessary to place the class certification issue before the court have been ongoing. A hearing on the plaintiffs’ motion for class certification was held on October 20, 2003, and proposed findings of fact and conclusions of law were submitted to the court on December 5, 2003. The trial is currently scheduled for January 18, 2005.

The investigation into this claim continues and it is in the discovery phase. 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. The plaintiffs allege that they are the rightful owners of a one-half undivided mineral interest in and to certain lands in Brooks County, Texas. As Cody Energy, LLC, the Company acquired certain leases and wells from Wynn-Crosby 1996, Ltd. in 1997 and 1998 and the Company subsequently acquired a 320 acre lease from Hector and Gloria Lopez in 2001. The plaintiffs allege that they are entitled to be declared the rightful owners of an undivided interest in the surface and 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. The original trial date of May 19, 2003 has been cancelled and a new trial date has

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not been set. 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 $13 million. The carrying value of this property is approximately $34 million. Co-defendants Shell Oil Company and Shell Western E&P filed a motion for summary judgment seeking dismissal of plaintiffs’ causes of action on multiple grounds. The original plaintiffs’ attorneys asked permission from the Court to withdraw from the representation. The Court granted that request, and new attorneys for some, but not all of the plaintiffs have recently entered the case. The motion for summary judgment was reset and a hearing was held in December of 2003. The Company joined in the motion. After a second hearing, the Court denied the motion for summary judgment.

Although the investigation into this claim is in its early stages, 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 ensure 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 of 2004, the Company’s wholly owned subsidiary, Cody Energy, LLC, filed suit 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 had proposed a new prospect to certain of these co-working interest owners located within jointly owned oil and gas leases. Some of the co-working interest owners elected to participate and some did not. The initial well was successful and subsequent wells have been drilled to exploit the discovery made in the first well.

In December, certain of the co-working interest owners who elected not to participate in the initial well notified Cody that they believed that they had the right to participate in subsequent wells. Cody contends that, under the terms of the agreements between the parties, the co-working interest owners that elected not to participate in the initial well in the prospect lost their right to participate in subsequent wells in the prospect. 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 contends that this lien is improper and has sought damages for its filing. Cody is vigorously prosecuting this case which is in its early stage of discovery. No trial date has been set by the court.

The investigation into this claim is in its early stages. 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.

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 $10 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, although operating results and cash flow could be significantly impacted in the reporting periods in which such matters are resolved.

- 12 -

7. 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, 2004, the Company had 27 cash flow hedges open: eight natural gas price collar arrangements and 19 natural gas price swap arrangements. Additionally, the Company had five crude oil financial instruments and one natural gas financial instrument open at June 30, 2004, that did not qualify for hedge accounting under SFAS 133. At June 30, 2004, a $62.9 million ($39.0 million net of tax) unrealized loss was recorded in Accumulated Other Comprehensive Income, along with a $73.8 million derivative liability. The change in derivative fair value for the current and prior periods has been included as a component of Natural Gas Production and Crude Oil and Condensate revenue, respectively.

Realized and unrealized gains (losses) recognized in natural gas and crude oil revenue are as follows:


	Three-Months Ended June 30,
	2004						2003
	Realized			Unrealized			Realized			Unrealized
Net Operating Revenues - (In Thousands)
Natural Gas Production	$	(13,262	)	$	1,306		$	(12,348	)	$	(536	)
Crude Oil		(3,326	)		(1,959	)		(236	)		(114	)

Total	$	(16,588	)	$	(653	)	$	(12,584	)	$	(650	)


	Six-Months Ended June 30,
	2004						2003
	Realized			Unrealized			Realized			Unrealized
Net Operating Revenues - (In Thousands)
Natural Gas Production	$	(19,930	)	$	(418	)	$	(37,516	)	$	(999	)
Crude Oil		(5,496	)		(5,854	)		(2,144	)		(195	)

Total	$	(25,426	)	$	(6,272	)	$	(39,660	)	$	(1,194	)

Assuming no change in commodity prices, after June 30, 2004 the Company would reclassify to earnings, over the next 12 months, $31.1 million in after-tax expenditures associated with commodity derivatives. This reclassification represents the net liability associated with open positions at June 30, 2004 related to remaining anticipated 2004 production and a portion of 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, 2004, the Company had five open crude oil swap arrangements and one natural gas swap arrangement with an unrealized net loss of $8.5 million related to the crude oil positions and an unrealized net loss of $0.8 million related to natural gas position. Changes in these amounts are reflected in the respective line items of Net Operating Revenues.

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8. COMPREHENSIVE INCOME

Comprehensive Income includes Net Income and certain items recorded directly to Stockholders’ Equity and classified as Other Comprehensive Income. The following table illustrates the calculation of Comprehensive Income for the six-month periods ended June 30, 2004 and 2003:


	Six-Months Ended June 30,
	2004						2003
	(In Thousands)
Accumulated Other Comprehensive Loss - Beginning of Period				$	(23,135	)				$	(12,939	)
Net Income (Loss)	$	38,329					$	(21,319	)
Other Comprehensive Loss
Reclassification Adjustment for Settled Contracts		22,611						37,493
Changes in Fair Value of Hedge Positions		(51,683	)					(64,324	)
Foreign Currency Translation Adjustment		(11	)					—
Deferred Income Tax		11,094						10,197

Total Other Comprehensive Loss	$	(17,989	)		(17,989	)	$	(16,634	)		(16,634	)

Comprehensive Income (Loss)	$	20,340					$	(37,953	)

Accumulated Other Comprehensive Loss - End of Period				$	(41,124	)				$	(29,573	)

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.

Deferred income tax of $10.2 million at June 30, 2003 represents the net deferred tax liability of ($14.3) million on the Reclassification Adjustment for Settled Contracts and $24.5 million on the Changes in Fair Value of Hedge Positions.

