SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D. C. 20549

FORM 10-K/A

Amendment No. 1

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

For the fiscal year ended December 31, 2003

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)

Securities registered pursuant to Section 12(b) of the Act:

Title of each class	Name of each exchange on which registered
Common Stock, par value $.10 per share	New York Stock Exchange
Rights to Purchase Preferred Stock	New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act: None

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 if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K  ¨.

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Act).    Yes  x    No  ¨

The aggregate market value of Common Stock, par value $.10 per share (“Common Stock”), held by non-affiliates (based upon the closing sales price on the New York Stock Exchange on June 30, 2003), the last business day of registrant’s most recently completed second fiscal quarter was approximately $889,100,000.

As of January 30, 2004, there were 32,390,158 shares of Common Stock outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the Proxy Statement for the Annual Meeting of Stockholders to be held April 29, 2004 are incorporated by reference into Part III of this report.

CABOT OIL & GAS CORPORATION

AMENDMENT NO. 1 TO THE 2003 ANNUAL REPORT ON FORM 10-K/A

Explanatory Note

This Amendment No. 1 to annual report on Form 10-K/A (“Form 10-K/A”) is being filed to amend the Company’s annual report on Form 10-K for the year ended December 31, 2003, which was filed with the SEC on February 18, 2004 (“Original Form 10-K”). Accordingly, pursuant to rule 12b-15 under the Securities Exchange Act of 1934, as amended, this Form 10-K/A contains the complete text of items 6, 8 and 9A of Part II and item 15 of Part IV, as amended, as well as certain currently dated certifications. Unaffected items have not been repeated in this Amendment No. 1.

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. Accordingly, we have revised our consolidated balance sheet to reflect this change in classification. The net effect of these revisions on the Company’s balance sheets at December 31, 2003 and 2002 was an increase to current assets, non-current assets, total assets, current liabilities, long-term deferred income taxes and total liabilities and stockholders’ equity. Such revisions had no impact on our Consolidated Statement of Operations, Consolidated Statement of Cash Flows, Consolidated Statement of Stockholders’ Equity or Consolidated Statement of Comprehensive Income.

The significant effects of the revisions on our consolidated balance sheets from the amounts previously reported are summarized in the following tables (in thousands of dollars):

	As of December 31, 2003
Balance Sheet Line Item	Previously Reported		As Restated		Increase
Deferred Income Taxes - Current Assets	$	—	$	21,935	$	21,935
Total Current Assets	$	121,396	$	143,331	$	21,935
Deferred Income Taxes - Non-Current Assets	$	—	$	8,920	$	8,920
Total Assets	$	1,024,201	$	1,055,056	$	30,855
Deferred Income Taxes - Current Liabilities (1)	$	—	$	1,826	$	1,826
Total Current Liabilities	$	154,701	$	156,527	$	1,826
Deferred Income Taxes - Non-Current Liabilities	$	179,926	$	208,955	$	29,029
Total Liabilities and Stockholders’ Equity	$	1,024,201	$	1,055,056	$	30,855

(1) This amount has been reported as an accrued liability on the Consolidated Balance Sheet.

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	As of December 31, 2002
Balance Sheet Line Item	Previously Reported		As Restated		Increase
Deferred Income Taxes - Current Assets	$	—	$	14,263	$	14,263
Total Current Assets	$	92,162	$	106,425	$	14,263
Deferred Income Taxes - Non-Current Assets	$	—	$	15,755	$	15,755
Total Assets	$	1,070,929	$	1,100,947	$	30,018
Deferred Income Taxes - Current Liabilities (1)	$	—	$	602	$	602
Total Current Liabilities	$	120,931	$	121,533	$	602
Deferred Income Taxes - Non-Current Liabilities	$	200,207	$	229,623	$	29,416
Total Liabilities and Stockholders’ Equity	$	1,070,929	$	1,100,947	$	30,018

(1) This amount has been reported as an accrued liability on the Consolidated Balance Sheet.

This amendment does not reflect events occurring after the filing of the Original Form 10-K, and does not modify or update the disclosures therein in any way other than as required to reflect the amendments as described above and set forth below.

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TABLE OF CONTENTS

PART II
ITEM 6	Selected Historical Financial Data	5
ITEM 8	Financial Statements and Supplementary Data	6
ITEM 9A	Controls and Procedures	42
PART IV
ITEM 15	Exhibits, Financial Statements, Schedules and Reports on Form 8-K	43

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

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ITEM 6. SELECTED HISTORICAL FINANCIAL DATA

The following table summarizes selected consolidated financial data for Cabot Oil & Gas for the periods indicated. This information should be read in conjunction with Management’s Discussion and Analysis of Financial Condition and Results of Operations, and the Consolidated Financial Statements and related Notes.

	Year Ended December 31,
(In Thousands, Except Per Share Amounts)	2003		2002		2001		2000		1999
Income Statement Data
Operating Revenues	$	509,391	$	353,756	$	447,042	$	368,651	$	294,037
Income from Operations		66,587		49,088		95,366		64,817		39,498
Net Income Available to Common Stockholders		21,132		16,103		47,084		29,221		5,117
Basic Earnings per Share	$	0.66	$	0.51	$	1.56	$	1.07	$	0.21
Dividends per Common Share	$	0.16	$	0.16	$	0.16	$	0.16	$	0.16
Balance Sheet Data
Properties and Equipment, Net	$	895,955	$	971,754	$	981,338	$	623,174	$	590,301
Total Assets (1)		1,055,056		1,100,947		1,092,810		776,353		706,887
Long-Term Debt		270,000		365,000		393,000		253,000		277,000
Stockholders’ Equity		365,197		350,657		346,552		242,505		186,496

(1) Restated to reflect the revision of deferred income taxes. See Note 2 to the Consolidated Financial Statements for further discussion.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

	Page
Report of Independent Registered Public Accounting Firm	7
Consolidated Statement of Operations for the Years Ended December 31, 2003, 2002 and 2001	8
Consolidated Balance Sheet at December 31, 2003 and 2002	9
Consolidated Statement of Cash Flows for the Years Ended December 31, 2003, 2002 and 2001	10
Consolidated Statement of Stockholders’ Equity for the Years Ended December 31, 2003, 2002 and 2001	11
Consolidated Statement of Comprehensive Income for the Years Ended December 31, 2003, 2002 and 2001	12
Notes to the Consolidated Financial Statements	13
Supplemental Oil and Gas Information (Unaudited)	38
Quarterly Financial Information (Unaudited)	42

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Report of Independent Registered Public Accounting Firm

To the Stockholders and Board of Directors of Cabot Oil & Gas Corporation:

In our opinion, the consolidated financial statements listed in the accompanying index present fairly, in all material respects, the financial position of Cabot Oil & Gas Corporation and its subsidiaries at December 31, 2003 and 2002, and the results of their operations, their cash flows and their comprehensive income for each of the three years in the period ended December 31, 2003 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management; our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

As discussed in Notes 1 and 13 to the consolidated financial statements, the Company adopted Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations” effective January 1, 2003.

As discussed in Note 12 to the consolidated financial statements, the Company adopted Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended, effective January 1, 2001.

As discussed in Note 2 to the consolidated financial statements, the Company has restated its consolidated balance sheets to correct the classification of its deferred tax assets and liabilities.

/s/ PricewaterhouseCoopers LLP

Houston, Texas

February 16, 2004, except for Note 2

as to which the date is August 6, 2004

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CABOT OIL & GAS CORPORATION

CONSOLIDATED STATEMENT OF OPERATIONS

(In thousands, except per share amounts)

	Year Ended December 31,
	2003			2002		2001
NET OPERATING REVENUES
Natural Gas Production	$	322,556		$	221,101	$	301,671
Brokered Natural Gas		95,816			58,729		90,710
Crude Oil and Condensate		81,040			67,548		47,544
Other		9,979			6,378		7,117
		509,391			353,756		447,042
OPERATING EXPENSES
Brokered Natural Gas Cost		86,162			53,007		87,785
Direct Operations - Field and Pipeline		50,399			50,047		41,217
Exploration		58,119			40,167		71,165
Depreciation, Depletion and Amortization		94,903			96,512		80,619
Impairment of Unproved Properties		9,348			9,348		7,803
Impairment of Long-Lived Assets (Note 15)		93,796			2,720		6,852
General and Administrative		25,112			28,377		27,920
Taxes Other Than Income		37,138			24,734		28,341
		454,977			304,912		351,702
Gain on Sale of Assets		12,173			244		26
INCOME FROM OPERATIONS		66,587			49,088		95,366
Interest Expense and Other		23,545			25,311		20,817
Income Before Income Taxes		43,042			23,777		74,549
Income Tax Expense		15,063			7,674		27,465
NET INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE		27,979			16,103		47,084
CUMULATIVE EFFECT OF ACCOUNTING CHANGE, NET OF TAX (Note 13)		(6,847	)		—		—
NET INCOME	$	21,132		$	16,103	$	47,084
Basic Earnings Per Share - Before Accounting Change	$	0.87		$	0.51	$	1.56
Diluted Earnings Per Share - Before Accounting Change	$	0.87		$	0.50	$	1.53
Basic Loss Per Share - Accounting Change	$	(0.21	)	$	—	$	—
Diluted Loss Per Share - Accounting Change	$	(0.21	)	$	—	$	—
Basic Earnings Per Share	$	0.66		$	0.51	$	1.56
Diluted Earnings Per Share	$	0.65		$	0.50	$	1.53
Average Common Shares Outstanding		32,050			31,737		30,276
Diluted Common Shares		32,290			32,076		30,684

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

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CABOT OIL & GAS CORPORATION

CONSOLIDATED BALANCE SHEET

(In thousands, except share amounts)

	December 31,
	2003			2002
	Restated			Restated
ASSETS
Current Assets
Cash and Cash Equivalents	$	724		$	1,602
Accounts Receivable		87,425			70,028
Inventories		18,241			15,252
Deferred Income Taxes		21,935			14,263
Other		15,006			5,280
Total Current Assets		143,331			106,425
Properties and Equipment, Net (Successful Efforts Method)		895,955			971,754
Deferred Income Taxes		8,920			15,755
Other Assets		6,850			7,013
	$	1,055,056		$	1,100,947
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Accounts Payable	$	84,943		$	72,619
Accrued Liabilities		71,584			48,914
Total Current Liabilities		156,527			121,533
Long-Term Debt		270,000			365,000
Deferred Income Taxes		208,955			229,623
Other Liabilities		54,377			34,134
Commitments and Contingencies (Note 9)
Stockholders’ Equity
Common Stock:
Authorized — 80,000,000 Shares of $.10 Par Value Issued and Outstanding — 32,538,255 Shares and 32,133,118 Shares in 2003 and 2002, Respectively		3,254			3,213
Additional Paid-in Capital		361,699			353,093
Retained Earnings		27,763			11,674
Accumulated Other Comprehensive Loss		(23,135	)		(12,939	)
Less Treasury Stock, at Cost:
302,600 Shares in 2003 and 2002		(4,384	)		(4,384	)
Total Stockholders’ Equity		365,197			350,657
	$	1,055,056		$	1,100,947

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

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CABOT OIL & GAS CORPORATION

CONSOLIDATED STATEMENT OF CASH FLOWS

(In Thousands)

