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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-Q

þ        QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE        

SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2003

OR

¨        TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE        

SECURITIES EXCHANGE ACT OF 1934

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  þ    No  ¨

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

The number of shares outstanding of Registrant’s common stock, par value $0.001, as of May 12, 2003, was 20,338,753.

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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)

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 CONSOLIDATED 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 financial statements and related notes present our consolidated financial position as of March 31, 2003 and December 31, 2002, the results of our operations for the three months ended March 31, 2003 and 2002, cash flows for the three months ended March 31, 2003 and 2002 and comprehensive income (loss) for the three months ended March 31, 2003 and 2002. The financial statements have been prepared in accordance with the instructions to interim reporting as prescribed by the Securities and Exchange Commission (“SEC”). All adjustments, consisting only of normal recurring adjustments, that in the opinion of management were necessary for a fair statement of the results for the interim periods, have been reflected. All significant intercompany transactions have been eliminated. Certain reclassifications have been made to prior period amounts to conform to current period presentation. The results of operations for the three months ended March 31, 2003 should not be taken as indicative of the results to be expected for the full year. The interim financial statements should be read in conjunction with our consolidated financial statements and notes thereto presented in our 2002 Annual Report on Form 10-K.

Note 2 — Accounting Pronouncements

In June 2001 the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards (“SFAS”) No. 143 “Accounting for Asset Retirement Obligations” (“SFAS 143”). SFAS 143 provides accounting requirements for retirement obligations associated with tangible long-lived assets, including: 1) the timing of 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. We adopted SFAS 143 on January 1, 2003 and recorded a liability for asset retirement obligations of $23.4 million (using a 12.5% discount rate) and a net of tax cumulative effect of change in accounting principle of $0.7 million.

The reconciliation of the beginning and ending asset retirement obligation as of March 31, 2003 is as follows (in thousands):

The following table summarizes the pro forma net income and earnings per share for the three months ended March 31, 2002 and for the years ended December 31, 2002, 2001 and 2000 as if SFAS 143 had been adopted on January 1, 2000 (in thousands, except per share amounts):

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The following table summarizes pro forma asset retirement obligations as of March 31, 2002 and December 31, 2002, 2001 and 2000 as if SFAS 143 had been adopted on January 1, 2000 (in thousands):

In April 2002, the FASB issued SFAS No. 145, “Rescission of FASB Statements No. 4, No. 44, and No. 64, Amendment of FASB Statement No. 13, and Technical Corrections” (“SFAS 145”). Among other things, SFAS 145 requires gains and losses from early extinguishment of debt to be included in income from continuing operations instead of being classified as extraordinary items as previously required by generally accepted accounting principles. SFAS 145 is effective for fiscal years beginning after May 15, 2002 and we adopted the statement on January 1, 2003. Gains or losses on early extinguishment of debt that were classified as an extraordinary item in periods prior to adoption must be reclassified into income from continuing operations. The adoption of SFAS 145 required the $0.6 million (net of tax) of extraordinary loss for the year ended December 31, 2001 to be reclassified to interest expense and income tax benefit.

In June 2002, the FASB issued SFAS No. 146, “Accounting for Costs Associated with Exit or Disposal Activities” (“SFAS 146”). SFAS 146 addresses financial accounting and reporting for costs associated with exit or disposal activities and nullified Emerging Issues Task Force Issue No. 94-3, “Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring”. SFAS 146 requires that a liability for a cost associated with an exit or disposal activity be recognized when the liability is incurred. SFAS 146 also establishes that fair value is the objective for initial measurement of the liability. The provisions of this statement are effective for exit or disposal activities that are initiated after December 31, 2002. We adopted the provisions of SFAS 146 on January 1, 2003 and the adoption did not have an effect on our financial position or results of operations.

In April 2003, the FASB issued SFAS No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities” (“SFAS 149”). SFAS 149 amends and clarifies accounting for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities under SFAS 133. SFAS 149 clarifies under what circumstances a contract with an initial net investment meets the characteristic of a derivative and when a derivative contains a financing component that warrants special reporting in the statement of cash flows. This Statement is generally effective for contracts entered into or modified after June 30, 2003 and is not expected to have a material impact on our financial statements.

In November 2002, the FASB issued FASB Interpretation No. 45 “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantee of Indebtedness of Others” (“FIN 45”). FIN 45 requires that upon issuance of a guarantee, the guarantor must recognize a liability for the fair value of the obligation it assumes under that guarantee. FIN 45’s provisions for initial recognition and measurement should be applied on a prospective basis to guarantees issued or modified after December 31, 2002. The disclosure provisions apply to financial statements for periods ending after December 15, 2002. We do not currently have guarantees that require disclosure. We adopted the measurement provisions of this statement on January 1, 2003 and the adoption did not have an effect on our financial position or results of operations.