9. ADOPTION OF SFAS 143, “ACCOUNTING FOR ASSET RETIREMENT OBLIGATIONS”

Effective January 1, 2003, the Company adopted SFAS 143, “Accounting for Asset Retirement Obligations.” SFAS 143 requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. The associated asset retirement cost is capitalized as part of the carrying amount of the long-lived asset. Subsequently, the asset retirement cost is allocated to expense using a systematic and rational method over the asset’s useful life. The adoption of SFAS 143 resulted in (1) an increase of total liabilities because more retirement obligations are required to be recognized, (2) an increase in the recognized cost of assets because the retirement costs are added to the carrying amount of the long-lived asset and (3) an increase in operating expense because of the accretion of the retirement obligation and additional depreciation and depletion. The majority of the asset retirement obligations recorded by the Company relate to the plugging and abandonment of oil and gas wells. However, liabilities will also be recorded for meter stations, pipelines, processing plants and compressors. At January 1, 2003, there were no assets legally restricted for purposes of settling asset retirement obligations. The Company recorded a net-of-tax cumulative effect of change in accounting principle loss in January 2003 of $6.8 million and recorded a retirement obligation of $35.2 million. There was no impact on the Company’s cash flows as a result of adopting SFAS 143.

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Subsequent to the adoption of SFAS 143, there has been no significant current period activity with respect to additional retirement liabilities, settled liabilities, and revisions of estimated cash flows. Additional retirement obligations increase the liability associated with new oil and gas wells and other facilities as these obligations are incurred.

The following table reflects the changes of the asset retirement obligations during the first six months of 2004.


(In Thousands)
Carrying amount of asset retirement obligations at December 31, 2003	$	36,848
Liabilities added during the current period		822
Liabilities settled during the current period		(455	)
Current period accretion expense		1,075
Revisions to estimated cash flows		—

Carrying amount of asset retirement obligations at June 30, 2004	$	38,290

10. PENSION AND OTHER POSTRETIREMENT BENEFITS

The components of net periodic benefit costs for the three-months and six-months ended June 30, 2004 and 2003 are as follows:


	For the Three-Months Ended June 30,						For the Six-Months Ended June 30,
	2004			2003			2004			2003
				(In Thousands)
Qualified and Non-Qualified Pension Plans
Current Period Service Cost	$	504		$	440		$	1,007		$	881
Interest Accrued on Pension Obligation		520			420			1,039			839
Expected Return on Plan Assets		(369	)		(250	)		(737	)		(500	)
Net Amortization and Deferral		41			41			83			83
Recognized Loss		203			151			406			301

Net Periodic Benefit Costs	$	899		$	802		$	1,798		$	1,604

Postretirement Benefits Other than Pension Plans
Service Cost of Benefits During the Period	$	71		$	66		$	142		$	133
Interest Cost on the Accumulated Postretirement
Benefit Obligation		93			96			185			193
Recognized Gain		(31	)		(39	)		(61	)		(78	)
Amortization of Transition Obligation		165			166			331			331

Total Postretirement Benefit Cost	$	298		$	289		$	597		$	579

In 2004 the Company does not have any required minimum funding obligations. Currently, management has not determined if a discretionary funding will be made in 2004.

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Report of Independent Registered Public Accounting Firm

To the Board of Directors and Shareholders 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, 2004, and the related condensed consolidated statement of operations for each of the three and six month periods ended June 30, 2004 and 2003 and the condensed consolidated statement of cash flows for the six month periods ended June 30, 2004 and 2003. These interim financials 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, 2003 and the related consolidated statements of operations, comprehensive income, stockholders’ equity, and of cash flows for the year then ended (not presented herein), and in our report dated February 16, 2004, except for Note 2 of such financial statements as to which the date is August 6, 2004, we expressed an unqualified opinion on those consolidated financial statements in a report that also included explanatory paragraphs referring to changes in accounting principle as discussed in Notes 1, 12 and 13 and a restatement of the consolidated balance sheets to correct the classification of deferred tax assets and liabilities as discussed in Note 2. In our opinion, the information set forth in the accompanying condensed consolidated balance sheet as of December 31, 2003, 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

August 9, 2004

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

The following review of operations for the three and six month periods ended June 30, 2004 and 2003 should be read along 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/A for the year ended December 31, 2003.

Overview

In the first half of 2004, we produced 41.6 Bcfe compared to production of 44.2 Bcfe for the comparable period of the prior year. Natural gas production was 35.3 Bcf and oil production was 1,036 Mbbls. Natural gas production in the current period remained at a substantially consistent level when compared to 2003 which had production of 35.2 Bcf. Our ability to maintain natural gas production is attributable to successful drilling efforts on properties acquired in the Cody acquisition and drilling success in the East region in 2003 and 2004 in southern West Virginia. Oil production decreased in the current period when compared to the comparable period of the prior year with 1,457 Mbbls produced in the first half of 2003. The decrease in oil production is primarily the result of the continued decline of the CL&F lease in south Louisiana, along with the decline in the production profile in the West region due to declines in expenditures in 2002 and 2003.

In the six-months ended June 30, 2004, we drilled 130 gross wells (118 development and 12 exploratory wells) with a success rate of 98% compared to 68 gross wells (61 development and seven exploratory wells) with a success rate of 93% for the comparable period of the prior year. For the full year, we plan to drill 268 gross wells compared to 173 gross wells in 2003.

We had net income of $38.3 million, or $1.18 per share, for the six-months ended June 30, 2004 compared to a net loss of $21.3 million, or $0.67 per share, for the comparable period of the prior year. The prior year loss was substantially due to non-cash impairment charges of $87.9 million (pre-tax) related to the liquidation of a limited partnership interest in the Kurten field and the cumulative effect of accounting change in the amount of $6.8 million due to the adoption of SFAS 143.

In the first half of 2004, natural gas prices improved over those of the same period of the comparable year and our financial results reflect their impact. Our realized natural gas price was $5.12 per Mcf, or 13% higher, than the $4.52 per Mcf price realized in the same period of the prior year. These realized prices are impacted by realized gains and losses resulting from commodity derivatives. 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, inventory 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.