	Year Ended December 31,
	2003			2002			2001
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income	$	21,132		$	16,103		$	47,084
Adjustments to Reconcile Net Income to Cash Provided by Operating Activities:
Cumulative Effect of Accounting Change		6,847			—			—
Depletion, Depreciation and Amortization		94,903			96,512			80,619
Impairment of Unproved Properties		9,348			9,348			7,803
Impairment of Long-Lived Assets		93,796			2,720			6,852
Deferred Income Tax Expense		(9,837	)		7,882			14,157
Gain on Sale of Assets		(12,173	)		(244	)		(26	)
Exploration Expense		58,119			40,167			71,165
Change in Derivative Fair Value		3,347			2,376			(177	)
Other		885			3,888			3,030
Changes in Assets and Liabilities:
Accounts Receivable		(17,397	)		(19,317	)		34,966
Inventories		(2,989	)		2,308			(6,523	)
Other Current Assets		(9,208	)		3,976			(3,524	)
Other Assets		163			(4,307	)		(515	)
Accounts Payable and Accrued Liabilities		7,041			7,342			(4,894	)
Other Liabilities		(2,339	)		(4,572	)		3,383
Net Cash Provided by Operating Activities		241,638			164,182			253,400
CASH FLOWS FROM INVESTING ACTIVITIES
Capital Expenditures		(122,018	)		(103,189	)		(127,129	)
Acquisition of Cody Company (1)		—			—			(187,785	)
Proceeds from Sale of Assets		28,281			4,688			6,829
Exploration Expense		(58,119	)		(40,167	)		(71,165	)
Net Cash Used by Investing Activities		(151,856	)		(138,668	)		(379,250	)
CASH FLOWS FROM FINANCING ACTIVITIES
Increase in Short-Term Financing		248,655			180,000			442,481
Decrease in Short-Term Financing		(341,000	)		(205,746	)		(323,700	)
Sale of Common Stock Proceeds		6,728			3,461			7,749
Dividends Paid		(5,043	)		(5,079	)		(4,802	)
Net Cash Provided (Used) by Financing Activities		(90,660	)		(27,364	)		121,728
Net Decrease in Cash and Cash Equivalents		(878	)		(1,850	)		(4,122	)
Cash and Cash Equivalents, Beginning of Period		1,602			3,452			7,574
Cash and Cash Equivalents, End of Period	$	724		$	1,602		$	3,452

⁽¹⁾ The amount excludes non-cash consideration of $49.9 million in common stock issued in connection with the acquisition of Cody Company in August 2001. This amount also excludes the $78.0 million of deferred taxes pertaining to the difference between the fair value of the assets acquired and the related tax basis. The amount includes the $181.3 million in cash consideration plus $6.4 million in capitalized acquisition costs. See Note 14, Acquisition of Cody Company.

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

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CABOT OIL & GAS CORPORATION

CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY

(In thousands)	Common Shares	Stock Par		Treasury Stock			Paid-In Capital		Accumulated Other Comprehensive Income (Loss)			Retained Earnings (Deficit)			Total
Balance at December 31, 2000	29,494	$	2,949	$	(4,384	)	$	285,572	$	—		$	(41,632	)	$	242,505
Net Income													47,084			47,084
Exercise of Stock Options	411		42					9,339								9,381
Common Stock Dividends at $0.16 per Share													(4,802	)		(4,802	)
Other Comprehensive Income										835						835
Stock Grant Vesting								1,689								1,689
Issuance of Common Stock	2,000		200					49,660								49,860
Balance at December 31, 2001	31,905	$	3,191	$	(4,384	)	$	346,260	$	835		$	650		$	346,552
Net Income													16,103			16,103
Exercise of Stock Options	209		20					3,845								3,865
Common Stock Dividends at $0.16 per Share													(5,079	)		(5,079	)
Other Comprehensive Loss										(13,774	)					(13,774	)
Stock Grant Vesting	19		2					2,988								2,990
Balance at December 31, 2002	32,133	$	3,213	$	(4,384	)	$	353,093	$	(12,939	)	$	11,674		$	350,657
Net Income													21,132			21,132
Exercise of Stock Options	345		35					7,733								7,768
Common Stock Dividends at $0.16 per Share													(5,043	)		(5,043	)
Other Comprehensive Loss										(10,196	)					(10,196	)
Stock Grant Vesting	60		6					873								879
Balance at December 31, 2003	32,538	$	3,254	$	(4,384	)	$	361,699	$	(23,135	)	$	27,763		$	365,197

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

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CABOT OIL & GAS CORPORATION

CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME

	Year Ended December 31,
(In thousands)	2003			2002			2001
Net Income Available to Common Stockholders	$	21,132		$	16,103		$	47,084
Other Comprehensive (Loss) Income
Cumulative Effect of Change in Accounting Principle on January 1, 2001		—			—			(4,269	)
Reclassification Adjustment for Settled Contracts		47,926			6,230			(32,749	)
Changes in Fair Value of Hedge Positions		(63,014	)		(26,361	)		38,380
Adjustment to Recognize Minimum Pension Liability		(1,333	)		(2,177	)		—
Foreign Currency Translation Adjustment		(5	)		—			—
Deferred Income Tax		6,230			8,534			(527	)
Total Other Comprehensive (Loss) Income		(10,196	)		(13,774	)		835
Comprehensive Income	$	10,936		$	2,329		$	47,919

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

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CABOT OIL & GAS CORPORATION

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

1. Summary of Significant Accounting Policies

Basis of Presentation and Principles of Consolidation

Cabot Oil & Gas Corporation and its subsidiaries are engaged in the exploration, development, production and marketing of natural gas and, to a lesser extent, crude oil and natural gas liquids. The Company also transports, stores, gathers and purchases natural gas for resale. The Company operates in one segment, natural gas and oil exploration and exploitation almost exclusively within the continental United States.

The consolidated financial statements contain the accounts of the Company after eliminating all significant intercompany balances and transactions.

Certain prior year amounts have been reclassified to conform to the current year presentation.

Recently Issued Accounting Pronouncements

In June 2001, the FASB approved for issuance Statement of Financial Accounting Standards (SFAS) 143, “Accounting for Asset Retirement Obligations.” SFAS 143 establishes accounting requirements for retirement obligations associated with tangible long-lived assets, including (1) the timing of the liability recognition, (2) initial measurement of the liability, (3) allocation of asset retirement cost to expense, (4) subsequent measurement of the liability and (5) financial statement disclosures. SFAS 143 requires that an asset retirement cost should be capitalized as part of the cost of the related long-lived asset and subsequently allocated to expense using a systematic and rational method. 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 assets, 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. The Company adopted the statement on January 1, 2003. The transition adjustment resulting from the adoption of SFAS 143 has been reported as a cumulative effect of a change in accounting principle in January 2003.

In December 2002, the FASB issued SFAS No. 148, “Accounting for Stock-Based Compensation – Transition and Disclosure.” SFAS 148 amends SFAS 123, “Accounting for Stock-Based Compensation”, to provide alternative methods of transition for a voluntary change to the fair value based method of accounting for stock-based employee compensation. In addition, this Statement amends the disclosure requirements of SFAS 123 to require prominent disclosures in both annual and interim financial statements about the method of accounting for stock-based employee compensation and the effect of the method used on the reported results. The provisions of SFAS 148 are effective for financial statements for fiscal years ending after December 15, 2002.

In January 2003, the FASB issued Financial Interpretation No. 46, “Consolidation of Variable Interest Entities – An Interpretation of ARB No. 51” (FIN 46 or Interpretation). FIN 46 is an interpretation of Accounting Research Bulletin 51, “Consolidated Financial Statements,” and addresses consolidation by business enterprises of variable interest entities (VIEs). The primary objective of the Interpretation is to provide guidance on the identification of, and financial reporting for, entities over which control is achieved through means other than voting rights; such entities are known as VIEs. The Interpretation requires an enterprise to consolidate a VIE if that enterprise has a variable interest that will absorb a majority of the entity’s expected losses if they occur, receive a majority of the entity’s expected residual returns if they occur or both. An enterprise shall consider the rights and obligations conveyed by its variable interests in making this determination. At December 31, 2003 the Company did not have any entities that would qualify for consolidation in accordance with the provisions of FIN 46. Therefore, the adoption of FIN 46 did not have an impact on the Company’s consolidated financial statements.

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In April 2003 the FASB issued SFAS 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities.” SFAS 149 amends and clarifies accounting for derivative instruments, including certain derivative instruments embedded in other contracts and hedging activities under SFAS 133. The amendments set forth in SFAS 149 require that contracts with comparable characteristics be accounted for similarly. SFAS 149 is generally effective for contracts entered into or modified after June 30, 2003 (with a few exceptions) and for hedging relationships designated after June 30, 2003. The guidance is to be applied prospectively only. The adoption of SFAS 149 did not have an impact on the Company’s consolidated financial statements.

In May 2003 the FASB issued SFAS 150, “Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity.” This Statement establishes standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. It requires that an issuer classify a financial instrument that is within its scope as a liability (or an asset in some circumstances). Many of those instruments were previously classified as equity. This Statement was developed in response to concerns expressed by preparers, auditors, regulators, investors, and other users of financial statements about issuers´ classification in the statement of financial position of certain financial instruments that have characteristics of both liabilities and equity but that have been presented either entirely as equity or between the liabilities section and the equity section of the statement of financial position. This Statement also addresses questions about the classification of certain financial instruments that embody obligations to issue equity shares.

In accordance with SFAS 150, companies with consolidated entities that will terminate by a specified date, such as limited-life partnerships, will have to measure the liabilities for the other owners’ interests in those limited-life entities based on the fair values of the limited-life entities’ assets. Period-to-period changes in the liabilities are to be reported in the consolidated income statement as interest costs. As a result of SFAS 150, liability amounts and related interest costs may be significantly greater than the minority interests previously recognized. This Statement is effective for financial instruments entered into or modified after May 31, 2003, and otherwise is effective at the beginning of the first interim period beginning after June 15, 2003. The adoption of this standard did not have an impact on the Company’s consolidated financial statements.

Management has been made aware of an issue regarding the application of provisions of SFAS 141, Business Combinations and SFAS No. 142, Goodwill and Other Intangible Assets ( SFAS 142 ) to companies in the extractive industries, including oil and gas companies. The issue is 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, Cabot 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 No. 69, Disclosures about Oil and Gas Producing Activities ( SFAS 69 ). Also under consideration is whether SFAS 142 requires registrants to provide the additional disclosures prescribed by SFAS 142 for intangible assets for costs associated with mineral rights.

If it is ultimately determined that SFAS 142 requires the Company to reclassify costs associated with mineral

rights from property and equipment to intangible assets, management currently believes that its results of operations and financial condition would not be affected, since such intangible assets would continue to be depleted and assessed for impairment in accordance with existing successful efforts accounting rules and impairment standards. In addition, costs associated with mineral rights would continue to be characterized as oil and gas property costs in the Company’s required disclosures under SFAS 69.

At December 31, 2003, the Company had net undeveloped leaseholds of approximately $63.0 million that would be classified on its balance sheet as intangible undeveloped leaseholds, and developed leaseholds of approximately $318.4 million (net of accumulated depletion) that would be classified as intangible developed leaseholds if the Company applied the interpretation currently being discussed.

On December 23, 2003, the FASB issued SFAS 132, “Employers’ Disclosures about Pensions and Other Postretirement Benefits,” an amendment of SFAS 87, 88, and 106, and a revision of SFAS 132. This statement revises employers’ disclosures about pension plans and other postretirement benefit plans. It does not change the measurement or recognition of those plans required by SFAS 87, “Employers’ Accounting for Pensions,” SFAS 88, “Employers’ Accounting for

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Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits,” and SFAS 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions.” The new rules require additional disclosures about the assets, obligations, cash flows, and net periodic benefit cost of defined benefit pension plans and other postretirement benefit plans. The required information should be provided separately for pension plans and for other postretirement benefit plans. The new disclosures are effective for 2003 calendar year financial statements.

Pipeline Exchanges

Natural gas gathering and pipeline operations normally include exchange arrangements with customers and suppliers. The volumes of natural gas due to or from the Company under exchange agreements are recorded at average selling or purchase prices, as the case may be, and are adjusted monthly to reflect market changes. The net value of exchanged natural gas is included in inventories in the consolidated balance sheet.

