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SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

For the quarterly period ended March 31, 2004

Commission file number 1-10447

CABOT OIL & GAS CORPORATION

(Exact name of registrant as specified in its charter)

1200 Enclave Parkway, Houston, Texas 77077

(Address of principal executive offices including Zip Code)

(281) 589-4600

(Registrant’s telephone number)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months and (2) has been subject to such filing requirements for the past 90 days.    Yes  x    No  ¨

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

As of April 26, 2004, there were 32,892,303 shares of Common Stock, Par Value $.10 Per Share, outstanding.

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CABOT OIL & GAS CORPORATION

INDEX TO FINANCIAL STATEMENTS

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PART I. FINANCIAL INFORMATION

ITEM 1. Financial Statements

CABOT OIL & GAS CORPORATION

CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS (Unaudited)

(In thousands, except per share amounts)

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

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CABOT OIL & GAS CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEET

(In thousands, except share amounts)

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

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CABOT OIL & GAS CORPORATION

CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS (Unaudited)

(In thousands)

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

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CABOT OIL & GAS CORPORATION

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)

1. FINANCIAL STATEMENT PRESENTATION

During interim periods, Cabot Oil & Gas Corporation (the Company) follows the same accounting policies used in its Annual Report to Stockholders and its Report on Form 10-K filed with the Securities and Exchange Commission. People using financial information produced for interim periods are encouraged to refer to the footnotes in the Annual Report to Stockholders when reviewing interim financial results. In management’s opinion, the accompanying interim condensed consolidated financial statements contain all material adjustments, consisting only of normal recurring adjustments, necessary for a fair presentation. The results of operations for any interim period are not necessarily indicative of the results of operations for the entire year.

Our independent accountants have performed a review of these condensed consolidated interim financial statements in accordance with standards established by the American Institute of Certified Public Accountants. Pursuant to Rule 436(c) under the Securities Act of 1933, this report should not be considered a part of a registration statement prepared or certified by PricewaterhouseCoopers LLP within the meanings of Sections 7 and 11 of the Act.

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

Recently Issued Accounting Pronouncements

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 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 March 31, 2004 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.

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

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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.

SFAS 150 contains guidance which stipulates that 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 our consolidated financial statements. In November 2003 the FASB issued FSP 150-3, “Effective Date, Disclosures, and Transition for Mandatorily Redeemable Financial Instruments of Certain Nonpublic Entities and Certain Mandatorily Redeemable Non Controlling Interests Under SFAS 150,” which defers indefinitely the provisions of SFAS 150 as they relate to the Company’s limited life partnerships acquired in conjunction with the Cody acquisition.

We have 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 was whether SFAS 142 requires registrants to reclassify costs associated with mineral rights, including both proved and unproved leasehold acquisition costs, as intangible assets in the balance sheet, apart from other capitalized oil and gas property costs. Historically, the Company and other oil and gas companies have included the cost of these oil and gas leasehold interests as part of oil and gas properties and provided the disclosures required by SFAS No. 69, Disclosures about Oil and Gas Producing Activities (SFAS 69). Also under consideration was whether SFAS 142 requires registrants to provide the additional disclosures prescribed by SFAS 142 for intangible assets for costs associated with mineral rights. In March 2004, the Emerging Issues Task Force (EITF) released a consensus on EITF Issue No. 04-2, “Whether Mineral Rights are Tangible or Intangible Assets,” that stated mineral rights are tangible assets. Additionally, the FASB has issued guidance that would amend SFAS 141 and 142 to exclude mineral rights from the definition of intangible assets.

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 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 must be provided separately for pension plans and for other postretirement benefit plans. The new disclosures are effective for 2003 calendar year financial statements. See footnote 10 for the interim disclosures.

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Stock Based Compensation

SFAS 123, “Accounting for Stock-Based Compensation”, as amended by SFAS 148, “Accounting for Stock-Based Compensation – Transition and Disclosure,” outlines a fair value based method of accounting for stock options or similar equity instruments. The Company has opted to continue using the intrinsic value based method, as recommended by Accounting Principles Board (APB) Opinion 25, to measure compensation cost for its stock option plans.