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 2004, excluding acquisitions, we expect to spend approximately $228 million in capital and exploration expenditures. For the six-months ended June 30, 2004, $131.7 million of capital and exploration expenditures have been invested in our exploration and development efforts.

We remain focused on our strategies of concentrating our capital spending program on projects balancing acceptable risk with the strongest economics. The favorable drilling results and enhanced infrastructure in our East region in 2003 and the first half of 2004 are the result of our refocusing our production growth efforts in this region. Accordingly, we have expanded our capital budget in the East. We will continue to use a portion of the cash flow from our long-lived Mid-Continent natural gas reserves to fund our exploration and development efforts in the Gulf Coast and Rocky Mountain areas. In addition, we have expanded our interest in the offshore Gulf of Mexico and Canada. Our offshore efforts are an extension of our Gulf Cost region and account for approximately ten percent of our current year capital budget. Our Canadian investment is considered a long-term strategic play with a strong focus on growing these operations through our exploration efforts. In the current year we have allocated approximately six percent of our capital budget to these operations. We believe these strategies are appropriate in the current industry environment and will continue to add shareholder value over the long term.

- 17 -

The preceding paragraphs, discussing our strategic pursuits and goals, contain forward-looking information. See Forward-Looking Information on page 31.

Financial Condition

Capital Resources and Liquidity

Our primary source of cash for the first six months of 2004 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. 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 and pay dividends. See below for additional discussion and analysis of cash flow.


	Six-Months Ended June 30,
	2004			2003
Cash Flows Provided by Operating Activities	$	143,301		$	139,804
Cash Flows Used by Investing Activities		(128,120	)		(78,093	)
Cash Flows Provided (Used) by Financing Activities		5,524			(61,010	)

Net Increase (Decrease) in Cash and Cash Equivalents	$	20,705		$	701

Operating Activities. Cash flows from operating activities increased for the six month period ended June 30, 2004 by $3.5 million. The increase for the six months ended is substantially due to an increase in net operating revenues due to higher commodity prices in the amount of $1.7 million with an offsetting reduction related to a decline in our brokered natural gas margin of $0.6 million. Changes in assets and liabilities increased operating cash flow by $1.1 million. The remaining variance of $1.3 million is related to the net impact of non-cash items to reconcile net income (loss) to cash. See the Statement of Cash Flows for a detail of these items.

Investing Activities. The primary driver of cash used by investing activities is capital spending and exploration expense. These budgeted amounts are established based on current commodity prices. Due to the volatility of commodity prices the budget may be periodically adjusted during any given year. Cash flows used in investing activities increased for the six months ended June 30, 2004 in the amount of $51.0 million due to an increase in our capital budget. This amount was offset by a decrease in exploration expense in the amount of $3.3 million. The increase in our capital budget is due to an increase in drilling activity over the prior year as a result of higher commodity prices. The decrease in exploration expense is due to a decline in dry hole expense as a result of improved drilling success.

Financing Activities. Cash flows provided by financing activities was $5.5 million for the six months ended June 30, 2004. This is the result of proceeds from the exercise of stock options, offset by the purchase of treasury shares and dividend payments. Cash flows used by financing activities for the six months ended June 30, 2003 was $61.0 million. This is due to a net repayment on our revolving credit facility in the amount of $61.0 million. Cash utilized for the repayments was generated from operating cash flows.

The available credit line under our revolving credit facility, currently $250 million, 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 bank’s petroleum engineer) and other assets. At June 30, 2004, we had no outstanding balance on the facility with excess capacity totaling $250 million of the total available credit facility. The revolving term of the credit facility ends in October 2006. 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 acquisitions.

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On August 13, 1998, the Company announced that its Board of Directors (“Board”) authorized the repurchase of two million shares of the Company’s stock in the open market or in negotiated transactions. All purchases executed have been through open market transactions. There is no expiration date associated with the authorization to repurchase securities of the Company. See Item 2 “Changes in Securities, Use of Proceeds and Issuer Purchases of Equity Securities” of Part II “Other Information” for additional information.

Capitalization

Our capitalization information is as follows:


	June 30, 2004			December 31, 2003
	*(In millions)*
Debt	$	270.0		$	270.0
Stockholders’ Equity ⁽¹⁾		392.0			365.2

Total Capitalization	$	662.0		$	635.2

Debt to Capitalization		41	%		43	%

Cash and Cash Equivalents	$	21.4		$	0.7

⁽¹⁾	Includes common stock, net of treasury stock.

During the first half of 2004, we paid dividends of $2.6 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.

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 budget such capital expenditures while considering projected cash flows for the year.

The following table presents major components of capital and exploration expenditures:


	Six-Months Ended June 30,
*(In millions)*	2004		2003
Capital Expenditures
Drilling and Facilities	$	87.3	$	38.6
Leasehold Acquisitions		9.5		10.8
Pipeline and Gathering		6.8		2.2
Other		1.0		0.7

		104.6		52.3

Proved Property Acquisitions		1.4		1.0
Exploration Expense		25.7		29.1

Total	$	131.7	$	82.4

We continually assess the natural gas price environment and may increase or decrease the capital and exploration expenditures accordingly. See the Overview discussion for additional information regarding the current year drilling program.

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Critical Accounting Policies and Estimates

Readers of this document and users of the information contained in it should be aware of how certain events may impact our financial results based on the accounting policies in place. The most significant policies are discussed below.