Properties and Equipment

The Company uses the successful efforts method of accounting for oil and gas producing activities. Under this method, acquisition costs for proved and unproved properties are capitalized when incurred. Exploration costs, including geological and geophysical costs, the costs of carrying and retaining unproved properties and exploratory dry hole drilling costs, are expensed. Development costs, including the costs to drill and equip development wells, and successful exploratory drilling costs to locate proved reserves are capitalized.

The impairment of unamortized capital costs is measured at a lease level and is reduced to fair value if it is determined that the sum of expected future net cash flows is less than the net book value. The Company determines if an impairment has occurred through either adverse changes or as a result of the annual review of all fields. During 2002, the Company recorded total impairments of $2.7 million. In 2003, the Company recorded impairments related to the loss of a reversionary interest in its Kurten field and a field in the East region. These impairments totaled $93.8 million.

In 2002, the Company recorded impairments on four small fields, three of which were in the Gulf Coast and one in the Rocky Mountains. For each of these fields, the capitalized cost exceeded the future undiscounted cash flows. In addition, a pipeline in the Eastern region was written down to fair market value. During 2001, the Company recorded a total impairment of $6.9 million primarily related to three Gulf Coast fields for which capitalized cost exceeded the future undiscounted cash flows. Additionally, one natural gas processing plant in the Rocky Mountains was written down to fair market value.

Capitalized costs of proved oil and gas properties, after considering estimated dismantlement, restoration and abandonment costs, net of estimated salvage values, are depreciated and depleted on a field basis by the units-of-production method using proved developed reserves. The costs of unproved oil and gas properties are generally combined and amortized over a period that is based on the average holding period for such properties and the Company’s experience of successful drilling. Properties related to gathering and pipeline systems and equipment are depreciated using the straight-line method based on estimated useful lives ranging from 10 to 25 years. Certain other assets are also depreciated on a straight-line basis.

Prior to the adoption of SFAS 143 on January 1, 2003, future estimated plug and abandonment costs were accrued over the productive life of certain oil and gas properties when the residual value of well equipment was not sufficient to cover the plug and abandonment liability. The accrued liability for plug and abandonment costs was included in accumulated depreciation, depletion and amortization. As a component of accumulated depreciation, depletion and amortization, future plug and abandonment costs were $17.1 million at December 31, 2002 and $14.4 million at December 31, 2001. The total estimated liability to plug and abandon all wells was $53.0 million at December 31, 2002 and $50.8 million at December 31, 2001, excluding the residual value of well equipment. See Note 13, “Adoption of SFAS 143, Accounting for Asset Retirement Obligations”, for additional information.

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Costs of retired, sold or abandoned properties that make up a part of an amortization base (partial field) are charged to accumulated depreciation, depletion and amortization if the units-of-production rate is not significantly affected. Accordingly, a gain or loss, if any, is recognized only when a group of proved properties (entire field) that make up the amortization base has been retired, abandoned or sold.

Revenue Recognition and Gas Imbalances

The Company applies the sales method of accounting for natural gas revenue. Under this method, revenues are recognized based on the actual volume of natural gas sold to purchasers. Natural gas production operations may include joint owners who take more or less than the production volumes entitled to them on certain properties. Production volume is monitored to minimize these natural gas imbalances. A natural gas imbalance liability is recorded in other liabilities in the consolidated balance sheet if the Company’s excess takes of natural gas exceed its estimated remaining proved reserves for these properties. See Note 4 for a listing of the Company’s liabilities for the current year ended.

Brokered Natural Gas Margin

The revenues and expenses related to brokering natural gas are reported gross as part of Operating Revenues and Operating Expenses. The Company realizes brokered margin as a result of buying and selling natural gas in back-to-back transactions. The Company realized $9.7 million, $5.7 million, and $2.9 million of brokered natural gas margin in 2003, 2002, and 2001, respectively.

Income Taxes

The Company follows the asset and liability method of accounting for income taxes. Under this method, deferred tax assets and liabilities are recorded for the estimated future tax consequences attributable to the differences between the financial carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using the tax rate in effect for the year in which those temporary differences are expected to turn around. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in the year of the enacted rate change.

Natural Gas Measurement

The Company records estimated amounts for natural gas revenues and natural gas purchase costs based on volumetric calculations under its natural gas sales and purchase contracts. Variances or imbalances resulting from such calculations are inherent in natural gas sales, production, operation, measurement, and administration. Management does not believe that differences between actual and estimated natural gas revenues or purchase costs attributable to the unresolved variances or imbalances are material.

Accounts Payable

This account includes credit balances from outstanding checks in zero balance cash accounts. The credit balance included in accounts payable was $2.7 million at December 31, 2003, which is reflected as an increase in short-term borrowings in financing activities in the Consolidated Statement of Cash Flows. There was no reclassification necessary at December 31, 2002.

Risk Management Activities

From time to time, the Company enters into derivative contracts, such as natural gas price swaps or costless price collars, as a hedging strategy to manage commodity price risk associated with its inventories, production or other contractual commitments. These transactions are executed for purposes other than trading. Gains or losses on these hedging activities are generally recognized over the period that the inventory, production or other underlying commitment is hedged as an offset to the specific hedged item. Cash flows related to any recognized gains or losses associated with these hedges are reported as cash flows from operations. If a hedge is terminated prior to expected maturity, gains or losses are deferred and included in income in the same period that the underlying production or other contractual commitment is delivered. Unrealized gains or losses associated with any derivative contract not considered a hedge would be recognized currently in the results of operations.

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A derivative instrument qualifies as a hedge if all of the following tests are met:

• The item to be hedged exposes the Company to price risk.

• The derivative reduces the risk exposure and is designated as a hedge at the time the Company enters into the contract.

• At the inception of the hedge and throughout the hedge period there is a high correlation between changes in the market value of the derivative instrument and the fair value of the underlying item being hedged.

When the designated item associated with a derivative instrument matures, is sold, extinguished or terminated, derivative gains or losses are recognized as part of the gain or loss on the sale or settlement of the underlying item. For example, in the case of natural gas price hedges, the gain or loss is reflected in natural gas revenue. When a derivative instrument is associated with an anticipated transaction that is no longer expected to occur or if correlation no longer exists, the gain or loss on the derivative is recognized currently in the results of operations to the extent the market value changes in the derivative have not been offset by the effects of the price changes on the hedged item since the inception of the hedge. See Note 12, Financial Instruments, for further discussion.

On January 1, 2001, the Company adopted SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities”, and SFAS No. 138, “Accounting for Certain Derivative Instruments and Certain Hedging Activities”. SFAS 133 requires all derivatives to be recognized in the statement of financial position as either assets or liabilities and measured at fair value. In addition, all hedging relationships must be designated, reassessed and documented according to the provisions of SFAS 133. SFAS 138 amended portions of SFAS 133 and was adopted with SFAS 133.

All hedge transactions are subject to the Company’s risk management policy which does not permit speculative positions. The Company formally documents all relationships between hedging instruments and hedged items, as well as its risk management objectives and strategy for undertaking the hedge. This process includes specific identification of the hedging instrument and the hedge transaction, the nature of the risk being hedged and how the hedging instrument’s effectiveness will be assessed. Both at the inception of the hedge and on a quarterly basis going forward, the Company assesses whether the derivatives that are used in hedging transactions are highly effective in offsetting changes in cash flows of hedged items.

Stock Based Compensation

The Company accounts for stock-based compensation in accordance with the intrinsic value based method recommended 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 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.

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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.

	Year Ended December 31,
(In thousands, except per share amounts)	2003		2002		2001
Net Income, as reported	$	21,132	$	16,103	$	47,084
Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards, net of tax		1,950		1,605		1,355
Pro forma net income	$	19,182	$	14,498	$	45,729
Earnings per share:
Basic - as reported	$	0.66	$	0.51	$	1.56
Basic - pro forma	$	0.60	$	0.46	$	1.51
Diluted - as reported	$	0.65	$	0.50	$	1.53
Diluted - pro forma	$	0.59	$	0.45	$	1.49

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

	Year Ended December 31,
(In thousands, except per share amounts)	2003			2002			2001
Compensation Expense in Net Income, as reported (1)	$	1,001		$	2,326		$	1,078
Weighted Average Value per Option Granted During the Period (2)	$	6.77		$	6.23		$	8.61
Assumptions
Stock Price Volatility		35.3	%		35.8	%		34.9	%
Risk Free Rate of Return		2.5	%		3.9	%		4.7	%
Dividend Rate (per year)	$	0.16		$	0.16		$	0.16
Expected Term (in years)		4			4			4

⁽¹⁾ Compensation expense is defined as expense related to the vesting of stock grants, net of tax. Compensation expense in 2002 includes $1.7 million related to the acceleration of stock awards due to the retirement of an executive.

⁽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 three years is not necessarily indicative of future effects on net income and earnings per share.

Cash and Cash Equivalents

The Company considers all highly liquid short-term investments with original maturities of three months or less to be cash equivalents. At December 31, 2003, and 2002, the cash and cash equivalents are primarily concentrated in one financial institution. The Company periodically assesses the financial condition of these institutions and believes that any possible credit risk is minimal.

Environmental Matters

Environmental expenditures are expensed or capitalized, as appropriate, depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations, and that do not have future economic benefit are expensed. Liabilities related to future costs are recorded on an undiscounted basis when environmental assessments and/or remediation activities are probable and the costs can be reasonably estimated. Any insurance recoveries are recorded as assets when received.

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Use of Estimates

In preparing financial statements, the Company follows generally accepted accounting principles. These principles require management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. The Company’s most significant financial estimates are based on the remaining proved oil and gas reserves (see Supplemental Oil and Gas Information). Actual results could differ from those estimates.

2. Restatement of Financial Statements

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. Accordingly, we have revised our consolidated balance sheet to reflect this change in classification. Such revisions had no impact on our Consolidated Statement of Operations, Consolidated Statement of Cash Flows, Consolidated Statement of Stockholders’ Equity or Consolidated Statement of Comprehensive Income.

The significant effects of the revisions on our consolidated balance sheets from the amounts previously reported are summarized in the following tables (in thousands of dollars):

	As of December 31, 2003
Balance Sheet Line Item	Previously Reported		As Restated
Deferred Income Taxes - Current Assets	$	—	$	21,935
Total Current Assets	$	121,396	$	143,331
Deferred Income Taxes - Non-Current Assets	$	—	$	8,920
Total Assets	$	1,024,201	$	1,055,056
Deferred Income Taxes - Current Liabilities (1)	$	—	$	1,826
Total Current Liabilities	$	154,701	$	156,527
Deferred Income Taxes - Non-Current Liabilities	$	179,926	$	208,955
Total Liabilities and Stockholders’ Equity	$	1,024,201	$	1,055,056

(1) This amount has been reported as an accrued liability on the Consolidated Balance Sheet.

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	As of December 31, 2002
Balance Sheet Line Item	Previously Reported		As Restated
Deferred Income Taxes - Current Assets	$	—	$	14,263
Total Current Assets	$	92,162	$	106,425
Deferred Income Taxes - Non-Current Assets	$	—	$	15,775
Total Assets	$	1,070,929	$	1,100,947
Deferred Income Taxes - Current Liabilities (1)	$	—	$	602
Total Current Liabilities	$	120,931	$	121,533
Deferred Income Taxes - Non-Current Liabilities	$	200,207	$	229,623
Total Liabilities and Stockholders’ Equity	$	1,070,929	$	1,100,947

(1) This amount has been reported as an accrued liability on the Consolidated Balance Sheet.

3. Properties and Equipment

Properties and equipment are comprised of the following:

	December 31,
	2003			2002
	(In Thousands)
Unproved Oil and Gas Properties	$	86,918		$	76,959
Proved Oil and Gas Properties		1,469,751			1,459,240
Gathering and Pipeline Systems		146,909			137,137
Land, Building and Improvements		4,758			4,884
Other		28,658			29,457
		1,736,994			1,707,677
Accumulated Depreciation, Depletion and Amortization		(841,039	)		(735,923	)
	$	895,955		$	971,754

During 2003 the Company divested of certain non-strategic assets. These assets include properties in Pennsylvania that were sold for $16.1 million, and resulted in a gain of $6.9 million. Additionally, the Company divested of a water treatment facility in the amount of $3.4 million, which resulted in a gain of $2.5 million.

