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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-Q

For the quarterly period ended March 31, 2004

OR

Commission file number: 000-32261

ATP OIL & GAS CORPORATION

(Exact name of registrant as specified in its charter)

4600 Post Oak Place, Suite 200

Houston, Texas 77027

(Address of principal executive offices)

(Zip Code)

(713) 622-3311

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), 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 Exchange Act)    Yes  ¨    No  x

The number of shares outstanding of Registrant’s common stock, par value $0.001, as of May 12, 2004, was 24,533,356.

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ATP OIL & GAS CORPORATION

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PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(In Thousands, Except Share Amounts)

(Unaudited))

See accompanying notes to consolidated financial statements.

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ATP OIL & GAS CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(In Thousands, Except Per Share Amounts)

(Unaudited)

See accompanying notes to consolidated financial statements.

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ATP OIL & GAS CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In Thousands)

(Unaudited)

See accompanying notes to consolidated financial statements.

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ATP OIL & GAS CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(In Thousands)

(Unaudited)

See accompanying notes to consolidated financial statements.

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ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLID ATED FINANCIAL STATEMENTS

(unaudited)

Note 1—Organization

ATP Oil & Gas Corporation (“ATP”), a Texas corporation, was formed on August 8, 1991 and is engaged in the acquisition, development and production of natural gas and oil properties in the Gulf of Mexico and the U.K. and Dutch Sectors of the North Sea (the “North Sea”). We primarily focus our efforts on natural gas and oil properties with proved undeveloped reserves that are economically attractive to us but are not strategic to major or exploration-oriented independent oil and gas companies.

The accompanying unaudited consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”) for interim financial information and reflect all adjustments (consisting of normal recurring accruals) which are, in the opinion of management, necessary for a fair presentation of the results of operations for the interim periods. All significant intercompany transactions have been eliminated. Certain reclassifications have been made to prior period amounts to conform to current period presentation. The interim financial information and notes thereto should be read in conjunction with our 2003 Annual Report on Form 10-K. The results of operations for the three months ended March 31, 2004 are not necessarily indicative of results to be expected for the entire year.

Note 2—Recent Accounting Pronouncements

We have been made aware of an issue regarding the application of provisions of Statement of Financial Accounting Standards (“SFAS”) No. 141, “Business Combinations (“SFAS 141”) 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, we and other oil and gas companies have included the cost of these oil and gas leasehold interests as part of oil and gas properties. 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.

An Emerging Issues Task Force Working Group (“EITF”) was created to research the accounting and disclosure treatment of mineral rights for oil and gas companies. As a result, the EITF added Issue No. 04-2, “Whether Mineral Rights are Tangible or Intangible Assets and Related Issues,” and Issue No. 03-S, “Application of FASB Statement No. 142, Goodwill and Other Intangible Assets, to Oil and Gas Companies”. Although the EITF has not issued formal guidance to oil and gas companies, at the March 2004 meeting, the EITF reached a consensus that mineral interests for mining companies should be accounted for as tangible assets.

Note 3—Asset Retirement Obligations

We adopted the provisions of SFAS No. 143, “Accounting for Asset Retirement Obligations,” (“SFAS 143”) on January 1, 2003. This statement 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 costs are capitalized as part of the carrying amount of the asset. The asset retirement liability is allocated to operating expense by using a systematic and rational method.

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Upon adoption of the statement, an asset retirement obligation of approximately $23.1 million was recorded to reflect the estimated obligations related to the future plugging and abandonment of our wells. An addition to oil and gas properties of approximately $15.4 million for the related asset retirement costs and a cumulative effect of change in accounting principle of approximately $0.7 million (net of $0.3 million of deferred taxes) was also recorded. A reconciliation of the changes in the liability from December 31, 2003 to March 31, 2004 follows (in thousands):

Note 4—Disposition of Oil and Gas Properties

Effective in February 2004, we entered into an agreement to sell 25% of our working interests as of December 31, 2003 in seven Gulf of Mexico (“GOM”) properties consisting of ten offshore leases for $19.5 million. This sale represents 10.6 Bcfe of proved reserves, 94% of which were proved undeveloped at December 31, 2003, in the GOM (5.2% of our GOM reserves). The sale was implemented in two stages. The first stage closed in February 2004 whereby we received $10.5 million for a 25% interest in one property and a 10% interest in six properties. The second stage closed on April 20, 2004 whereby we received $9.0 million for the remaining 15% interests in the six properties.