Oil and Gas Reserves

The process of estimating quantities of proved reserves is inherently uncertain, and the reserve data included in this document are only estimates. The process relies on interpretations of available geologic, geophysic, engineering and production data. The extent, quality and reliability of this technical data can vary. The degree of uncertainty varies among the three regions in which we operate. The estimation of reserves in the Gulf Coast region requires more estimates then the East and West regions and inherently has more uncertainty surrounding reserve estimation. The differences in the reserve estimation process are substantially due to the geological conditions in which the wells are drilled. The process also requires certain economic assumptions, some of which are mandated by the SEC, such as oil and gas prices. Additional assumptions include drilling and operating expenses, capital expenditures, taxes and availability of funds. The accuracy of a reserve estimate is a function of:

•

the quality and quantity of available data;

•

the interpretation of that data;

•

the accuracy of various mandated economic assumptions; and

•

the judgment of the persons preparing the estimate.

In 2003, 100% of the Company’s reserves were subject to an external audit by Miller & Lents, Ltd., an independent oil and gas reservoir engineering consulting firm, who in their opinion determined the estimates to be reasonable in the aggregate. Additionally, in 2003 the Company did not have a significant reserve revision recorded. For more information regarding reserve estimation, including historical reserve revisions, read the Supplemental Oil and Gas Disclosure in the Annual Report on Form 10-K/A for the year ended December 31, 2003.

Our rate of recording depreciation, depletion and amortization expense (DD&A) is dependent upon our estimate of proved reserves, which is utilized in our unit-of-production method calculation. If the estimates of proved reserves were to be reduced, the rate at which we record DD&A expense would increase, reducing net income. Such a reduction in reserves may result from lower market prices, which may make it non-economic to drill for and produce higher cost fields. A five percent positive or negative revision to proved reserves throughout the Company would decrease or increase the DD&A rate by approximately $0.05 to $0.06 per Mcfe. Revisions in significant fields may individually affect the Company’s DD&A rate. It is estimated that a positive or negative reserve revision of 10% in one of the Company’s most productive fields would have a $0.04 impact on the total Company DD&A rate.

In addition, a decline in proved reserve estimates may impact the outcome of our annual impairment test under SFAS 144, “Accounting for the Impairment or Disposal of Long-Lived Assets”. Due to the inherent imprecision of the reserve estimation process, risks associated with the operations of proved producing properties, and market sensitive commodity prices utilized in our impairment analysis, management cannot determine if an impairment is reasonably likely to occur in the future.

Carrying Value of Long-Lived Assets

The Company evaluates the impairment of its oil and gas properties on a lease-by-lease basis whenever events or changes in circumstances indicate an asset’s carrying amount may not be recoverable. The Company compares expected undiscounted future cash flows to the net book value of the asset. If the future undiscounted cash flows, based on the Company’s estimate of future crude oil and natural gas prices, operating costs and anticipated production from proved reserves are lower than the net book value of the asset, the capitalized cost is reduced to fair value. Commodity pricing is estimated by using a combination of historical and current prices adjusted for geographical location and quality differentials, as well as other factors that management believes will impact realizable prices. Fair value is calculated by discounting the

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future cash flows. In 2001 and 2002 there have not been any unusual or unexpected occurrences that have caused significant revisions in estimated cash flows which are utilized in the Company’s impairment test. In 2003 the Company significantly revised the estimated cash flow utilized in our impairment review of the Kurten field due to a loss of a reversionary interest in the field. In December 2003 the Company’s remaining interest in the field was sold. For additional discussion on the Kurten field impairment see Note 2 to the consolidated financial statements.

Costs attributable to our unproved properties are not subject to the impairment analysis described above, however, a portion of the costs associated with such properties is subject to amortization based on past experience and average property lives. Average property lives are determined on a regional basis and based on the estimated life of unproved property leasehold rights. Historically, there have not been significant changes in the average property lives of each of the regions. However, if the average property life increases, the amount of the amortization charge in a given reporting period will decrease. If the average unproved property life decreases or increases by one year the amortization would increase or decrease by approximately $1.0 million.

In the past the average leasehold life in the Gulf Coast region has been shorter than the average life in the East and West regions. Average property lives in the Gulf Coast, East and West regions have been four, seven and six years, respectively. As these properties are developed and reserves are proven, the remaining capitalized costs are subject to depreciation and depletion. If the development of these properties is deemed unsuccessful, the capitalized costs related to the unsuccessful activity is expensed in the year the determination is made. The rate at which the unproved properties are written off depends on the timing and success of the Company’s future exploration program.

Accounting for Derivative Instruments and Hedging Activities

Periodically we enter into derivative commodity instruments to hedge our exposure to price fluctuations on natural gas and crude oil production. We follow the accounting prescribed in SFAS 133. Under SFAS 133, the fair value of each derivative instrument is recorded as either an asset or liability on the balance sheet. At the end of each period, these instruments are marked-to-market. The gain or loss on the change in fair value is recorded as Other Comprehensive Income, a component of equity, to the extent that the derivative instrument is an effective hedge. Under SFAS 133, effectiveness is a measurement of how closely correlated the hedge instrument is with the underlying physical sale. For example, a natural gas price swap that converts Henry Hub index to a fixed price would be perfectly correlated, and 100% effective, if the underlying gas were sold at the Henry Hub index. Any portion of the gains or losses that are considered ineffective under the SFAS 133 test are recorded immediately as a component of operating revenue on the statement of operations.

Long-Term Employee Benefit Costs

Our costs of long-term employee benefits, particularly pension and postretirement benefits, are incurred over long periods of time, and involve many uncertainties over those periods. The net periodic benefit cost attributable to current periods is based on several assumptions about such future uncertainties, and is sensitive to changes in those assumptions. It is management’s responsibility, often with the assistance of independent experts, to select assumptions that in its judgment represent best estimates of those uncertainties. It also is management’s responsibility to review those assumptions periodically to reflect changes in economic or other factors that affect those assumptions.

The current benefit service costs, as well as the existing liabilities, for pensions and other postretirement benefits are measured on a discounted present value basis. The discount rate is a current rate, related to the rate at which the liabilities could be settled. Our assumed discount rate is based on average rates published for high-quality fixed income securities.