Prior to the adoption of SFAS 143 on January 1, 2003, future estimated plug and abandonment costs were accrued over the productive life of certain oil and gas properties when the residual value of well equipment was not sufficient to cover the plug and abandonment liability. The accrued liability for plug and abandonment costs was included in Accumulated Depreciation, Depletion and Amortization. Total future plug and abandonment costs of $17.1 million and $1.1 million, recorded at December 31, 2002, have been reclassified from Accumulated Depreciation, Depletion and Amortization and Other Accrued Liabilities, respectively, to Other Long-Term Liabilities due to the adoption of SFAS 143. These reclassifications were made to conform to the current period presentation. See Note 13 for additional discussion regarding the adoption of SFAS 143.

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4. ADDITIONAL BALANCE SHEET INFORMATION

    Certain balance sheet amounts are comprised of the following:

	December 31,
	2003			2002
	(In Thousands)
Accounts Receivable
Trade Accounts	$	79,439		$	65,796
Joint Interest Accounts		13,312			6,601
Current Income Tax Receivable		—			2,479
Other Accounts		81			619
		92,832			75,495
Allowance for Doubtful Accounts		(5,407	)		(5,467	)
	$	87,425		$	70,028
Other Current Assets
Commodity Hedging Contracts - SFAS 133	$	1,152		$	634
Drilling Advances		6,443			558
Prepaid Balances		4,325			2,131
Other Accounts		3,086			1,957
	$	15,006		$	5,280
Accounts Payable
Trade Accounts	$	11,872		$	12,358
Natural Gas Purchases		5,751			6,058
Royalty and Other Owners		28,001			20,254
Capital Costs		21,964			13,900
Taxes Other Than Income		3,280			3,076
Drilling Advances		5,721			7,254
Wellhead Gas Imbalances		2,085			2,817
Other Accounts		6,269			6,902
	$	84,943		$	72,619
Accrued Liabilities
Employee Benefits	$	9,105		$	8,751
Taxes Other Than Income		13,359			9,887
Interest Payable		6,368			7,076
Commodity Hedging Contracts - SFAS 133		36,582			20,680
Deferred Income Taxes (Restated)		1,826			602
Other Accounts		4,344			1,918
	$	71,584		$	48,914
Other Liabilities
Postretirement Benefits Other Than Pension	$	2,132		$	1,843
Accrued Pension Cost		6,232			8,486
Commodity Hedging Contracts - FAS 133		3,051			—
Accrued Plugging and Abandonment Liability		36,848			18,151
Taxes Other Than Income and Other		6,114			5,654
	$	54,377		$	34,134

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5. Inventories

Inventories are comprised of the following:

	December 31,
(In thousands)	2003			2002
Natural Gas and Oil in Storage	$	15,191		$	11,519
Tubular Goods and Well Equipment		3,367			3,334
Pipeline Exchange Balances		(317	)		399
	$	18,241		$	15,252

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.

6. Debt and Credit Agreements

10.18% Notes

In May 1990, the Company issued an aggregate principal amount of $80 million of its 12-year 10.18% Notes (10.18% Notes) to a group of nine institutional investors in a private placement offering. The 10.18% Notes required five annual $16 million principal payments each May starting in 1998. The Company paid the outstanding principal balance of $32 million, together with accrued interest and a $0.9 million prepayment penalty (which was recorded as a component of interest expense) in May 2001.

7.19% Notes

In November 1997, the Company issued an aggregate principal amount of $100 million of its 12-year 7.19% Notes (7.19% Notes) to a group of six institutional investors in a private placement offering. The 7.19% Notes require five annual $20 million principal payments starting in November 2005. The Company may prepay all or any portion of the indebtedness on any date with a prepayment penalty. The 7.19% Notes contain restrictions on the merger of the Company or any subsidiary with a third party other than under certain limited conditions. There are also various other restrictive covenants customarily found in such debt instruments. These covenants include a required asset coverage ratio (present value of proved reserves to debt and other liabilities) that must be at least 1.5 to 1.0, and a minimum annual coverage ratio of operating cash flow to interest expense for the trailing four quarters of 2.8 to 1.0.

7.33% Weighted Average Fixed Rate Notes

To partially fund the cash portion of the acquisition of Cody Company in August 2001, the Company issued $170 million of Notes to a group of seven institutional investors in a private placement transaction in July 2001. Prior to the determination of the Note’s interest rates, the Company entered into a treasury lock in order to reduce the risk of rising interest rates. Interest rates rose during the pricing period, resulting in a $0.7 million gain that will be amortized over the life of the Notes, and thereby reducing the effective interest rate by 5.5 basis points. All of the Notes have bullet maturities and were issued in three separate tranches as follows:

	Principal		Term	Coupon
Tranche 1	$	75,000,000	10-year	7.26	%
Tranche 2	$	75,000,000	12-year	7.36	%
Tranche 3	$	20,000,000	15-year	7.46	%

The Notes were issued under the same Note Purchase Agreement as the 7.19% Notes.

Revolving Credit Agreement

The Company has a $250 million Revolving Credit Agreement (Credit Facility) that utilizes nine banks. The term of the Credit Facility expires in October 2006. The available credit line is subject to adjustment from time to time on

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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 three 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-third of the excess during each of the three months.

Interest rates under the Credit Facility are based on Euro-Dollars (LIBOR) or Base Rate (Prime) indications, plus a margin. These associated margins are subject to increase if the total indebtedness is either greater than 60% or 80% of the Company’s debt limit of $520 million, as shown below.

	Debt Percentage
	Lower than 60%		60% - 80%		Higher than 80%
Euro-Dollar margin	1.250	%	1.500	%	1.750	%
Base Rate margin	0.250	%	0.500	%	0.750	%

The Company’s effective interest rates for the Credit Facility in the years ended December 31, 2003, 2002, and 2001 were 1.9%, 3.4%, and 7.6%, respectively. The Credit Facility provides for a commitment fee on the unused available balance at an annual rate of three-eighths of 1%. The Credit Facility also contains various customary restrictions, which include the following:

(a) Maintenance of a minimum asset coverage ratio (present value of proved reserves to debt and other liabilities) that must be at least 1.5 to 1.0.

(b) Maintenance of a minimum annual coverage ratio of operating cash flow to interest expense for the trailing four quarters of 2.8 to 1.0.

(c) Prohibition on the merger or sale of all, or substantially all, of the Company’s or any subsidiary’s assets to a third party, except under certain limited conditions.

(d) The aggregate level of commodity hedging must not exceed 80% of the anticipated future production during the period covered by the hedges.

The Company was in compliance with all covenants at December 31, 2003 and 2002.

7. Employee Benefit Plans

Pension Plan

The Company has a non-contributory, defined benefit pension plan for all full-time employees. Plan benefits are based primarily on years of service and salary level near retirement. Plan assets are mainly fixed income investments and equity securities. The Company complies with the Employee Retirement Income Security Act of 1974 and Internal Revenue Code limitations when funding the plan. The measurement date used to measure pension benefit amounts is December 31, 2003.

The Company has a non-qualified equalization plan to ensure payments to certain executive officers of amounts to which they are already entitled under the provisions of the pension plan, but which are subject to limitations imposed by federal tax laws. This plan is unfunded.

Net periodic pension cost of the Company during the last three years are comprised of the following:

(In thousands)	2003			2002			2001
Qualified
Current Year Service Cost	$	1,481		$	1,056		$	914
Interest Accrued on Pension Obligation		1,515			1,362			1,198
Expected Return on Plan Assets		(999	)		(991	)		(1,064	)
Net Amortization and Deferral		88			88			88
Recognized Loss (Gain)		415			21			(28	)
Net Periodic Pension Cost	$	2,500		$	1,536		$	1,108

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(In thousands)	2003		2002		2001
Non-Qualified
Current Year Service Cost	$	280	$	78	$	88
Interest Accrued on Pension Obligation		163		29		72
Net Amortization		77		77		77
Loss Recognized from Settlement		—		963		—
Recognized Loss		187		7		21
Net Periodic Pension Cost	$	707	$	1,154	$	258

The following table illustrates the funded status of the Company’s pension plans at December 31:

	2003						2002
(In thousands)	Qualified			Non-Qualified			Qualified			Non-Qualified
Actuarial Present Value of:
Accumulated Benefit Obligation	$	21,347		$	3,171		$	18,136		$	338
Projected Benefit Obligation	$	27,411		$	6,136		$	23,530		$	2,511
Plan Assets at Fair Value		18,683			—			10,279			—
Projected Benefit Obligation in Excess of Plan Assets		8,728			6,136			13,251			2,511
Unrecognized Net Loss		(7,083	)		(5,457	)		(7,283	)		(2,462	)
Unrecognized Prior Service Cost		(336	)		(399	)		(424	)		(475	)
Adjustment to Recognize Minimum Liability		1,355			2,891			2,313			764
Accrued Pension Cost	$	2,664		$	3,171		$	7,857		$	338

The change in the combined projected benefit obligation of the Company’s qualified and non-qualified pension plans during the last three years is explained as follows:

(In thousands)	2003			2002			2001
Beginning of Year	$	26,042		$	19,894		$	17,151
Service Cost		1,761			1,134			1,002
Interest Cost		1,678			1,391			1,270
Actuarial Loss		4,679			5,860			1,166
Benefits Paid		(613	)		(2,237	)		(695	)
End of Year	$	33,547		$	26,042		$	19,894

The change in the combined plan assets at fair value of the Company’s qualified and non-qualified pension plans during the last three years is explained as follows:

(In thousands)	2003			2002			2001
Beginning of Year	$	10,279		$	9,909		$	11,801
Actual Return on Plan Assets		2,446			(1,280	)		(1,527	)
Employer Contribution		6,735			4,080			584
Benefits Paid		(613	)		(2,237	)		(695	)
Expenses Paid		(164	)		(193	)		(254	)
End of Year	$	18,683		$	10,279		$	9,909

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The reconciliation of the combined funded status of the Company’s qualified and non-qualified pension plans at the end of the last three years is explained as follows:

(In thousands)	2003			2002			2001
Funded Status	$	14,864		$	15,762		$	9,985
Unrecognized Gain (Loss)		(12,540	)		(9,745	)		(2,413	)
Unrecognized Prior Service Cost		(735	)		(899	)		(1,064	)
Net Amount Recognized	$	1,589		$	5,118		$	6,508
Accrued Benefit Liability – Qualified Plan	$	2,664		$	7,857		$	6,423
Accrued Benefit Liability – Non-Qualified Plan		3,171			338			816
Intangible Asset		(4,246	)		(3,077	)		(731	)
Net Amount Recognized	$	1,589		$	5,118		$	6,508

Assumptions used to determine projected post-retirement benefit obligations and pension costs are as follows:

	2003		2002		2001
Discount Rate (1)	6.25	%	6.50	%	7.25	%
Rate of Increase in Compensation Levels	4.00	%	4.00	%	4.00	%
Long-Term Rate of Return on Plan Assets	8.00	%	9.00	%	9.00	%
Health Care Cost Trend for Medical Benefits	8.00	%	8.00	%	8.00	%

⁽¹⁾ Represents the rate used to determine the benefit obligation. A 6.50% discount rate was used to compute pension costs in 2003, a rate of 7.25% in 2002, and a rate of 7.50% was used in 2001.

The long-term expected rate of return used in 2003 is eight percent. The Company establishes the long-term expected rate of return by developing a forward looking long-term expected rate of return assumption for each asset class, taking into account factors such as the expected real return for the specific asset class and inflation.