The $19.5 million in proceeds were allocated among the fair values of the properties sold in both stages. Of the $10.5 million received in the first sale, $8.3 million (including purchase price adjustments) was allocated to the interests in the properties sold, resulting in a gain of approximately $3.0 million over the carrying value of $5.3 at the time of the sale. The remainder of the proceeds of $2.2 million has been deferred until the second closing on April 20, 2004 and is included in current liabilities in the consolidated financial statements.

At March 31, 2004, the second stage of the sale had not yet been completed and the carrying value of the remaining interests in the properties of approximately $7.4 million has been classified as “assets held for sale” under the provisions of SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets.” During the second quarter of 2004, we expect to record a gain of approximately $3.0 million to $4.0 million related to the second stage of the sale.

Note 5—Long-Term Debt

Long-term debt as of the dates indicated were as follows (in thousands):

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On March 29, 2004, we entered into a new $185.0 million term loan of which $150.0 million is a Senior Secured First Lien Term Loan Facility and $35.0 million is a Senior Secured Second Lien Term Loan Facility (“Term Loan”). The Term Loan matures in March 2009. It is secured by substantially all of our oil and gas assets in the Gulf of Mexico and the U.K. Sector – North Sea and is guaranteed by our wholly owned subsidiaries ATP Energy and ATP Oil & Gas (U.K.) Limited. We used $116.2 million of the proceeds of the Term Loan to repay in full our previous credit facility in effect at December 31, 2003. At closing, we received net proceeds of $56.0 million after repaying our previous credit facility, the repurchase of 750,000 warrants associated with the previous credit facility described below, a 3% original issue discount of $5.6 million and fees associated with the transaction.

As consideration for an amendment and waivers of non-compliance with certain covenants under our previous credit facility, on February 16, 2004 we issued warrants to purchase 750,000 shares of our common stock. The warrants were issued with an exercise price of $6.75 per share and had an expiration of February 16, 2009. The warrants also included the right, under certain conditions, for us to repurchase all of the outstanding warrants for $750,000 prior to May 17, 2004, when the warrants became exercisable. These warrants were repurchased for $750,000 and retired on March 29, 2004.

The Term Loan was issued at an average annual interest rate of 10.8%. The $150.0 million term loan bears interest at the base rate plus a margin of 7.5% or LIBOR (with a 2% floor) plus a margin of 8.5% at the election of ATP. Beginning in October 2004, the margin will increase from 8.5% to 9.5% increasing the average annual interest rate to 11.2%. The $35.0 million term loan bears interest at the base rate plus a margin of 9.0% or LIBOR (with a 2% floor) plus a margin of 10.0% at the election of ATP.

In connection with the issuance of the Term Loan we paid fees and expenses of $8.2 million and granted warrants to purchase 2,452,336 shares of common stock of ATP for $7.25 per share. The warrants have a term of six years and expire in March 2010. The fair value of the warrants, as determined by use of the Black-Scholes valuation model, is approximately $4.2 million and has been accounted for as additional paid-in-capital and debt discount. The fair value was calculated with the following weighted-average assumptions: zero dividend yield; risk-free interest rate of 3.0%; volatility of 51.6% and an expected life of 6 years. The value was adjusted for liquidity issues associated with a potential sale of such a large volume of shares in relation to our public float. This amount and the original issue discount of $5.6 million will be accreted over the life of the loan as additional interest expense.