The benefit obligation and the periodic cost of postretirement medical benefits also are measured based on assumed rates of future increase in the per capita cost of covered health care benefits. As of December 31, 2003, the assumed rate of increase was 8.0%. The net periodic cost of pension benefits included in expense also is affected by the expected long-term rate of return on plan assets assumption. The expected return on plan assets rate is normally changed less frequently than the assumed discount rate, and reflects long-term expectations, rather than current fluctuations in market conditions. The actual rate of return on plan assets

- 21 -

may differ from the expected rate due to the volatility normally experienced in capital markets. Management’s goal is to manage the investments over the long term to achieve optimal returns with an acceptable level of risk and volatility.

Stock Based Compensation

In accordance with current accounting standards there are two alternative methods that can be used to account for stock-based compensation. The first method is the Intrinsic Value method and recognizes compensation cost as the excess, if any, of the quoted market price of our stock at the grant date over the amount an employee must pay to acquire the stock. The second method is the Fair Value method. Under the fair value method, compensation cost is measured at the grant date based on the value of an award and is recognized over the service period, which is usually the vesting period. Currently, we account for stock-based compensation in accordance with the Intrinsic Value method.

Results of Operations

Second Quarters of 2004 and 2003 Compared

Net Income and Income from Operations

We reported net income in the second quarter of 2004 of $19.3 million, or $0.59 per share. During the corresponding quarter of 2003, we reported net income of $17.9 million, or $0.56 per share. Operating income increased $1.6 million compared to the comparable period of the prior year. The increase in current year operating income was substantially due to a decrease in exploration expense in the amount of $6.1 million, offset by an increase in general and administrative expense of $3.4 million and an increase in taxes other than income of $1.3 million. See the analysis on Operating Expenses for discussion related to these changes.

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Natural Gas Production Revenues

The average total company realized natural gas production sales price, including the realized impact of derivative instruments, was $5.02 per Mcf compared to $4.50 per Mcf for the comparable period of the prior year. These prices include the realized impact of derivative instruments which reduced these prices by $0.75 per Mcf in 2004 and $0.68 per Mcf in 2003. The following table excludes the unrealized gain (loss) from the change in derivative fair value of $1.3 million and ($0.5) million for the three months ended June 30, 2004 and 2003, respectively. These unrealized changes in fair value have been included in the Natural Gas Production revenues line item on the Statement of Operations.


	Three Months Ended June 30,					Variance
	2004			2003		Amount			Percent
Natural Gas Production (Mmcf)
Gulf Coast		7,600			7,379		221		3	%
West		5,216			6,020		(804	)	(13	)%
East		4,841			4,646		195		4	%

Total Company		17,657			18,045		(388	)	(2	)%

Natural Gas Production Sales Price ($/Mcf)
Gulf Coast	$	5.12		$	4.96	$	0.16		3	%
West	$	4.64		$	3.60	$	1.04		29	%
East	$	5.29		$	4.92	$	0.37		8	%
Total Company	$	5.02		$	4.50	$	0.52		12	%

Natural Gas Production Revenue (in thousands)
Gulf Coast	$	38,889		$	36,562	$	2,327		6	%
West		24,208			21,689		2,519		12	%
East		25,625			22,861		2,764		12	%

Total Company	$	88,722		$	81,112	$	7,610		9	%

Price Variance Impact on Natural Gas Production Revenue
Gulf Coast	$	1,229
West		5,417
East		1,807

Total Company	$	8,453

Volume Variance Impact on Natural Gas Production Revenue
Gulf Coast	$	1,097
West		(2,898	)
East		958

Total Company	$	(843	)

The decrease in natural gas production in the West region is due substantially to the natural production decline in the Rocky Mountains as a result of reduced capital expenditures in 2002 and 2003. The impact of the decline in the West region was partially offset by an increase in the Gulf Coast and East region. The increase in the Gulf Coast region is due to the results of the 2003 drilling program on properties acquired in the Cody acquisition. The increase in the East region is due to successful drilling in 2003 and 2004 in southern West Virginia. The increase in the realized natural gas price combined with the decrease in production resulted in a net natural gas revenue increase of $7.6 million, excluding the unrealized impact of derivative instruments.

- 23 -

Brokered Natural Gas Revenue and Cost


	Three Months Ended June 30,					Variance
	2004			2003		Amount			Percent
Sales Price	$	7.19		$	4.99	$	2.20		44	%
Volume Brokered (Mmcf)		2,173			4,686		(2,513	)	(54	)%

Brokered Natural Gas Revenues (in thousands)	$	15,628		$	23,370

Purchase Price	$	6.26		$	4.60	$	1.66		36	%
Volume Brokered (Mmcf)		2,173			4,686		(2,513	)	(54	)%

Brokered Natural Gas Cost (in thousands)	$	13,596		$	21,539

Brokered Natural Gas Margin (in thousands)	$	2,032		$	1,831	$	201		11	%

Sales Price Variance Impact on Revenue	$	4,781
Volume Variance Impact on Revenue	$	(12,540	)

	$	(7,759	)

Purchase Price Variance Impact on Purchases	$	(3,607	)
Volume Variance Impact on Purchases	$	11,567

	$	7,960

The decrease in brokered natural gas revenues of $7.8 million combined with the decline in brokered natural gas cost of $8.0 million resulted in a slight increase to the brokered natural gas margin of $0.2 million.

- 24 -

Crude Oil and Condensate Revenues

The average total company realized crude oil sales price, including the realized impact of derivative instruments, was $31.10 per Bbl for the second quarter of 2004 and $29.27 for the comparable period of the prior year. These prices include the realized impact of derivative instruments which reduced these prices by $6.67 per Bbl in 2004 and $0.33 per Bbl in 2003. The following table excludes the unrealized loss from the change in derivative fair value of $2.0 million and $0.1 million for the three-months ended June 30, 2004 and 2003, respectively. These unrealized changes in fair value have been included in the Crude Oil and Condensate revenues line item on the Statement of Operations.