The plan assets of the Company’s qualified and non-qualified pension plans at December 31, 2003 and 2002, by asset category are as follows:

	2003				2002
(In thousands)	Amount		Percent		Amount		Percent
Equity securities	$	11,722	63	%	$	7,059	69	%
Debt securities		3,349	18	%		3,012	29	%
Other (1)		3,612	19	%		208	2	%
Total	$	18,683	100	%	$	10,279	100	%

⁽¹⁾ Primarily consists of cash and cash equivalents.

The Company’s investment strategy for benefit plan assets is to invest in funds to maximize a return over the long-term, subject to an appropriate level of risk, and to achieve a minimum five percent annual real rate of return on the total portfolio. Additionally, the objective of the equity portion of the pension plan assets is to have a rate of return that exceeds the Standard & Poors 500 index by a minimum of two percent annually over the long-term. To achieve these objectives assets are invested with a range of 60 percent to 80 percent equity and 20 percent to 40 percent fixed income.

The funding levels of the pension plans are in compliance with standards set by applicable law or regulation. 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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Savings Investment Plan

The Company has a Savings Investment Plan (SIP) which is a defined contribution plan. The Company matches a portion of employees’ contributions in cash. Participation in the SIP is voluntary and all regular employees of the Company are eligible to participate. The Company charged to expense plan contributions of $1.4 million, $1.3 million, and $1.0 million in 2003, 2002, and 2001, respectively. The plan contribution rose in 2003, 2002 and 2001 due to an increase in the Company’s matching program. Effective July 1, 2001, the Company increased its dollar-for-dollar matching limit from 4% to 6% of an employee’s pretax earnings. The Company’s Common Stock is an investment option within the SIP.

Deferred Compensation Plan

In 1998, the Company established a Deferred Compensation Plan. This plan is available to officers of the Company and acts as a supplement to the Savings Investment Plan. The Company matches a portion of the employee’s contribution and those assets are invested in instruments selected by the employee. Unlike the SIP, the Deferred Compensation Plan does not have dollar limits on tax deferred contributions. However, the assets of this plan are held in a rabbi trust and are subject to additional risk of loss in the event of bankruptcy or insolvency of the Company. At December 31, 2003, the balance in the Deferred Compensation Plan’s rabbi trust was $3.6 million.

The employee participants guide the diversification of trust assets. The trust assets are invested in mutual funds that cover the investment spectrum from equity to money market. These mutual funds are publicly quoted and reported at market value. No shares of the Company’s stock are held by the trust. Settlement payments are made to participants in cash, either in a lump sum or in periodic installments. The market value of the trust assets is recorded on the Company’s balance sheet as a component of Other Assets and the corresponding liability is recorded as a component of Other Liabilities.

There is no impact on earnings or earnings per share from the changes in market value of the deferred compensation plan assets for two reasons. First, the changes in market value of the trust assets are offset completely by changes in the value of the liability, which represents trust assets belonging to plan participants. Second, no shares of the Company’s stock are held in the trust.

The Company charged to expense plan contributions of less than $20,000 in each year presented.

Postretirement Benefits Other than Pensions

In addition to providing pension benefits, the Company provides certain health care and life insurance benefits for retired employees, including their spouses, eligible dependents and surviving spouses (retirees). These benefits are commonly called postretirement benefits. Most employees become eligible for these benefits if they meet certain age and service requirements at retirement. The Company was providing postretirement benefits to 244 retirees at the end of 2003 and 246 retirees at the end of 2002. The measurement date used to measure postretirement benefits other than pensions is December 31, 2003.

On December 8, 2003, the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the Act) was signed into law. The Act introduces a prescription drug benefit under Medicare as well as a federal subsidy to sponsors of retiree health care benefit plans that provide a benefit that is at least actuarially equivalent to certain Medicare benefits. In accordance with FASB Staff Position 106-1, Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003, any measures of the accumulated plan benefit obligation or net periodic postretirement benefit cost in the financial statements or accompanying notes do not reflect the effects of the Act on the Company’s plan. Specific authoritative guidance on the accounting for the federal subsidy is pending and that guidance, when issued, could require the Company to change previously reported information. Currently, management is considering the impact of this Act on the Company’s plan and the possible economic consequences. However, management does not believe the accounting treatment will have a material impact on the consolidated financial statements of the Company.

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When the Company adopted SFAS 106, “Employers’ Accounting for Postretirement Benefits Other Than Pension”, in 1992, it began amortizing the $16.9 million accumulated postretirement benefit, known as the Transition Obligation, over a period of 20 years.

Postretirement benefit costs recognized during the last three years are as follows:

(In thousands)	2003			2002			2001
Service Cost of Benefits Earned During the Year	$	265		$	215		$	175
Interest Cost on the Accumulated Postretirement Benefit Obligation		385			381			388
Amortization Benefit of the Unrecognized Gain		(155	)		(267	)		(291	)
Amortization Benefit of the Unrecognized Transition Obligation		662			662			662
Total Postretirement Benefit Cost	$	1,157		$	991		$	934

The health care cost trend rate used to measure the expected cost in 2000 for medical benefits to retirees was 8%. Provisions of the plan should prevent significant future increases in employer cost after 2000.

A one-percentage-point increase or decrease in health care cost trend rates for future periods would not have a material impact on the accumulated net postretirement benefit obligation or the total postretirement benefit cost recognized. Company costs are substantially capped at 2000 levels and the retirees assume the majority of any future increases in costs.

The funded status of the Company’s postretirement benefit obligation at December 31, 2003, and 2002 is comprised of the following:

(In thousands)	2003			2002
Plan Assets at Fair Value	$	—		$	—
Accumulated Postretirement Benefits Other Than Pensions		6,181			6,185
Unrecognized Cumulative Net Gain		1,736			2,113
Unrecognized Transition Obligation		(5,293	)		(5,955	)
Accrued Postretirement Benefit Liability	$	2,624		$	2,343

The change in the accumulated postretirement benefit obligation during the last three years is presented as follows:

(In thousands)	2003			2002			2001
Beginning of Year	$	6,185		$	5,507		$	5,429
Service Cost		265			215			175
Interest Cost		386			381			388
Actuarial Loss		221			912			265
Benefits Paid		(876	)		(830	)		(750	)
End of Year	$	6,181		$	6,185		$	5,507

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8. Income Taxes

Income tax expense is summarized as follows:

	Year Ended December 31,
(In thousands)	2003			2002			2001
Current
Federal	$	22,826	(1)	$	(1,158	)(1)	$	10,984	(1)
State		2,075			869			496
Total		24,901			(289	)		11,480
Deferred
Federal		(8,549	)		7,931			13,723
State		(1,289	)		32			2,262
Total		(9,838	)		7,963			15,985
Total Income Tax Expense	$	15,063		$	7,674		$	27,465

⁽¹⁾ Federal Income Taxes Payable is $2.7 million at December 31, 2003 and zero at December 31, 2002 and 2001. The zero balances are primarily due to tax payments made during 2002 and 2001 overpayments applied to the current year.

Total income taxes were different than the amounts computed by applying the statutory federal income tax rate as follows:

	Year Ended December 31,
(In thousands)	2003			2002			2001
Statutory Federal Income Tax Rate		35	%		35	%		35	%
Computed “Expected” Federal Income Tax	$	15,065		$	8,322		$	26,092
State Income Tax, Net of Federal Income Tax Benefit		1,334			737			2,758
Other, Net		(1,336	)(1)		(1,385	)(2)		(1,385	)(3)
Total Income Tax Expense	$	15,063		$	7,674		$	27,465

⁽¹⁾ Other, Net includes credit adjustments of $0.8 million related to the recognition of benefit for a state statutory depletion in excess of basis and $0.5 million related to the recognition of a benefit for a state net operating loss.

⁽²⁾ Other, Net includes credit adjustments totaling $0.8 million to deferred taxes as a result of a reduction to the state effective tax rate,$0.8 million to deferred taxes as a result of basis adjustments related to the Cody acquisition, and other permanent items.

⁽³⁾ Other, Net includes credit adjustments totaling $1.7 million to deferred taxes as a result of a reduction to the state effective tax rate and other permanent items.

The tax effects of temporary differences that resulted in significant portions of the deferred tax liabilities and deferred tax assets as of December 31 were as follows:

(In thousands)	2003		2002
	Restated		Restated
Deferred Tax Liabilities
Property, Plant and Equipment	$	208,955	$	229,623
Items Accrued for Financial Reporting Purposes		1,826		602
Deferred Tax Assets
Alternative Minimum Tax Credit Carryforwards		—		12,083
Net Operating Loss Carryforwards		725		746
Items Accrued for Financial Reporting Purposes		11,679		9,182
Other Comprehensive Income		18,451		8,007
		30,855		30,018
Net Deferred Tax Liabilities	$	179,926	$	200,207

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As of December 31, 2003, the Company had a net operating loss carryforward of $14.2 million for state income tax reporting purposes, the majority of which will expire between 2010 and 2018 and none available for regular federal income tax purposes. The Company does not have any alternative minimum tax credit carryforwards available at December 31, 2003 to offset regular income taxes in future years.

9. Commitments and Contingencies

Lease Commitments

The Company leases certain transportation vehicles, warehouse facilities, office space, and machinery and equipment under cancelable and non-cancelable leases. The lease for the Company’s office in Houston runs for approximately six more years. Most of the Company’s leases expire within five years and may be renewed. Rent expense under such arrangements totaled $8.5 million, $8.8 million, and $7.7 million for the years ended December 31, 2003, 2002, and 2001, respectively.

Future minimum rental commitments under non-cancelable leases in effect at December 31, 2003 are as follows:

(In thousands)
2004	$	4,650
2005		4,275
2006		3,791
2007		3,538
2008		2,481
Thereafter		606
	$	19,341

Contingencies

The Company is a defendant in various lawsuits and is involved in other gas contract issues. All known liabilities are fully accrued based on management’s best estimate of the potential loss. In management’s opinion, final judgments or settlements, if any, which may be awarded in connection with any one or more of these suits and claims would not have a significant impact on the results of operations, financial position or cash flows of any period.

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 under the Wyoming Rules of Civil Procedure and alleged that the Company improperly deducted costs of production from royalty payments to the plaintiffs and other similarly situated persons. Additionally, the suit claimed that the Company 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 was recently able to settle the case and the State District Court Judge recently entered his order approving the settlement. The settlement was for a total of $2.25 million. 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.

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. That case is on hold awaiting a Wyoming Supreme Court decision on two certified questions.

Although management believes that a number of the Company’s defenses are supported by Wyoming case law, two letter decisions handed down by state district court judges in other cases do not support certain of the defenses. In one of the cases the case has been settled so no order will be entered. In the other case a generic order has been entered adopting the

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letter decision by reference. It is not known what effect, if any, the decision, will have on the pending case. In addition, in 2000 a district court judge’s decision supported the defenses of the Company, and that decision was recently orally confirmed by another state district court judge. Accordingly, there is a split of authority concerning the interpretation of the reporting penalty provisions of the Wyoming Royalty Payment Act, which will need to be resolved by the Wyoming Supreme Court.

As noted above, the judge agreed to certify two questions of state law for decision by the Wyoming State Supreme Court. The Wyoming State Supreme Court has agreed to decide both questions, and these decisions should dispose of important issues in the pending federal case. The federal judge refused, however, 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 the Company’s position in the state district court letter decision. 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 can be broken down into $15.7 million for alleged violations of the check stub reporting statute and the remainder for all other damages. In the opinion of our outside counsel, Brown, Drew & Massey, LLP the likelihood of the plaintiffs recovering the stated damages for violation of the check stub reporting statute is remote.

The Company is vigorously defending the case. The Company has a reserve that management believes is adequate to provide for the potential liability based on its estimate of the probable outcome of this case. Should circumstances change, the potential impact may materially affect quarterly or annual results of operations and cash flows. However, management does not believe it would materially impact our financial position.

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 the Company has taken improper deductions from the royalty and has 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.