The terms of the Term Loan require us to maintain certain covenants which are tested on a quarterly basis beginning June 30, 2004. Capitalized terms are defined in the credit agreement for the Term Loan. The covenants include:

We expect that we will be in compliance with the financial covenants under our new Term Loan for the next twelve months. However, adverse changes in our expected production levels and reserves or material delays or cost overruns in 2004 could have a material adverse affect on our financial condition and results of operations and result in our non-compliance with these covenants. An event of non-compliance with any of the required covenants could result in a material mandatory repayment under the Term Loan.

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Note 6—Stock –Based Compensation

SFAS No. 123, “Accounting for Stock-Based Compensation” (“SFAS 123”), as amended by SFAS No. 148, “Accounting for Stock-Based Compensation – Transition and Disclosure,” (“SFAS 148”) outlines a fair value based method of accounting for stock options or similar equity instruments. We have continued using the intrinsic value based method, as allowed 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 we had applied the fair value recognition provisions of SFAS 123 to stock-based employee compensation.

Note 7—Earnings Per Share

Basic earnings per share is computed by dividing net income (loss) available to common shareholders by the weighted average number of common shares outstanding during the period. Diluted earnings per share is determined on the assumption that outstanding stock options have been converted using the average price for the period. For purposes of computing earnings per share in a loss year, potential common shares have been excluded from the computation of weighted average common shares outstanding because their effect is antidilutive.

Basic and diluted net income (loss) per share is computed based on the following information (in thousands, except per share amounts):

Note 8—Derivative Instruments and Price Risk Management Activities

Derivative financial instruments, utilized to manage or reduce commodity price risk related to our production are accounted for under the provisions of SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (“SFAS 133”) and related interpretations. Under this standard, all derivatives are carried on the balance sheet at fair value. If the derivative is designated as a fair value hedge, the changes in the fair value

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of the derivative and of the hedged item attributable to the hedged risk are recognized in earnings. If the derivative is designated as a cash flow hedge, the effective portions of changes in the fair value of the derivative are recorded in other comprehensive income (“OCI”) and are recognized in the consolidated statement of operations when the hedged item affects earnings. Ineffective portions of changes in the fair value of cash flow hedges are recognized in earnings. Derivative contracts that do not qualify for hedge accounting are recorded at fair value on our consolidated balance sheet and the associated unrealized gains and losses are recorded as a component of revenues in the current period.

We occasionally use derivative instruments with respect to a portion of our oil and gas production to manage our exposure to price volatility. These instruments may take the form of futures contracts, swaps or options.

At March 31, 2004, a $0.8 million unrealized loss was recorded to accumulated other comprehensive income, along with an $0.8 million derivative liability. Gains and losses are reclassified from accumulated other comprehensive income to the income statement as a component of natural gas and oil revenues in the period the hedged production occurs. If any ineffectiveness occurs, amounts are recorded directly to the income statement. All of this deferred loss will be reversed during the next twelve months as the forecasted transactions actually occur.

At March 31, 2004, we had entered into a natural gas swap that qualifies as a cash flow hedge with respect to our future natural gas production as follows

We also manage our exposure to oil and gas price risks by periodically entering into fixed-price delivery contracts. These physical contracts qualified and have been designated for the normal purchase and sale exemption under SFAS 133, as amended. At March 31, 2004, we had fixed-price contracts in place for the following natural gas and oil volumes:

Note 9—Commitments and Contingencies

Contingencies

In 2001 we purchased three properties in the U.K. Sector—North Sea. In accordance with the purchase agreement, we also committed to pay future consideration contingent upon the successful development and operation of the properties. The contingent consideration for each property includes amounts to be paid upon achieving first commercial production and upon achieving designated cumulative production levels. Since only the first threshhold of first commercial production has been achieved, such related contingent consideration has been accrued for payment in the consolidated financial statements. Upon achievement of the second threshhold, the remaining contingent consideration will be accrued and capitalized at that time. Future development is planned on the other two properties.

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Litigation

ATP was in a dispute over a contract for the sale of an oil and gas property. The matter was referred to arbitration and on December 19, 2003, ATP was notified by the arbitration panel of its decision to award $8.2 million to the other party. During the first quarter of 2004 all parties entered into a settlement agreement whereby ATP would pay the award and the lawsuit would be dismissed. ATP paid the award in two payments with the final payment being made on March 31, 2004, and the Court dismissed the lawsuit on April 16, 2004.