	Three Months Ended June 30,					Variance
	2004			2003		Amount			Percent
Crude Oil Production (Mbbl)
Gulf Coast		450			648		(198	)	(31	)%
West		42			51		(9	)	(18	)%
East		7			7		—		—

Total Company		499			706		(207	)	(29	)%

Crude Oil Sales Price ($/Bbl)
Gulf Coast	$	30.43		$	29.30	$	1.13		4	%
West	$	37.37		$	28.47	$	8.90		31	%
East	$	36.41		$	31.83	$	4.58		14	%
Total Company	$	31.10		$	29.27	$	1.83		6	%

Crude Oil Revenue (in thousands)
Gulf Coast	$	13,686		$	18,982	$	(5,296	)	(28	)%
West		1,574			1,462		112		8	%
East		251			220		31		14	%

Total Company	$	15,511		$	20,664	$	(5,153	)	(25	)%

Price Variance Impact on Crude Oil Revenue
Gulf Coast	$	508
West		375
East		31

Total Company	$	914

Volume Variance Impact on Crude Oil Revenue
Gulf Coast	$	(5,804	)
West		(263	)
East		—

Total Company	$	(6,067	)

The decrease in oil production is primarily the result of the continued decline of the CL&F lease in south Louisiana, along with the decline in the production profile in the West region due to declines in expenditures in 2002 and 2003. The increase in the realized crude oil price combined with the decline in production resulted in a net revenue decrease of $5.2 million, excluding the unrealized impact of derivative instruments.

- 25 -

Other Net Operating Revenues

Other operating revenues decreased $1.7 million. This change is substantially due to a decline in gas transportation revenue of $1.1 million, water treatment revenue of $0.4 million and natural gas liquid revenue of $0.1 million.

Operating Expenses

Total costs and expenses from operations decreased $8.8 million in the second quarter of 2004 compared to the same quarter of 2003. The primary reasons for this fluctuation are as follows:

•

Brokered Natural Gas Cost declined in the amount of $7.9 million. See the Brokered Natural Gas Revenue and Cost analysis for additional discussion.

•

Exploration expense decreased $6.1 million primarily as a result of decrease in spending on geological and geophysical expenses and a decrease in dry hole expense in 2004. During the second quarter of 2004, we decreased our geological and geophysical expenses by $2.1 million and incurred less dry hole expense in the amount of $4.0 million. The decrease in dry hole expense is substantially due to expense incurred in the prior year related to two exploratory wells in the Gulf Coast region which totaled $3.5 million.

•

General and Administrative expense increased by $3.4 million. This increase is substantially due to the recognition of expense of $2.2 million related to stock compensation plans, $0.7 million of expense related to professional services provided in conjunction with Sarbanes-Oxley compliance and $0.2 million related to an increase in insurance cost.

•

Taxes other than income increased by $1.3 million due to an increase in commodity prices.

Interest Expense and Other

Interest expense decreased $0.5 million. This variance is the combination of a decrease due to a lower average level of outstanding debt during the second quarter of 2004 when compared to the corresponding period of the prior year and a decline in interest rates on the revolving credit facility.

Income Tax Expense

Income tax expense increased $0.7 million due to a comparable increase in our pre-tax income.

Six Months of 2004 and 2003 Compared

Net Income and Income from Operations

We reported net income in the first half of 2004 of $38.3 million, or $1.18 per share. During the corresponding period of 2003, we reported a loss of $21.3 million, or $0.67 per share. Operating income increased $84.4 million compared to the comparable period of the prior year. The increase in current year operating income was substantially due to an increase in natural gas production revenue of $22.1 million, off-set by a decline in oil production revenue and other revenue in the amount of $17.3 million and $3.1 million, respectively, and a prior period non-cash impairment charge of $87.9 million.

- 26 -

Natural Gas Production Revenues

The average total company realized natural gas production sales price, including the realized impact of derivative instruments, was $5.12 per Mcf compared to $4.52 per Mcf for the comparable period of the prior year. These prices include the realized impact of derivative instruments which reduced these prices by $0.56 per Mcf in 2004 and $1.06 per Mcf in 2003. The following table excludes the unrealized loss from the change in derivative fair value of $0.4 million and $1.0 million for the six-months ended June 30, 2004 and 2003, respectively. These unrealized changes in fair value have been included in the Natural Gas Production revenues line item on the Statement of Operations.


	Six-Months Ended June 30,					Variance
	2004			2003		Amount			Percent
Natural Gas Production (Mmcf)
Gulf Coast		15,275			14,112		1,163		8	%
West		10,782			12,092		(1,310	)	(11	)%
East		9,280			9,029		251		3	%

Total Company		35,337			35,233		104		0	%

Natural Gas Production Sales Price ($/Mcf)
Gulf Coast	$	5.13		$	4.92	$	0.21		4	%
West	$	4.74		$	3.61	$	1.13		31	%
East	$	5.53		$	5.13	$	0.40		8	%
Total Company	$	5.12		$	4.52	$	0.60		13	%

Natural Gas Production Revenue (in thousands)
Gulf Coast	$	78,355		$	69,387	$	8,968		13	%
West		51,121			43,613		7,508		17	%
East		51,349			46,286		5,063		11	%

Total Company	$	180,825		$	159,286	$	21,539		14	%

Price Variance Impact on Natural Gas Production Revenue
Gulf Coast	$	3,245
West		12,233
East		3,779

Total Company	$	19,257

Volume Variance Impact on Natural Gas Production Revenue
Gulf Coast	$	5,717
West		(4,725	)
East		1,290

Total Company	$	2,282

The decrease in natural gas production in the West region is due substantially to the natural production decline in the Rocky Mountains as a result of reduced capital expenditures in 2003 and 2002. The impact of the decline in the West region was partially offset by an increase in the Gulf Coast and East region. The increase in the Gulf Coast region is due to successful drilling efforts on properties acquired in the Cody acquisition. The increase in the East region is due to successful drilling in 2003 and 2004 in southern West Virginia. The increase in the realized natural gas price combined with the increase in production resulted in a net revenue increase of $21.5 million, excluding the unrealized impact of derivative instruments.