The Company had removed the lawsuit to federal court; however, in February 2003, we received an order remanding the lawsuit back to state court. 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 March 29, 2004. Based on the current status of discovery, the trial date is likely to be continued at a later date.

The investigation into this claim continues and it is in the discovery phase. The Company is vigorously defending the case. The Company has reserves it believes are adequate to provide for these potential liabilities based on its estimate of the probable outcome of this matter. Should circumstances change, the potential impact may materially affect quarterly or annual results of operations and cash flows. However, management does not believe it would materially impact the Company’s financial position.

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 trial date of May 19, 2003 was

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cancelled and a new trial date has 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 $35 million. Co-defendants Shell Oil Company and Shell Western E&P have filed a motion for summary judgment seeking dismissal of plaintiffs’ causes of action on multiple grounds. The Company was in the process of joining in that motion, when the 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 held in December 2003. The Court has permitted plaintiffs additional time to gather more information, and it is anticipated that the court will hold a second hearing on the motion. The Company has joined in the motion.

Although the investigation into this claim has just begun, the Company intends to vigorously defend the case. Management cannot currently determine the likelihood or range of any potential outcome.

10. Cash Flow Information

Cash paid for interest and income taxes is as follows:

	Year Ended December 31,
(In thousands)	2003		2002		2001
Interest	$	18,298	$	25,112	$	16,295
Income Taxes	$	19,267	$	266	$	14,395

For the year ended December 31, 2003, the Company recorded a benefit of $2.7 million for a tax deduction taken due to employee stock option exercises.

11. Capital Stock

Incentive Plans

On May 3, 2001, the Second Amended and Restated 1994 Long-Term Incentive Plan and the Second Amended and Restated 1994 Non-Employee Director Stock Option Plan were approved by the shareholders. Under these two plans (Incentive Plans), incentive and non-statutory stock options, stock appreciation rights (SARs) and stock awards may be granted to key employees and officers of the Company, and non-statutory stock options may be granted to non-employee directors of the Company. A maximum of 4,200,000 shares of Common Stock may be issued under the Incentive Plans. There are no shares available for award under any previous equity plan. All stock options awarded under the Incentive Plans have a maximum term of five years from the date of grant, vesting over time. The options are issued at market value on the date of grant. No SARs have been granted under the Incentive Plans.

Information regarding the Company’s Incentive Plans is summarized below:

	December 31,
	2003	2002	2001
Shares Under Option at Beginning of Period	1,287,829	1,081,621	1,124,148
Granted	467,000	429,300	454,100
Exercised	345,386	181,027	408,949
Surrendered or Expired	59,942	42,065	87,678
Shares Under Option at End of Period	1,349,501	1,287,829	1,081,621
Options Exercisable at End of Period	511,719	570,406	355,778

For each of the three most recent years, the price range for outstanding options was $17.44 to $27.30 per share. The following tables provide more information about the options by exercise price and year.

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Options with exercise prices between $17.44 and $20.00 per share:

	December 31,
	2003		2002		2001
Options Outstanding
Number of Options		444,668		737,385		480,561
Weighted Average Exercise Price	$	19.22	$	18.97	$	17.79
Weighted Average Contractual Term (in years)		2.6		3.0		1.5
Options Exercisable
Number of Options		204,229		301,277		211,734
Weighted Average Exercise Price	$	19.04	$	18.39	$	17.29

Options with exercise prices between $20.01 and $27.30 per share:

	December 31,
	2003		2002		2001
Options Outstanding
Number of Options		904,833		550,444		601,060
Weighted Average Exercise Price	$	24.69	$	25.81	$	25.44
Weighted Average Contractual Term (in years)		3.4		3.0		4.3
Options Exercisable
Number of Options		307,490		269,129		144,044
Weighted Average Exercise Price	$	26.42	$	25.39	$	22.45

Dividend Restrictions

The Board of Directors of the Company determines the amount of future cash dividends, if any, to be declared and paid on the Common Stock depending on, among other things, the Company’s financial condition, funds from operations, the level of its capital and exploration expenditures, and its future business prospects. None of the note or credit agreements in place have a restricted payment provision.

Treasury Stock

In August 1998, the Board of Directors authorized the Company to repurchase up to two million shares of outstanding Common Stock at market prices. The timing and amount of these stock purchases are determined at the discretion of management. The Company may use the repurchased shares to fund stock compensation programs presently in existence, or for other corporate purposes. As of December 31, 1998, the Company had repurchased 302,600 shares, or 15% of the total authorized number of shares, for a total cost of approximately $4.4 million. No additional shares have been repurchased. The stock repurchase plan was funded from increased borrowings on the revolving credit facility. No treasury shares have been delivered or sold by the Company subsequent to the repurchase.

Purchase Rights

On January 21, 1991, the Board of Directors adopted the Preferred Stock Purchase Rights Plan and declared a dividend distribution of one right for each outstanding share of Common Stock. On December 8, 2000, the rights agreement for the plan was amended and restated to extend the term of the plan to 2010 and to make other changes. Each right becomes exercisable, at a price of $55, when any person or group has acquired or made a tender or exchange offer for beneficial ownership of 15% or more of the Company’s outstanding Common Stock. Each right entitles the holder, other than the acquiring person or group, to purchase one one-hundredth of a share of Series A Junior Participating Preferred Stock (Junior Preferred Stock). After a person or group acquires beneficial ownership of 15% of the Common Stock, each right entitles the holder to purchase Common Stock or other property having a market value (as defined in the plan) of twice the exercise price of the right. An exception to this triggering event applies in the case of a tender or exchange offer for all outstanding shares of Common Stock determined to be fair and in the best interests of the Company and its stockholders by a majority of the independent directors. Under certain circumstances, the Board of Directors may opt to exchange one share of Common Stock for each exercisable

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right. If there is a 15% holder and the Company is acquired in a merger or other business combination in which it is not the survivor, or 50% or more of the Company’s assets or earning power are sold or transferred, each right entitles the holder to purchase common stock of the acquiring company with a market value (as defined in the plan) equal to twice the exercise price of each right. At December 31, 2003 there were no shares of Junior Preferred Stock issued or outstanding.

The rights expire on January 21, 2010, and may be redeemed by the Company for $0.01 per right at any time before a person or group acquires beneficial ownership of 15% of the Common Stock.

12. Financial Instruments

The estimated fair value of financial instruments is the amount at which the instrument could be exchanged currently between willing parties. The carrying amounts reported in the consolidated balance sheet for cash and cash equivalents, accounts receivable, and accounts payable approximate fair value. The Company uses available marketing data and valuation methodologies to estimate fair value of debt. This disclosure is presented in accordance with SFAS 107, “Disclosures about Fair Value of Financial Instruments” and does not impact the Company’s financial position, results of operations or cash flows.

Long-Term Debt

	December 31, 2003				December 31, 2002
(In thousands)	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Debt
7.19% Notes	$	100,000	$	113,673	$	100,000	$	113,591
7.26% Notes		75,000		87,345		75,000		84,231
7.36% Notes		75,000		87,770		75,000		86,461
7.46% Notes		20,000		24,214		20,000		23,322
Credit Facility		—		—		95,000		95,000
	$	270,000	$	313,002	$	365,000	$	402,605

The fair value of long-term debt is the estimated cost to acquire the debt, including a premium or discount for the difference between the issue rate and the year-end market rate. The fair value of the 7.19% Notes, the 7.26% Notes, the 7.36% Notes and the 7.46% Notes is based on interest rates currently available to the Company. The Credit Facility approximates fair value because this instrument bears interest at rates based on current market rates.

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 December 31, 2003, the Company had 32 cash flow hedges open: 15 natural gas price collar arrangements and 17 natural gas price swap arrangements. Additionally, the Company had four crude oil financial instruments and one natural gas financial instrument open at December 31, 2003, that did not qualify for hedge accounting under SFAS 133. At December 31, 2003, a $33.9 million ($21.0 million net of tax) unrealized loss was recorded to Other Comprehensive Income, along with a $39.6 million derivative liability and a $1.2 million derivative receivable. The change in derivative fair value for the current and prior periods have been included as a component of Natural Gas Production and Crude Oil and Condensate revenue, as appropriate.

The following table summarizes the realized and unrealized impact of derivative activity reflected in the respective line item in Operating Revenues.

	Year Ended December 31,
	2003						2002						2001
	Realized			Unrealized			Realized			Unrealized			Realized		Unrealized
Operating Revenues - Increase / (Decrease) to Revenue
Natural Gas Production	$	(48,829	)	$	(1,468	)	$	(574	)	$	(1,683	)	$	33,840	$	177
Crude Oil	$	(3,963	)	$	(1,879	)	$	(5,202	)	$	(693	)	$	—	$	—

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Assuming no change in commodity prices, after December 31, 2003 the Company would reclassify to earnings, over the next 12 months, $20.3 million in after-tax expenditures associated with commodity derivatives. This reclassification represents the net liability associated with open positions at December 31, 2003 related to anticipated 2004 production.

Hedges on Production - Swaps

From time to time, the Company enters 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, the Company receives 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 the Company’s Revolving Credit Agreement, the aggregate level of commodity hedging must not exceed 80% of the anticipated future equivalent production during the period covered by the hedges. During 2003, natural gas price swaps covered 34,806 Mmcf, or 48% of our gas production, fixing the sales price of this gas at an average of $4.49 per Mcf.

At December 31, 2003, the Company 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)
As of December 31, 2003
Natural Gas Price Swaps on Production in:
First Quarter 2004	8,017	$	5.17
Second Quarter 2004	7,148		4.99
Third Quarter 2004	7,226		4.99
Fourth Quarter 2004	7,226		4.99
Full Year 2004	29,617	$	5.04	$	24,610
First Quarter 2005	2,510	$	5.13
Second Quarter 2005	2,537		5.13
Third Quarter 2005	2,565		5.13
Fourth Quarter 2005	2,565		5.13
Full Year 2005	10,177	$	5.13	$	2,284

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 December 31, 2003, the Company had four open crude oil swap arrangements and one natural gas swap arrangement with an unrealized net loss of $2.6 million and $0.8 million, respectively, recognized in Operating Revenues.

Hedges on Production - Options

Throughout 2002 and 2003, the Company believed that the pricing environment provided a strategic opportunity to significantly reduce the price risk on a portion of our production through the use of natural gas and crude oil collars. Under the collar arrangements, if the index price rises above the ceiling price, the Company pays the counterparty. If the index falls below the floor price, the counterparty pays the Company.

During 2003, natural gas price collars covered 16,136 Mmcf, or 22% of the Company’s gas production, with a weighted average floor of $4.46 per Mcf and a weighted average ceiling of $5.41 per Mcf. Additionally, during 2003, the Company had crude oil price collars which covered 362 Mbbls, or 25% of the Company’s production, with a weighted average floor of $24.75 per bbl and a weighted average ceiling of $28.86 per bbl. These crude oil contracts expired in June 2003.

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At December 31, 2003, the Company 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)
As of December 31, 2003
Natural Gas Price Collars on Production in:
First Quarter 2004	8,835	$	6.55 / $5.36
Second Quarter 2004	4,672	$	5.75 / $4.41
Third Quarter 2004	4,723	$	5.75 / $4.41
Fourth Quarter 2004	4,723	$	5.75 / $4.41
Full Year 2004	22,953	$	6.06 / $4.78	$	7,447
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	$	767

At December 31, 2003, the Company had no open crude oil price collar arrangements to cover future production.

The Company is 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.

Adoption of SFAS 133

The Company adopted SFAS 133 on January 1, 2001. 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.

Credit Risk

Although notional contract amounts are used to express the volume of natural gas price agreements, the amounts that can be subject to credit risk in the event of non-performance by third parties are substantially smaller. The Company does not anticipate any material impact on its financial results due to non-performance by the third parties.