The following table illustrates the effect on Net Income and Earnings Per Share if the Company had applied the fair value recognition provisions of SFAS 123 to stock-based employee compensation.

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

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

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2. PROPERTIES AND EQUIPMENT

Properties and equipment are comprised of the following:

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 (see Note 9). These reclassifications were made to conform to the current period presentation.

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

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3. ADDITIONAL BALANCE SHEET INFORMATION

Certain balance sheet amounts are comprised of the following:

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4. LONG-TERM DEBT

At March 31, 2004, the Company did not have any debt outstanding under its credit facility, which provides for an available credit line of $250 million. The available credit line is subject to adjustment from time to time on the basis of the projected present value (as determined by the bank’s petroleum engineer) of estimated future net cash flows from certain proved oil and gas reserves and other assets of the Company. The revolving term under this credit facility presently ends in October 2006 and is subject to renewal.

The Company has the following debt outstanding:

5. EARNINGS PER SHARE

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

The following is a calculation of basic and diluted weighted average shares outstanding for the three months ended March 31, 2004 and 2003:

6. COMMITMENTS AND CONTINGENCIES

Wyoming Royalty Litigation

In June 2000, the Company was sued by two overriding royalty owners in Wyoming state court for unspecified damages. The plaintiffs requested class certification 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 able to settle the case and the State District Court Judge entered his order approving the settlement in the fourth quarter of 2003. 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.

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In January 2002, 13 overriding royalty owners sued the Company in Wyoming federal district court. The plaintiffs in the federal case have made the same general claims pertaining to deductions from their overriding royalty as the plaintiffs in the Wyoming state court case but have not asked for class certification. That case is on hold awaiting a Wyoming Supreme Court decision on two certified questions.

Although management believes that a number of our 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 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 Company’s defenses, 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 our 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. It 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 it had taken improper deductions from the royalty and failed to properly inform the plaintiffs and other similarly situated persons of deductions taken from the royalty. The plaintiffs have also claimed that they are entitled to a 1/8th royalty share of the gas sales contract settlement that the Company reached with Columbia Gas Transmission Corporation in the 1995 Columbia Gas Transmission Corporation bankruptcy proceeding.

The Company has removed the lawsuit to federal court; however, in February 2003, the Company 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 January 18, 2005.

The investigation into this claim continues and it is in the discovery phase. The Company is vigorously defending the case. The Company has reserves management believes are adequate to provide for these potential liabilities based on managements 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 our financial position.

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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 79^th 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 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, LCC, acquired title and since Cabot acquired its lease is approximately $13 million. The carrying value of this property is approximately $34 million. Co-defendants Shell Oil Company and Shell Western E&P 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 filed by the defendants has been denied by the Court.

Although the investigation into this claim is continuing, management intends to vigorously defend the case. Management cannot currently determine the likelihood or range of any potential loss.

7. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITY

The Company periodically enters into derivative commodity instruments to hedge its exposure to price fluctuations on natural gas and crude oil production. At March 31, 2004, the Company had 27 cash flow hedges open: eight natural gas price collar arrangements and 19 natural gas price swap arrangements. Additionally, the Company had five crude oil financial instruments and one natural gas financial instrument open at March 31, 2004, that did not qualify for hedge accounting under SFAS 133. At March 31, 2004, a $56.9 million ($35.2 million net of tax) unrealized loss was recorded to Other Comprehensive Income, along with a $67.1 million derivative liability. 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.

Assuming no change in commodity prices, after March 31, 2004 the Company would reclassify to earnings, over the next 12 months, $30.1 million in after-tax expenditures associated with commodity derivatives. This reclassification represents the net liability associated with open positions at March 31, 2004 related to remaining anticipated 2004 production and a portion of anticipated 2005 production.

From time to time the Company enters into natural gas and crude oil swap arrangements that do not qualify for hedge accounting in accordance with SFAS 133. These financial instruments are recorded at fair value at the balance sheet date. At March 31, 2004, the Company had five open crude oil swap arrangements and one natural gas swap arrangement with an unrealized net loss of $6.5 million related to the crude oil positions and an unrealized net loss of $1.4 million related to natural gas positions. These amounts are reflected in the respective line items of Net Operating Revenues.