- 27 -

Brokered Natural Gas Revenue and Cost


	Six-Months Ended June 30,					Variance
	2004			2003		Amount			Percent
Sales Price	$	8.35		$	6.42	$	1.93		30	%
Volume Brokered		5,655			8,603		(2,948	)	(34	)%

Brokered Natural Gas Revenues	$	47,187		$	55,220

Purchase Price	$	7.48		$	5.79	$	1.69		29	%
Volume Brokered		5,655			8,603		(2,948	)	(34	)%

Brokered Natural Gas Cost	$	42,317		$	49,800

Brokered Natural Gas Margin (in thousands)	$	4,870		$	5,420	$	(550	)	(10	)%

Sales Price Variance Impact on Revenue	$	10,914
Volume Variance Impact on Revenue	$	(18,951	)

	$	(8,037	)

Purchase Price Variance Impact on Purchases	$	(9,557	)
Volume Variance Impact on Purchases	$	17,044

	$	7,487

The decrease in brokered natural gas revenues of $8.0 million combined with the decline in brokered natural gas cost of $7.5 million resulted in a slight decrease to the brokered natural gas margin of $0.5 million.

- 28 -

Crude Oil and Condensate Revenues

The average total company realized crude oil sales price, including the realized impact of derivative instruments, was $31.04 per Bbl for the first half of 2004 and $30.10 for the comparable period of the prior year. These prices include the realized impact of derivative instruments which reduced these prices by $5.31 per Bbl in 2004 and $1.47 per Bbl in 2003. The following table excludes the unrealized loss from the change in derivative fair value of $5.9 million and $0.2 million for the six-months ended June 30, 2004 and 2003, respectively. These unrealized changes in fair value have been included in the Crude Oil and Condensate revenues line item on the Statement of Operations.


	Six-Months Ended June 30,					Variance
	2004			2003		Amount			Percent
Crude Oil Production (Mbbl)
Gulf Coast		940			1,343		(403	)	(30	)%
West		83			100		(17	)	(17	)%
East		13			14		(1	)	(8	)%

Total Company		1,036			1,457		(421	)	(29	)%

Crude Oil Sales Price ($/Bbl)
Gulf Coast	$	30.57		$	30.10	$	0.47		2	%
West	$	35.89		$	30.22	$	5.67		19	%
East	$	34.17		$	29.05	$	5.12		18	%
Total Company	$	31.04		$	30.10	$	0.94		3	%

Crude Oil Revenue (in thousands)
Gulf Coast	$	28,745		$	40,431	$	(11,686	)	(29	)%
West		2,964			3,036		(72	)	(2	)%
East		464			370		94		26	%

Total Company	$	32,173		$	43,837	$	(11,664	)	(27	)%

Price Variance Impact on Crude Oil Revenue
Gulf Coast	$	444
West		468
East		69

Total Company	$	981

Volume Variance Impact on Crude Oil Revenue
Gulf Coast	$	(12,130	)
West		(540	)
East		25

Total Company	$	(12,645	)

The decrease in oil production is primarily the result of the continued decline of the CL&F lease in south Louisiana, along with the decline in the production profile in the West region due to declines in expenditures in 2002 and 2003. The increase in the realized crude oil price combined with the decline in production resulted in a net revenue decrease of $11.7 million, excluding the unrealized impact of derivative instruments.

- 29 -

Other Net Operating Revenues

Other operating revenues decreased $3.1 million. This change is substantially due to a decline in gas transportation revenue of $1.7 million, water treatment revenue of $0.7 million and natural gas liquid revenue of $0.5 million.

Operating Expenses

Total costs and expenses from operations decreased $91.4 million in the first half of 2004 compared to the same period of the prior year. The primary reasons for this fluctuation are as follows:

•

Brokered Natural Gas Cost declined in the amount of $7.5 million. See the Brokered Natural Gas Revenue and Cost analysis for additional discussion.

•

Exploration expense decreased $3.3 million primarily as a result of a decrease in dry hole expense in 2004 in the amount of $4.1 million. The Company experienced one exploratory dry hole in the current period compared to four in the comparable period of the prior year.

•

Depreciation, Depletion and Amortization increased $1.6 million. This increase is due to an increase in unit of production expense. This increase is primarily due to negative reserve revisions on certain wells in south Louisiana at December 31, 2003.

•

Impairment of Long-Lived Assets expense decreased $87.9 million. This decrease is related to the liquidation of a limited partnership interest in the Kurten field. See Note 2 of the consolidated financial statements for additional discussion.

•

General and Administrative expense increased by $3.5 million. This increase is due to the recognition of expense of $2.2 million related to stock compensation plans, $1.0 million of expense related to professional services provided in conjunction with Sarbanes-Oxley compliance and $0.3 million related to an increase in insurance cost.

•

Taxes other than income increased by $1.1 million due to an increase in commodity prices.

Interest Expense and Other

Interest expense decreased $0.6 million. This variance is the combination of a decrease due to a lower average level of outstanding debt during the first half of 2004 when compared to the corresponding period of the prior year and a decline in interest rates on the revolving credit facility.

Income Tax Expense

Income tax expense increased $32.3 million due to a comparable increase in our pre-tax income.

Recently Issued Accounting Pronouncements

- 30 -

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.

- 31 -

ITEM 3. Quantitative and Qualitative Disclosures about Market Risk

Commodity Price Swaps and Options

Our hedging policy 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 against declines in oil and gas prices. These hedging arrangements may expose us to risk of financial loss and limit the benefit to us of increases in prices. Please read the discussion below related to commodity price swaps and Note 7 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, 2004, the aggregate level of commodity hedging must not exceed 80% of the anticipated future equivalent production during the period covered by the hedges. During the first half of 2004, natural gas price swaps covered 15,165 Mmcf of our gas production, fixing the sales price of this gas at an average of $5.09 per Mcf.