In 2003, approximately 11% of the Company’s total sales were made to one customer. In 2002, approximately 14% of the Company’s total sales were made to one customer. In 2002, this customer operated certain properties in which the Company has interests in the Gulf Coast and purchased all of the production from these wells. This customer would resell the natural gas and oil to third parties with whom the Company would deal directly if the customer either ceased to exist or stopped buying its portion of the production. In 2001 the Company had no sales to any customer that exceeded 10% of its total gross revenues.

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13. 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 assets useful life. The adoption of SFAS 143 resulted in an increase of total liabilities because additional retirement obligations are required to be recognized, an increase in the recognized cost of assets because the retirement costs are added to the carrying amount of the long-lived asset and 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 December 31, 2003 there are 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 of 2003, of approximately $6.8 million ($11.0 million before tax) and recorded a retirement obligation of approximately $35.2 million. There will be no impact on the Company’s cash flows as a result of adopting SFAS 143.

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. Accretion expense for the year-ended December 31, 2003 was $2.1 million.

The following unaudited pro forma information has been prepared to give effect to the adoption of SFAS 143 as if it had been adopted on January 1, 2002 and January 1, 2001.

	Year Ended December 31,
	2003		2002		2001
	(In Thousands)
	(Except Per Share Amounts)
Net Income	$	21,132	$	15,077	$	46,171
Per Share - Basic	$	0.66	$	0.48	$	1.52
Per Share - Diluted	$	0.65	$	0.47	$	1.50

14. Other Revenue

Section 29 Tax Credits

Other revenue includes income generated from the monetization of the value of Section 29 tax credits (monetized credits) from most of the Company’s qualifying Eastern and Rocky Mountains properties. Due to the repurchase of these tax credit wells in December 2002 there was no monetization revenue realized in 2003. Revenue from these monetized credits was $2.0 million in 2002 and 2001. The production, revenues, expenses and proved reserves for these properties was reported by the Company as Other Revenue until the credits were repurchased in December 2002. In this repurchase transaction, the Company acquired 26 Bcfe for $7 million, or $0.27 per Mcfe. The effective date of the repurchase was December 31, 2002.

15. Acquisition of Cody Company

In August 2001, the Company acquired the stock of Cody Company, the parent of Cody Energy LLC (Cody acquisition) for $231.2 million consisting of $181.3 million of cash and 1,999,993 shares of common stock valued at $49.9 million. Substantially all of the proved reserves of Cody Company are located in the onshore Gulf Coast region. The acquisition was accounted for using the purchase method of accounting. As such, the Company reflected the assets and liabilities acquired at fair value in the Company’s balance sheet effective August 1, 2001 and the results of operations of Cody Company beginning August 1, 2001. The Company recorded a purchase price of approximately $315.6 million, which was allocated to specific assets and liabilities based on certain estimates of fair value resulting in approximately $302.4

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million allocated to property and $13.2 million allocated to working capital items. The remaining $78.0 million of the recorded purchase price reflected a non-cash item pertaining to the deferred income taxes attributable to the differences between the tax basis and the fair value of the acquired oil and gas properties, and acquisition related fees and costs of $6.4 million.

The following unaudited pro forma condensed income statement information for the year ended December 31, 2001 has been prepared to give effect to the Cody acquisition as if it had occurred on January 1, 2001

(In Thousands)	2001
Revenues	$	505,528
Net Income	$	54,513
Per share - Basic	$	1.75
Per share - Diluted	$	1.73

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, respectively, of 2003. 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 partners decision and the Company’s decision to proceed with the liquidation, it performed an impairment review which resulted in an after-tax charge of approximately $54.4 million. This impairment charge is reflected in the 2003 Statement of Operations as an operating expense but did not impact the Company’s cash flows.

16. Earnings per Common Share

Basic earnings per common share (EPS) is computed by dividing net income (the numerator) by the weighted average number of common shares outstanding for the period (the denominator). Diluted EPS is similarly calculated 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 year ended December 31, 2003, 2002 and 2001:

	December 31,
	2003	2002	2001
Shares - basic	32,049,664	31,736,975	30,275,906
Dilution effect of stock options and awards at end of period	240,621	338,972	408,361
Shares - diluted	32,290,285	32,075,947	30,684,267
Stock awards and shares excluded from diluted earnings per share due to the anti-dilutive effect	965,777	1,174,507	913,310

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CABOT OIL & GAS CORPORATION

SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) –

Oil and Gas Reserves

Users of this information should be aware that the process of estimating quantities of “proved” and “proved developed” natural gas and crude oil reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. As a result, revisions to existing reserve estimates may occur from time to time. Although every reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible, the subjective decisions and variances in available data for various reservoirs make these estimates generally less precise than other estimates included in the financial statement disclosures.

Proved reserves represent estimated quantities of natural gas, crude oil and condensate that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under economic and operating conditions in effect when the estimates were made.

Proved developed reserves are proved reserves expected to be recovered through wells and equipment in place and under operating methods used when the estimates were made.

Estimates of proved and proved developed reserves at December 31, 2003, 2002, and 2001 were based on studies performed by the Company’s petroleum engineering staff. The estimates were reviewed by Miller and Lents, Ltd., who indicated in their letter dated February 9, 2004, that based on their investigation and subject to the limitations described in their letter, they believe the results of those estimates and projections were reasonable in the aggregate.

No major discovery or other favorable or unfavorable event after December 31, 2003, is believed to have caused a material change in the estimates of proved or proved developed reserves as of that date.

The following table illustrates the Company’s net proved reserves, including changes, and proved developed reserves for the periods indicated, as estimated by the Company’s engineering staff.

	Natural Gas
	December 31,
(Millions of cubic feet)	2003		2002		2001
Proved Reserves
Beginning of Year	1,060,959		1,036,004		959,222
Revisions of Prior Estimates	(6,122	)	14,405		(44,266	)
Extensions, Discoveries and Other Additions	105,497		64,945		99,911
Production	(71,906	)	(73,670	)	(69,162	)
Purchases of Reserves in Place	1,590		26,262		91,290
Sales of Reserves in Place	(20,534	)	(6,987	)	(991	)
End of Year	1,069,484		1,060,959		1,036,004
Proved Developed Reserves	812,280		819,412		804,646
Percentage of Reserves Developed	76.0	%	77.2	%	77.7	%

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	Liquids
	December 31,
(Thousands of barrels)	2003		2002		2001
Proved Reserves
Beginning of Year	18,393		19,684		9,914
Revisions of Prior Estimates	307		1,871		254
Extensions, Discoveries and Other Additions	1,723		851		2,257
Production	(2,846	)	(2,909	)	(1,996	)
Purchases of Reserves in Place	—		261		9,255
Sales of Reserves in Place	(5,474	)	(1,365	)	—
End of Year	12,103		18,393		19,684
Proved Developed Reserves	9,405		13,267		15,328
Percentage of Reserves Developed	77.7	%	72.1	%	77.9	%

Capitalized Costs Relating to Oil and Gas Producing Activities

The following table illustrates the total amount of capitalized costs relating to natural gas and crude oil producing activities and the total amount of related accumulated depreciation, depletion and amortization.

	December 31,
(In thousands)	2003		2002		2001
Aggregate Capitalized Costs Relating to Oil and Gas Producing Activities	$	1,732,236	$	1,704,746	$	1,632,101
Aggregate Accumulated Depreciation, Depletion and Amortization	$	837,060	$	750,857	$	651,657

Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities

Costs incurred in property acquisition, exploration and development activities were as follows:

	Year Ended December 31,
(In thousands)	2003		2002		2001
Property Acquisition Costs, Proved (1)	$	1,524	$	8,799	$	245,079
Property Acquisition Costs, Unproved (1)		14,056		4,869		21,116
Exploration and Extension Well Costs (2)		83,147		52,012		91,261
Development Costs		77,006		55,165		90,246
Total Costs	$	175,733	$	120,845	$	447,702

⁽¹⁾ Excludes the $78.0 million deferred tax gross-up on the Cody acquisition in 2001.

⁽²⁾ Includes administrative exploration costs of $10,582, $8,942, and $9,831 for the years ended December 31, 2003, 2002, and 2001, respectively. These costs are excluded from the Company’s calculation of reserve replacement costs.

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Historical Results of Operations from Oil and Gas Producing Activities

The results of operations for the Company’s oil and gas producing activities were as follows:

	Year Ended December 31,
(In thousands)	2003		2002		2001
Operating Revenues	$	404,503	$	280,379	$	339,064
Costs and Expenses
Production		77,315		63,823		58,382
Other Operating		20,090		21,731		22,656
Exploration (1)		58,119		40,167		71,165
Depreciation, Depletion and Amortization		195,659		102,086		89,286
Total Costs and Expenses		351,183		227,807		241,489
Income Before Income Taxes		53,320		52,572		97,575
Provision for Income Taxes		18,662		18,400		34,151
Results of Operations	$	34,658	$	34,172	$	63,424

⁽¹⁾ Includes administrative exploration costs of $10,582, $8,942, and $9,831 for the years ended December 31, 2003, 2002, and 2001, respectively. These costs are excluded from the Company’s calculation of reserve replacement costs.

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves

The following information has been developed utilizing SFAS 69, “Disclosures about Oil and Gas Producing Activities”, procedures and based on natural gas and crude oil reserve and production volumes estimated by the Company’s engineering staff. It can be used for some comparisons, but should not be the only method used to evaluate the Company or its performance. Further, the information in the following table may not represent realistic assessments of future cash flows, nor should the Standardized Measure of Discounted Future Net Cash Flows be viewed as representative of the current value of the Company.

The Company believes that the following factors should be taken into account when reviewing the following information:

• Future costs and selling prices will probably differ from those required to be used in these calculations.

• Due to future market conditions and governmental regulations, actual rates of production in future years may vary significantly from the rate of production assumed in the calculations.

• Selection of a 10% discount rate is arbitrary and may not be a reasonable measure of the relative risk that is part of realizing future net oil and gas revenues.

• Future net revenues may be subject to different rates of income taxation.

Under the Standardized Measure, future cash inflows were estimated by applying year-end oil and gas prices adjusted for fixed and determinable escalations to the estimated future production of year-end proved reserves.

The average prices related to proved reserves at December 31, 2003, 2002, and 2001 for natural gas ($ per Mcf) were $5.96, $4.41, and $2.65, respectively, and for oil ($ per Bbl) were $30.94, $30.39, and $18.56, respectively. Future cash inflows were reduced by estimated future development and production costs based on year-end costs to arrive at net cash flow before tax. Future income tax expense was computed by applying year-end statutory tax rates to future pretax net cash flows, less the tax basis of the properties involved. SFAS 69 requires the use of a 10% discount rate.

Management does not use only the following information when making investment and operating decisions. These decisions are based on a number of factors, including estimates of probable as well as proved reserves, and varying price and cost assumptions considered more representative of a range of anticipated economic conditions.

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Standardized Measure is as follows:

	Year Ended December 31,
(In thousands)	2003(1)			2002(1)			2001(1)
Future Cash Inflows	$	6,742,214		$	5,236,349		$	3,107,668
Future Production Costs		(1,390,398	)		(1,137,615	)		(823,988	)
Future Development Costs		(310,923	)		(284,165	)		(266,833	)
Future Net Cash Flows Before Income Taxes		5,040,893			3,814,569			2,016,847
10% Annual Discount for Estimated Timing of Cash Flows		(2,844,855	)		(2,098,669	)		(1,065,747	)
Standardized Measure of Discounted Future Net Cash Flows Before Income Taxes		2,196,038			1,715,900			951,100
Future Income Tax Expenses, Net of 10% Annual Discount (2)		(716,630	)		(460,547	)		(185,074	)
Standardized Measure of Discounted Future Net Cash Flows	$	1,479,408		$	1,255,353		$	766,026

⁽¹⁾ Includes the future cash inflows, production costs and development costs, as well as the tax basis, related to the properties.

⁽²⁾ Future income taxes before discount were $1,800,519, $1,195,082, and $558,085 for the years ended December 31, 2003, 2002, and 2001, respectively.

Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves

The following is an analysis of the changes in the Standardized Measure:

	Year Ended December 31,
(In thousands)	2003			2002			2001
Beginning of Year	$	1,255,353		$	766,026		$	2,409,832
Discoveries and Extensions, Net of Related Future Costs		235,079			112,269			100,084
Net Changes in Prices and Production Costs (1)		475,026			703,874			(2,545,349	)
Accretion of Discount		171,590			95,110			353,625
Revisions of Previous Quantity Estimates, Timing and Other		(35,691	)		51,944			(358,134	)
Development Costs Incurred		27,529			20,516			26,158
Sales and Transfers, Net of Production Costs		(330,800	)		(216,555	)		(280,682	)
Net Purchases (Sales) of Reserves in Place		(62,596	)		(2,357	)		119,149
Net Change in Income Taxes		(256,082	)		(275,474	)		941,343
End of Year	$	1,479,408		$	1,255,353		$	766,026

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CABOT OIL & GAS CORPORATION

SELECTED DATA (UNAUDITED)

QUARTERLY FINANCIAL INFORMATION (UNAUDITED)

(In thousands, except per share amounts)	First			Second		Third		Fourth		Total
2003
Operating Revenues	$	135,916		$	126,756	$	125,471	$	121,248	$	509,391
Impairment of Long-Lived Assets		87,926			—		5,870		—		93,796
Operating Income		(46,691	)		34,850		43,630		34,798		66,587
Net Income (Loss) (1)		(39,223	)		17,904		23,220		19,231		21,132
Basic Earnings per Share (1)	$	(1.23	)	$	0.56	$	0.73	$	0.60	$	0.66
Diluted Earnings per Share (1)	$	(1.23	)	$	0.55	$	0.73	$	0.60	$	0.65
2002
Operating Revenues	$	75,073		$	89,584	$	85,549	$	103,550	$	353,756
Impairment of Long-Lived Assets		1,063			—		—		1,657		2,720
Operating Income (Loss)		4,996			9,850		15,111		19,131		49,088
Net Income (Loss)		(798	)		2,121		6,125		8,655		16,103
Basic Earnings per Share	$	(0.03	)	$	0.07	$	0.19	$	0.27	$	0.51
Diluted Earnings per Share	$	(0.03	)	$	0.07	$	0.19	$	0.27	$	0.50

(1) Net income reported in Form 10-Q as of September 30, 2003 has been revised to reflect the reversal of the adoption of SFAS 150. This reversal resulted in an increase of $0.6 million or $0.02 per common and diluted share for the three months then ended.

ITEM 9A. CONTROLS AND PROCEDURES

As of December 31, 2003, the Company carried out an evaluation, under the supervision and with the participation of the Company’s management, including the Company’s Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of the Company’s disclosure controls and procedures pursuant to Rules 13a-15 and 15d-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 issuer 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. Accordingly, in this Form 10-K/A we revised our consolidated balance sheets at December 31, 2003 and 2002 to reflect the reclassification of deferred income taxes. 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.

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PART IV

ITEM 15. EXHIBITS, FINANCIAL STATEMENTS, SCHEDULES AND REPORTS ON FORM 8-K

A. INDEX

1. Consolidated Financial Statements

See Index on page 6.

2. Financial Statement Schedules

None.

3. Exhibits

The following instruments are included as exhibits to this report. Those exhibits below incorporated by reference herein are indicated as such by the information supplied in the parenthetical thereafter. If no parenthetical appears after an exhibit, copies of the instrument have been included herewith.

Exhibit Number	Description
3.1	Certificate of Incorporation of the Company (Registration Statement No. 33-32553).
3.2	Amended and Restated Bylaws of the Company amended September 6, 2001 (Form 10-K for 2001).
3.3	Certificate of Amendment of Certificate of Incorporation (Form 8-K for July 2, 2002).
3.4	Certificate of Increase of Shares Designated Series A Junior Participating Preferred Stock (Form 8-K for July 2, 2002).
4.1	Form of Certificate of Common Stock of the Company (Registration Statement No. 33-32553).
4.2	Certificate of Designation for Series A Junior Participating Preferred Stock (Form 10-K for 1994).
4.3	Rights Agreement dated as of March 28, 1991, between the Company and The First National Bank of Boston, as Rights Agent, which includes as Exhibit A the form of Certificate of Designation of Series A Junior Participating Preferred Stock (Form 8-A, File No. 1-10477).
	(a) Amendment No. 1 to the Rights Agreement dated February 24, 1994 (Form 10-K for 1994).
	(b) Amendment No. 2 to the Rights Agreement dated December 8, 2000 (Form 8-K for December 21, 2000).
4.4	Certificate of Designation for 6% Convertible Redeemable Preferred Stock (Form 10-K for 1994).
4.5	Amended and Restated Credit Agreement dated as of May 30, 1995, among the Company, Morgan Guaranty Trust Company, as agent and the banks named therein.
	(a) Amendment No. 1 to Credit Agreement dated September 15, 1995 (Form 10-K for 1995).
	(b) Amendment No. 2 to Credit Agreement dated December 24, 1996 (Form 10-K for 1996).
4.7	Note Purchase Agreement dated November 14, 1997, among the Company and the purchasers named therein (Form 10-K for 1997).
4.8	Note Purchase Agreement dated as of July 26, 2001 among Cabot Oil & Gas Corporation and the Purchasers listed therein (Form 8-K for August 30, 2001).
4.9	Credit Agreement dated as of October 28, 2002 among the Company, the Banks Parties Hereto and Fleet National Bank, as administrative agent (Form 10-Q for the quarter ended September 30, 2002).
10.1	Supplemental Executive Retirement Agreement between the Company and Charles P. Siess, Jr. (Form 10-K for 1995).
10.2	Form of Change in Control Agreement between the Company and Certain Officers (Form 10-K for 2001).
10.3	Letter Agreement dated January 11, 1990, between Morgan Guaranty Trust Company of New York and the Company (Registration Statement No. 33-32553).
10.4	Form of Annual Target Cash Incentive Plan of the Company (Registration Statement No. 33-32553).

- 43 -

Exhibit Number	Description
10.5	Form of Incentive Stock Option Plan of the Company (Registration Statement No. 33-32553).
	(a)    First Amendment to the Incentive Stock Option Plan (Post-Effective Amendment No. 1 to S-8 dated April 26, 1993).
10.6	Form of Stock Subscription Agreement between the Company and certain executive officers and directors of the Company (Registration Statement No. 33-32553).
10.7	Transaction Agreement between Cabot Corporation and the Company dated February 1, 1991 (Registration Statement No. 33-37455).
10.8	Tax Sharing Agreement between Cabot Corporation and the Company dated February 1, 1991 (Registration Statement No. 33-37455).
10.9	Amendment Agreement (amending the Transaction Agreement and the Tax Sharing Agreement) dated March 25, 1991 (incorporated by reference from Cabot Corporation’s Schedule 13E-4, Am. No. 6, File No. 5-30636).
10.10	Savings Investment Plan & Trust Agreement of the Company (Form 10-K for 1991).
	(a)    First Amendment to the Savings Investment Plan dated May 21, 1993 (Form S-8 dated November 1, 1993).
	(b)    Second Amendment to the Savings Investment Plan dated May 21, 1993 (Form S-8 dated November 1, 1993).
	(c)    First through Fifth Amendments to the Trust Agreement (Form 10-K for 1995).
	(d)    Third through Fifth Amendments to the Savings Investment Plan (Form 10-K for 1996).
10.11	Supplemental Executive Retirement Agreements of the Company (Form 10-K for 1991).
10.12	Settlement Agreement and Mutual Release (Tax Issues) between Cabot Corporation and the Company dated July 7, 1992 (Form 10-Q for the quarter ended June 30, 1992).
10.13	Agreement of Merger dated February 25, 1994, among Washington Energy Company, Washington Energy Resources Company, the Company and COG Acquisition Company (Form 10-K for 1993).
10.14	1990 Non-employee Director Stock Option Plan of the Company (Form S-8 dated June 23, 1990).
	(a)    First Amendment to 1990 Non-employee Director Stock Option Plan (Post-Effective Amendment No. 2 to Form S-8 dated March 7, 1994).
	(b)    Second Amendment to 1990 Non-employee Director Stock Option Plan (Form 10-K for 1995).
10.15	Second Amended and Restated 1994 Long-Term Incentive Plan of the Company (Form 10-K for 2001).
10.16	Second Amended and Restated 1994 Non-Employee Director Stock Option Plan (Form 10-K for 2001).
10.17	Employment Agreement between the Company and Ray R. Seegmiller dated September 25, 1995 (Form 10-K for 1995).
10.18	Form of Indemnity Agreement between the Company and Certain Officers (Form 10-K for 1997).
10.19	Deferred Compensation Plan of the Company as Amended September 1, 2001 (Form 10-K for 2001).
10.20	Trust Agreement dated September 2000 between Harris Trust and Savings Bank and the Company (Form 10-K for 2001).
10.21	Lease Agreement between the Company and DNA COG, Ltd. dated April 24, 1998 (Form 10-K for 1998).
10.22	Credit Agreement dated as of December 17, 1998, between the Company and the banks named therein (Form 10-K for 1998).
10.23	Letter Agreement with Puget Sound Energy Company dated September 21, 1999 (Form 10-K for 1999).
10.24	Agreement and Plan of Merger, dated June 20, 2001, among Cabot Oil & Gas Corporation, COG Colorado Corporation, Cody Company and the shareholders of Cody Company (Form 8-K for June 28, 2001).
	(a)    Amendment to Agreement and Plan of Merger dated as of July 10, 2001 to the Agreement and plan of Merger, dated June 20, 2001, among Cabot Oil & Gas Corporation, COG Colorado Corporation, Cody Company and the shareholders of Cody Company (Form 8-K for August 30, 2001).
	(b)    Closing Agreement dated August 16, 2001 (Form 8-K for August 30, 2001).
10.25	Employment Agreement between the Company and Dan O. Dinges dated August 29, 2001 (Form 10-K for 2001).

- 44 -

Exhibit Number	Description
21.1	Subsidiaries of Cabot Oil & Gas Corporation.
23.1	Consent of PricewaterhouseCoopers LLP
23.2	Consent of Miller and Lents, Ltd.
23.3	Consent of Brown, Drew & Massey, LLP
28.1	Miller and Lents, Ltd. Review Letter
31.1	302 Certification – Chairman, President and Chief Executive Officer
31.2	302 Certification – Vice President and Chief Financial Officer
32.1	906 Certification

- 45 -

B. REPORTS ON FORM 8-K

None

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Houston, State of Texas, on the 9th of August 2004.

CABOT OIL & GAS CORPORATION
By:	/s/ Dan O. Dinges
	Dan O. Dinges
	Chairman, President and Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons in the capacities and on the dates indicated.

Signature	Title	Date
/s/ Dan O. Dinges Dan O. Dinges	Chairman, President and Chief Executive Officer (Principal Executive Officer)	August 9, 2004
/s/ Scott C. Schroeder Scott C. Schroeder	Vice President, Chief Financial Officer (Principal Financial Officer)	August 9, 2004
/s/ Henry C. Smyth Henry C. Smyth	Vice President, Controller and Treasurer (Principal Accounting Officer)	August 9, 2004
/s/ Robert F. Bailey Robert F. Bailey	Director	August 9, 2004
/s/ John G. L. Cabot John G. L. Cabot	Director	August 9, 2004
/s/ James G. Floyd James G. Floyd	Director	August 9, 2004
/s/ Robert Kelley Robert Kelley	Director	August 9, 2004
/s/ C. Wayne Nance C. Wayne Nance	Director	August 9, 2004
/s/ P. Dexter Peacock P. Dexter Peacock	Director	August 9, 2004
/s/ William P. Vititoe William P. Vititoe	Director	August 9, 2004

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