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8. COMPREHENSIVE INCOME

Comprehensive Income includes Net Income and certain items recorded directly to Stockholders’ Equity and classified as Other Comprehensive Income. The following table illustrates the calculation of Comprehensive Income for the three month periods ended March 31, 2004 and 2003:

Deferred income tax of $8.8 million represents the net deferred tax liability of ($2.4) million on the Reclassification Adjustment for Settled Contracts, $11.2 million on the Changes in Fair Value of Hedge Positions, and less than $0.1 million on the Foreign Currency Translation Adjustment.

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

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

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 was $0.5 million for the three months ended March 31, 2004 and 2003.

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10. PENSION AND OTHER POSTRETIREMENT BENEFITS

The components of net periodic benefit costs for the three months ended March 31, 2004 and 2003 are as follows:

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

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Report of Independent Accountants

To the Board of Directors and Shareholders of

Cabot Oil & Gas Corporation:

We have reviewed the accompanying condensed consolidated balance sheet of Cabot Oil & Gas Corporation and its subsidiaries (the “Company”) as of March 31, 2004, and the related condensed consolidated statements of operations and cash flows for each of the three-month periods ended March 31, 2004 and March 31, 2003. These interim financial statements are the responsibility of the Company’s management.

We conducted our review in accordance with standards established by the American Institute of Certified Public Accountants. A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with generally accepted auditing standards, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.

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

We previously audited in accordance with auditing standards generally accepted in the United States of America, the consolidated balance sheet as of December 31, 2003, and the related consolidated statements of operations, stockholders’ equity, and of cash flows for the year then ended (not presented herein), and in our report dated February 16, 2004 we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying condensed consolidated balance sheet as of December 31, 2003, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.

PricewaterhouseCoopers LLP

Houston, Texas

April 27, 2004

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

The following review of operations for the first quarter of 2004 and 2003 should be read along with our Condensed Consolidated Financial Statements and the Notes included in this Form 10-Q and with the Consolidated Financial Statements, Notes and Management’s Discussion and Analysis included in the Cabot Oil & Gas Form 10-K for the year ended December 31, 2003.

Overview

In the first three months of 2004, we produced 20.9 Bcfe compared to production of 21.9 Bcfe for the comparable period of the prior year. Natural gas production was 17.7 Bcf and oil production was 538 Mbbls. Natural gas production in the current period increased slightly from the same period in 2003. The increase in our natural gas production is attributable to successful drilling efforts on properties acquired in the Cody acquisition. The decrease in oil production is primarily the result of the continued decline of the CL&F lease in south Louisiana, along with the expected lower volumes from the Company’s West region due to reduced capital investment in 2002 and 2003.

In the three months ended March 31, 2004, we drilled 38 gross wells (32 development and six exploratory wells) with a success rate of 100% compared to 25 gross wells (22 development and three exploratory wells) with a success rate of 88% for the comparable period of the prior year. For the full year, we plan to drill 281 gross wells compared to 173 gross wells in 2003.

We had net income of $19.0 million, or $0.59 per share, for the three months ended March 31, 2004 compared to a net loss of $39.2 million, or $1.23 per share, for the comparable period of the prior year. The prior year loss was substantially due to non-cash impairment charges of $87.9 million (pre-tax) related to the liquidation of a limited partnership interest in the Kurten field and the cumulative effect of accounting change in the amount of $6.8 million due to the adoption of SFAS 143.

In the first three months of 2004, natural gas prices were higher than the same period of the comparable year and our financial results reflect their impact. Our realized natural gas price was $5.21 per Mcf, or 13% higher, than the $4.55 per Mcf price realized in the same period of the prior year. These realized prices are impacted by realized gains and losses resulting from commodity derivatives. Commodity prices are determined by factors that are outside of our control. Historically, commodity prices have been volatile and we expect them to remain volatile. Commodity prices are affected by changes in market demands, overall economic activity, weather, pipeline capacity constraints, inventory storage levels, basis differentials and other factors. As a result, we cannot accurately predict future natural gas, NGLs and crude oil prices, and therefore, cannot accurately predict revenues. In addition to production volumes and commodity prices, finding and developing sufficient amounts of crude oil and natural gas reserves at economical costs are critical to our long-term success. In 2004, excluding acquisitions, we expect to spend approximately $217 million in capital and exploration expenditures. For the three months ended March 31, 2004, $56.0 million of capital and exploration expenditures have been invested in our exploration and development efforts.