We are also, in the ordinary course of business, a claimant and/or defendant in various legal proceedings. Management does not believe that the outcome of these legal proceedings, individually, and in the aggregate will have a materially adverse effect on our financial condition, results of operations or cash flows.

Note 10—Segment Information

We follow SFAS No. 131, “Disclosures About Segments of an Enterprise and Related Information,” which requires that companies disclose segment data based on how management makes decisions about allocating resources to segments and measuring their performance. We manage our business and identify our segments based on geographic areas. We have two reportable segments: our operations in the Gulf of Mexico and our operations in the North Sea. Both of these segments involve oil and gas producing activities. Following is certain financial information regarding our segments for the three months ended March 31, 2004 and 2003 (in thousands):

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ATP OIL & GAS CORPORATION AND SUBSIDIARIES

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Executive Overview

General

ATP Oil & Gas Corporation is engaged in the acquisition, development and production of natural gas and oil properties in the Gulf of Mexico and the North Sea. We seek to acquire and develop properties with proved undeveloped reserves (“PUD”) that are economically attractive to us but are not strategic to major or large exploration-oriented independent oil and gas companies. We believe that our strategy provides assets for us to develop and produce without the risk, cost or time of exploration.

We seek to create value and reduce operating risks through the acquisition and development of proved natural gas and oil reserves in areas that have:

Source of Revenue

We derive our revenues from the sale of natural gas and oil that is produced from our natural gas and oil properties. Revenues are a function of the volume produced and the prevailing market price at the time of sale. The price of natural gas is the primary factor affecting our revenues. To achieve more predictable cash flows and to reduce our exposure to downward price fluctuations, we utilize derivative instruments to hedge future sales prices on a significant portion of our natural gas production. The use of certain types of derivative instruments may prevent us from realizing the full benefit of upward price movements.

First Quarter 2004 Highlights

Our financial and operating performance for the first quarter of 2004 included the following highlights:

A more complete overview and discussion of full year expectations can be found in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our 2003 Annual Report on Form 10-K.

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Results of Operations

Three Months Ended March 31, 2004 Compared to Three Months Ended March 31, 2003

For the three months ended March 31, 2004, we reported a net loss of $2.4 million, or $0.10 per share on total revenue of $24.0 million as compared with net income of $2.4 million, or $0.12 per share, on total revenue of $20.4 million for the three months ended March 31, 2003.

Oil and Gas Revenues

Sales volumes, average realized prices and oil and gas production revenue for the three months ended March 31, 2004 and 2003 were as follows:

Excluding the effects of price risk management activities, the decrease in oil and gas revenue in 2004 compared to 2003 was the result of natural decline at one of our significant properties. The decrease was partially offset by an increase in our natural gas production volumes from properties brought on line subsequent to the first quarter of 2003.

Lease Operating Expense. Lease operating expenses for the first quarter of 2004 increased to $4.5 million ($0.96 per Mcfe) from $3.6 million ($0.73 per Mcfe) in the first quarter of 2003. The increase per Mcfe was primarily attributable to the aforementioned decrease in production while certain costs remained fixed. In addition, our Helvellyn well in the North Sea commenced production and contributed $0.8 million to the increase.

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General and Administrative Expense. General and administrative expense increased to $4.1 million for the first quarter of 2004 compared to $3.1 million for the same period of 2003 primarily due to an increase in accounting fees of $0.4 million. In addition, we opened an office in the Netherlands late in the fourth quarter of 2003.

Credit Facility and Related Expenses. In the first quarter of 2004, we incurred substantial non-recurring costs of $1.9 million to maintain compliance with the requirements of our previous lender. These costs primarily consisted of legal fees of $0.8 million and professional fees of $0.8 million.