At June 30, 2004, we had open natural gas price swap contracts covering our 2004 and 2005 production as follows:


	Natural Gas Price Swaps
Contract Period	Volume in Mmcf	Weighted Average Contract Price		Unrealized Loss (In thousands)
*Natural Gas Price Swaps on Production in:*
Third Quarter 2004	7,226		4.99
Fourth Quarter 2004	7,226		4.99

Six Months Ended December 31, 2004	14,452	$	4.99	$	25,759

First Quarter 2005	5,069	$	5.14
Second Quarter 2005	5,125		5.14
Third Quarter 2005	5,181		5.14
Fourth Quarter 2005	5,181		5.14

Full Year 2005	20,556	$	5.14	$	25,516

From time to time the Company enters into natural gas and crude oil derivative arrangements that do not qualify for hedge accounting under SFAS 133. These financial instruments are recorded at fair value at the balance sheet date. At June 30, 2004, the Company had five open crude oil swap arrangements and one natural gas swap arrangement with an unrealized net loss of $8.5 million and $0.8 million recognized in Operating Revenues, respectively.

- 32 -

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 derivatives 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 half of 2004, natural gas price collars covered 13,507 Mmcf of our gas production, with a weighted average floor of $5.03 per Mcf and a weighted average ceiling of $6.27 per Mcf.

At June 30, 2004, we had open natural gas price collar contracts covering our 2004 and 2005 production as follows:


	Natural Gas Price Collars
Contract Period	Volume in Mmcf	Weighted Average Ceiling / Floor		Unrealized Loss (In thousands)
*Natural Gas Price Collars on Production in:*
Third Quarter 2004	4,723	$	5.75 / $4.41
Fourth Quarter 2004	4,723	$	5.75 / $4.41

Six Months Ended December 31, 2004	9,446	$	5.75 / $4.41	$	8,857

First Quarter 2005	826	$	5.45 / $4.90
Second Quarter 2005	836	$	5.45 / $4.90
Third Quarter 2005	845	$	5.45 / $4.90
Fourth Quarter 2005	845	$	5.45 / $4.90

Full Year 2005	3,352	$	5.45 / $4.90	$	4,463

At June 30, 2004, we have no open crude oil price collar arrangements to cover our 2004 or 2005 production.

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 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.

In August 2004 we determined that deferred tax assets and liabilities associated with current and non-current assets and liabilities that had historically been classified in long-term deferred income taxes should instead be classified as current and non-current deferred tax assets and liabilities based on the classification of the related asset and liability for financial reporting purposes. We identified this deficiency and we brought it to the attention of our audit committee and auditors promptly. We believe we have addressed this deficiency as we have implemented internal controls surrounding the calculation and review of deferred income tax classification to enhance our ability to comply with all appropriate tax and related accounting issues.

There have been no significant changes in the Company’s internal controls, other than those related to deferred income taxes, or in other factors that could significantly affect internal controls subsequent to the date the Company carried out its evaluation.

- 33 -

PART II. OTHER INFORMATION

ITEM 2. Changes in Securities, Use of Proceeds and Issuer Purchases of Equity Securities

Issuer Purchases of Equity Securities (1)


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 2004	46,200	$	30.81	46,200	1,651,200
May 2004	111,900	$	35.02	111,900	1,539,300
June 2004	—		—

Total	158,100

(1)

- 34 -

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

On April 29, 2004, the Company held its Annual Meeting of Stockholders. At this meeting, the Company’s stockholders voted on the following matters:

•

the election of two directors,

•

the approval of the 2004 Incentive Plan, and

•

the ratification of the appointment of PricewaterhouseCoopers LLP, independent certified public accountants, as auditors of the Company for its 2004 fiscal year.

Of the 32,394,833 shares entitled to vote, 30,938,281 were voted.

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


Robert F. Bailey
For:		30,685,381
Withheld:		252,900

John G. L. Cabot
For:		22,555,540
Withheld:		8,382,741

The terms of office of directors, Dan O. Dinges, James G. Floyd, Robert Kelley, C. Wayne Nance, and P. Dexter Peacock and William P. Vititoe continued beyond the meeting date.

Shareholders voted to approve the 2004 Incentive Plan by the following vote:


For:		26,548,636
Against:		2,129,453
Abstain:		8,251
Broker No Votes:		2,251,941

Shareholders voted to ratify the appointment of PricewaterhouseCoopers LLP, independent certified public accountants, as auditors of the Company for its 2004 fiscal year by the following vote:


For		30,525,191
Against		406,923
Abstain		6,167

- 35 -

ITEM 6. Exhibits and Reports on Form 8-K

(a)

Exhibits


10.26		- 2004 Incentive Plan (Form 10-Q for the quarter ended June 30, 2004).

10.27		- 2004 Performance Award Agreement (Form 10-Q for the quarter ended June 30, 2004).

15.1		- Awareness letter of PricewaterhouseCoopers LLP

23.1		- Consent of Brown, Drew & Massey, LLP

23.2		- Consent of Miller and Lents, Ltd.

31.1		- 302 Certification - Chairman, President and Chief Executive Officer

31.2		- 302 Certification - Vice President and Chief Financial Officer

32.1		- 906 Certification

(b)

Reports on Form 8-K

None

- 36 -

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)


August 9, 2004	By:	/s/ Dan O. Dinges
		Dan O. Dinges
		Chairman, President and
		Chief Executive Officer
		(Principal Executive Officer)

August 9, 2004	By:	/s/ Scott C. Schroeder
		Scott C. Schroeder
		Vice President and Chief Financial Officer
		(Principal Financial Officer)

August 9, 2004	By:	/s/ Henry C. Smyth
		Henry C. Smyth
		Vice President, Controller and Treasurer
		(Principal Accounting Officer)

- 37 -

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