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

The preceding paragraphs, discussing our strategic pursuits and goals, contain forward-looking information. See Forward-Looking Information on page 25.

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Financial Condition

Capital Resources and Liquidity

Our capital resources consist primarily of cash flows from our oil and gas properties and asset-based borrowings supported by our oil and gas reserves. The level of earnings and cash flows depend on many factors, including the price of crude oil and natural gas and our ability to control and reduce costs. Demand for crude oil and natural gas has historically been subject to seasonal influences characterized by peak demand and higher prices in the winter heating season. However, throughout 2003 and in the first quarter of 2004 the demand for natural gas and crude oil has remained unusually strong.

Our primary source of cash during the first three months of 2004 was generated from operations. Cash was primarily used to fund exploration and development expenditures and pay dividends, with the remaining excess invested in short-term cash equivalent investments. See below for additional discussion and analysis of cash flow.

Cash flow discussion and analysis:

The available credit line under our revolving credit facility, currently $250 million, is subject to adjustment on the basis of the present value of estimated future net cash flows from proved oil and gas reserves (as determined by the bank’s petroleum engineer) and other assets. At March 31, 2004, we had no outstanding balance on the facility with excess capacity totaling $250 million of the total available credit facility. The revolving term of the credit facility ends in October 2006. We strive to manage our debt at a level below the available credit line in order to maintain excess borrowing capacity. Management believes that we have the ability to finance through new debt or equity offerings, if necessary, our capital requirements, including acquisitions.

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Capitalization

Our capitalization information is as follows:

During the first three months of 2004, we paid dividends of $1.3 million on our Common Stock. A regular dividend of $0.04 per share of Common Stock has been declared for each quarter since we became a public company in 1990.

Capital and Exploration Expenditures

On an annual basis, we generally fund most of our capital and exploration activities, excluding major oil and gas property acquisitions, with cash generated from operations, and budget such capital expenditures while considering projected cash flows for the year.

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

We plan to drill 281 gross wells in 2004. This drilling program includes approximately $217 million in total capital and exploration expenditures. We will continue to assess the natural gas price environment and may increase or decrease the capital and exploration expenditures accordingly.

Critical Accounting Policies and Estimates

The Company’s discussion and analysis of its financial condition and results of operation are based upon condensed consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted and adopted in the United States. The preparation of these financial statements requires the Company to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses. There have been no changes to the Company’s critical accounting policies from those described in the 2003 Form 10-K. See the Company’s Annual Report on Form 10-K for the year ended December 31, 2003, for further discussion.

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Results of Operations

First Quarters of 2004 and 2003 Compared

Net Income and Income from Operations

We reported net income in the first quarter of 2004 of $19.0 million, or $0.59 per share. During the corresponding quarter of 2003, we reported a net loss of $39.2 million, or $1.23 per share. Operating income increased $82.8 million compared to the comparable period of the prior year. The increase in current year operating income was substantially due to an increase in our realized natural gas and crude oil prices as well as the non-cash pre-tax impairment charge of $87.9 million in the prior year. Net income increased in the current year due to an increase in operating income and the cumulative effect of accounting change impact of $6.8 million in the prior year.

Natural Gas Production Revenues

The average total company realized natural gas production sales price, including the realized impact of derivative instruments, was $5.21 per Mcf compared to $4.55 per Mcf for the comparable period of the prior year. These prices include the realized impact of derivative instruments which reduced these prices by $0.38 per Mcf in 2004 and $1.46 per Mcf in 2003. The following table excludes the unrealized loss from the change in derivative fair value of $1.7 million and $0.5 million for the three months ended March 31, 2004 and 2003, respectively. These unrealized changes in fair value have been included in the Natural Gas Production revenues line item on the Statement of Operations.