Depreciation, Depletion and Amortization Expense. Depreciation, depletion and amortization expense increased $3.8 million (49%) during the first quarter of 2004 to $11.6 million from $7.8 million for the same period in 2003. The average DD&A rate was $2.49 per Mcfe in the first quarter of 2004 compared to $1.55 per Mcfe in the same quarter of 2003. A contributor to this increase was our Helvellyn well which accounted for $2.4 million at a rate of $2.83 per Mcfe.

Loss on Extinguishment of Debt. In the first quarter of 2004, we recognized a non-cash loss of $3.3 million on the extinguishment of debt related to our prior credit facility agreement

Gain on Disposition of Properties. In the first quarter of 2004, we recognized a gain of $3.0 million on the sale of interests in certain GOM properties. See Note 4 to the Consolidated Financial Statements.

Income Taxes. In the first quarter of 2004, we increased the deferred tax valuation allowance to equal the deferred tax asset based upon management’s determination that the recognition criteria for realization had not been met.

Liquidity and Capital Resources

At March 31, 2004, we had working capital of approximately $7.4 million, an increase of approximately $53.8 million from December 31, 2003. In compliance with the definition of working capital under our term loan, we had working capital of approximately $16.0 million. This definition excludes current maturities of long-term debt, the current portion of assets and liabilities from derivatives and the current portion of asset retirement obligations.

Our working capital position has improved dramatically as a result of several events during the first quarter of 2004 including the following:

We have financed our acquisition and development activities through a combination of project-based development arrangements, bank borrowings and proceeds from our equity offerings, as well as cash from operations and the sale on a promoted basis of interests in selected properties. We intend to finance our near-term development projects in the Gulf of Mexico and North Sea through available cash flows, proceeds from our recent term loan and the potential sell down of interests in the development projects. As operator of all of our projects in development, we have the ability to significantly control the timing of most of our capital expenditures. We believe the cash flows from operating activities combined with our ability to control the timing of substantially all of our future development and acquisition requirements will provide us with the flexibility and liquidity to meet our future planned capital requirements.

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Cash Flows

Cash used in operating activities in the first quarter of 2004 was $8.6 million and cash provided by operations in the first quarter of 2003 was $20.3 million, respectively. Cash flow from operations decreased primarily due to an increase in amounts due from partners for capital costs incurred during the first quarter of 2004 and payment of a litigation award of $8.2 million.

Cash used in investing activities in the first quarter of 2004 and 2003 was $12.2 million and $22.3 million, respectively. Developmental capital expenditures in the Gulf of Mexico and North Sea were approximately $17.9 million and $4.7 million in first quarter of 2004, offset by the receipt of $10.5 million in proceeds for the sale of certain interests in seven of our properties discussed below. Developmental capital expenditures in the Gulf of Mexico and North Sea were approximately $18.0 million and $4.3 million in first quarter of 2003.

In February 2004, we entered into an agreement to sell 25% of our working interests as of December 31, 2003 in seven Gulf of Mexico (“GOM”) properties for $19.5 million. This sale represents 10.6 Bcfe of proved reserves in the GOM (5.2% of our GOM reserves), 93.5% of which were proved undeveloped at December 31, 2003. The sale was implemented in two stages. The first stage closed in February 2004 whereby we received $10.5 million for a 25% interest in one property and a 10% interest in six properties. The second stage closed on April 20, 2004 whereby we received $9.0 million for the remaining 15% interests in the six properties. Under the terms of the agreements, the purchaser will receive their share of revenues and pay their share of costs from January 1, 2004 through the respective closing dates (see Note 4 to the Consolidated Financial Statements).

Cash provided by financing activities in the first quarter of 2004 consisted of net payments of $117.1 million related to our prior credit facility and net proceeds of $179.5 million related to our new term loan and warrants issued. We also incurred deferred financing costs of approximately $8.5 million related to the new term loan.

Term Loan

On March 29, 2004, we entered into a new $185.0 million term loan of which $150.0 million is a Senior Secured First Lien Term Loan Facility and $35.0 million is a Senior Secured Second Lien Term Loan Facility (“Term Loan”). The Term Loan matures in March 2009. It is secured by substantially all of our oil and gas assets in the Gulf of Mexico and the U.K. Sector – North Sea and is guaranteed by our wholly owned subsidiaries ATP Energy and ATP Oil & Gas (U.K.) Limited. We used $116.2 million of the proceeds of the Term Loan to repay in full our previous credit facility in effect at December 31, 2003. At closing, we received net proceeds of $56.0 million after repaying our previous credit facility, the repurchase of 750,000 warrants associated with the previous credit facility described below, a 3% original issue discount of $5.6 million and fees associated with the transaction.

As consideration for an amendment and waivers of non-compliance with certain covenants under our previous credit facility, on February 16, 2004 we issued warrants to purchase 750,000 shares of our common stock. The warrants were issued with an exercise price of $6.75 per share and had an expiration of February 16, 2009. The warrants also included the right, under certain conditions, for us to repurchase all of the outstanding warrants for $750,000 prior to May 17, 2004, when the warrants became exercisable. These warrants were repurchased for $750,000 and retired on March 29, 2004.

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The Term Loan was issued at an average annual interest rate of 10.8%. The $150.0 million term loan bears interest at the base rate plus a margin of 7.5% or LIBOR (with a 2% floor) plus a margin of 8.5% at the election of ATP. Beginning in October 2004, the margin will increase from 8.5% to 9.5% increasing the average annual interest rate to 11.2%. The $35.0 million term loan bears interest at the base rate plus a margin of 9.0% or LIBOR (with a 2% floor) plus a margin of 10.0% at the election of ATP.

In connection with the issuance of the Term Loan we paid fees and expenses of $8.2 million and granted warrants to purchase 2,452,336 shares of common stock of ATP for $7.25 per share. The warrants have a term of six years and expire in March 2010. The fair value of the warrants, as determined by use of the Black-Scholes valuation model, is approximately $4.2 million and has been accounted for as additional paid-in-capital and debt discount. The fair value was calculated with the following weighted-average assumptions: zero dividend yield; risk-free interest rate of 3.0%; volatility of 51.6% and an expected life of 6 years. The value was adjusted for liquidity issues associated with a potential sale of such a large volume of shares in relation to our public float. This amount and the original issue discount of $5.6 million will be accreted over the life of the loan as additional interest expense.

The terms of the Term Loan require us to maintain certain covenants which are tested on a quarterly basis beginning June 30, 2004. Capitalized terms are defined in the credit agreement for the Term Loan. The covenants include:

We expect that we will be in compliance with the financial covenants under our new Term Loan for the next twelve months. However, adverse changes in our expected production levels and reserves or material delays or cost overruns in 2004 could have a material adverse affect on our financial condition and results of operations and result in our non-compliance with these covenants. An event of non-compliance with any of the required covenants could result in a material mandatory repayment under the Term Loan.

Commitments and Contingencies

In preparing financial statements at any point in time, management is periodically faced with uncertainties, the outcomes of which are not within its control and will not be known for prolonged periods of time. As discussed in Note 9 to the Consolidated Financial Statements, we are involved in actions from time to time, which if determined adversely, could have a material negative impact on our financial position, results of operations and cash flows. Management, with the assistance of counsel makes estimates, if determinable, of ATP’s probable liabilities and records such amounts in the consolidated financial statements. Such estimates may be the minimum amount of a range of probable loss when no single best estimate is determinable. Disclosure is made, when determinable, of any additional possible amount of loss on these claims, or if such estimate cannot be made, that fact is disclosed. Along with our counsel, we monitor developments related to these legal matters and, when appropriate, we make adjustments to recorded liabilities to reflect current facts and circumstances. Although it is difficult to predict the ultimate outcome of these matters, management believes that the recorded amounts, if any, are reasonable.

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Accounting Pronouncements

See Note 2 to our Consolidated Financial Statements for a discussion of recently issued accounting pronouncements.

Critical Accounting Policies

Our discussion and analysis of our financial condition and results of operations are based on consolidated financial statements which have been prepared in accordance with generally accepted accounting principles in the United States. The preparation of these financial statements requires us to make estimates and judgments that affect the reported amounts or assets, liabilities, revenues and expenses. We believe that certain accounting policies affect our more significant judgments and estimates used in the preparation of our consolidated financial statements. Our 2003 Annual Report on Form 10-K includes a discussion of our critical accounting policies.

Interest Rate Risk

We are exposed to changes in interest rates. Changes in interest rates affect the interest earned on our cash and cash equivalents and the interest rate paid on borrowings under the credit facility. Under our current policies, we do not use interest rate derivative instruments to manage exposure to interest rate changes.

Foreign Currency Risk.

The net assets, net earnings and cash flows from our wholly owned subsidiaries in the U.K. and the Netherlands are based on the U.S. dollar equivalent of such amounts measured in the applicable functional currency. These foreign operations have the potential to impact our financial position due to fluctuations in the local currency arising from the process of re-measuring the local functional currency in the U.S. dollar. We have not utilized derivatives or other financial instruments to hedge the risk associated with the movement in foreign currencies.

Commodity Price Risk

Our revenues, profitability and future growth depend substantially on prevailing prices for natural gas and oil. Prices also affect the amount of cash flow available for capital expenditures and our ability to borrow and raise additional capital. Lower prices may also reduce the amount of natural gas and oil that we can economically produce. We currently sell a portion of our natural gas and oil production under price sensitive or market price contracts. We periodically use derivative instruments to hedge our commodity price risk. We hedge a portion of our projected natural gas and oil production through a variety of financial and physical arrangements intended to support natural gas and oil prices at targeted levels and to manage our exposure to price fluctuations. We may use futures contracts, swaps and fixed price physical contracts to hedge our commodity prices. Realized gains and losses from our price risk management activities are recognized in oil and gas sales when the associated production occurs. For derivatives designated as cash flow hedges, the unrecognized gains and losses are included as a component of other comprehensive income (loss) to the extent the hedge is effective. See Note 8 to the Consolidated Financial Statements for additional information. We do not hold or issue derivative instruments for speculative purposes.

Our internal hedging policy provides that we examine the economic effect of entering into a commodity contract with respect to the properties that we acquire. We generally acquire properties at prices that are below the management’s estimated value of the estimated proved reserves at the then current natural gas and oil prices. We may enter into short-term hedging arrangements if (1) we are able to obtain commodity contracts at prices sufficient to secure an acceptable internal rate of return on a particular property or on a group of properties or (2) if deemed necessary by the terms of our existing credit agreements.

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Item 4. Controls and Procedures

a. Based on their evaluation of the Company’s disclosure controls and procedures as of a date within 90 days of the filing date of this Quarterly Report on Form 10-Q, the Company’s chief executive officer and chief financial officer have concluded that Company’s disclosure controls and procedures were adequate and designed to ensure that material information relating to the Company and the Company’s consolidated subsidiaries would be made known to them by others within those entities.

b. There were no significant changes in the Company’s internal controls or in other factors that could significantly affect these controls subsequent to the date of their evaluation.

Forward-Looking Statements and Associated Risks

This Quarterly Report contains projections and other forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934. These projections and statements reflect the Company’s current views with respect to future events and financial performance. No assurances can be given, however, that these events will occur or that these projections will be achieved and actual results could differ materially from those projected as a result of certain factors. A discussion of these factors is included in the Company’s 2003 Form 10-K.

PART II. OTHER INFORMATION

Items 1, 2, 3, 4 & 5 are not applicable and have been omitted.

Item 6—Exhibits and Reports on Form 8-K

B. Reports on Form 8-K

Current Report on Form 8-K filed on April 4, 2004, pursuant to Item 12, Results of Operations announcing its earnings results for the fourth quarter of 2004.

Current Report on Form 8-K filed on April 23, 2004, pursuant to Item 4, Changes in Registrant’s Certifying Accountant announcing the dismissal of KPMG LLP and the engagement of Deloitte & Touche LLP.

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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 and thereunto duly authorized.

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