In January 2003, the FASB issued FASB Interpretation No. 46, “Consolidation of Variable Interest Entities” (“FIN 46”). FIN 46 requires a company to consolidate a variable interest entity if it is designated as the primary beneficiary of that entity even if the company does not have a majority of voting interest. A variable interest entity is generally defined as an entity where its equity is unable to finance its activities or where the owners of the entity lack the risk and rewards of ownership. The provisions of FIN 46 apply immediately to variable interest entities created after January 31, 2003 and to variable interest entities in which an enterprise obtains an interest after that date. The adoption of FIN 46 did not have an effect on our financial position or results of operations.

Emerging Issues Task Force (“EITF”) Issue No. 02-03, “Recognition and Reporting of Gains and Losses on Energy Trading Contracts” under EITF Issues No. 98-10, “Accounting for Contracts Involved in Energy Trading and Risk Management Activities” was issued in June 2002. EITF Issue No. 02-03 addresses certain issues related to energy trading activities, including (a) gross versus net presentation in the income statement, (b) whether the initial fair value of an energy trading contract can be other than the price at which it was exchanged, and (c) accounting for inventory utilized in energy trading activities. As of January 1, 2003, we have presented our gas sold and purchased activities in the statement of operations for all periods on a net rather than a gross basis under other income (expense). The remaining provisions effective January 1, 2003 had no impact on our financial position or results of operations.

Note 3 — Long-Term Debt

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

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We have a $100.0 million senior-secured revolving credit facility which is secured by substantially all of our U.S. oil and gas properties, as well as by approximately two-thirds of the capital stock of our foreign subsidiaries and is guaranteed by our wholly owned subsidiary, ATP Energy, Inc. The amount available for borrowing under the credit facility is limited to the loan value, as determined by the bank, of oil and gas properties pledged under the facility. If our outstanding balance exceeds our borrowing base at any time, we are required to repay such excess within 30 days and our interest rate during the time an excess exists is increased by 2.00%.

On March 25, 2003, we entered into an agreement with our lenders to defer our scheduled borrowing base redetermination until the next scheduled redetermination in May 2003, reaffirm the current borrowing base of $56.0 million and the borrowing base reduction amount of zero and to reduce the amount outstanding under our borrowing base by $6.0 million between March 28, 2003 and May 31, 2003. On May 13, 2003, we entered into an amendment to our credit facility under which the borrowing base was redetermined and was established at $50.0 million with the borrowing base reduction amount re-established at zero until the next redetermination in July 2003. As part of the May 13, 2003 amendment, the lenders removed the requirement of a positive working capital position, effective as of March 31, 2003, and re-established the amount we could advance to our foreign subsidiaries to a maximum of $17.0 million. Under the amendment, we agreed to maintain a positive working capital, calculated pursuant to our lenders’ requirements, commencing June 30, 2003. At the next scheduled redetermination in July 2003, the lenders can increase or decrease the borrowing base and re-establish the monthly reduction amount. A material reduction in the borrowing base or a material increase in the monthly reduction amount by the lender would have a material negative impact on our cash flows and our ability to fund future operations.

Advances under the credit facility can be in the form of either base rate loans or Eurodollar loans. The interest on a base rate loan is a fluctuating rate equal to the higher of the Federal funds rate plus 0.5% and the bank base rate, plus a margin of 0.25%, 0.50%, 0.75% or 1.00% depending on the amount outstanding under the credit agreement. The interest on a Eurodollar loan is equal to the Eurodollar rate, plus a margin of 2.25%, 2.50%, 2.875%, or 3.125% depending on the amount outstanding under the credit facility. The credit facility matures in May 2004. Our credit facility contains conditions and restrictive provisions, among other things, (1) limiting us to enter into any arrangement to sell or transfer any of our material property, (2) prohibiting a merger into or consolidation with any other person or sell or dispose of all or substantially all of our assets, (3) maintaining certain financial ratios and (4) limitations on advances to our foreign subsidiaries.

Effective June 29, 2001, we issued a note payable to a purchaser for a face principal amount of $31.3 million which matures in June 2005 and bears interest at a fixed rate of 11.5% per annum. The note is secured by second priority liens on substantially all of our U.S. oil and gas properties and is subordinated in right of payment to our existing senior indebtedness. We executed an agreement in connection with the note which contains conditions and restrictive provisions and requires the maintenance of certain financial ratios. Upon consent of the purchaser, which shall not be unreasonably withheld, the note may be repaid prior to the maturity date with an additional repayment premium based on the percentage of the principal amount paid, ranging from 4.5% during the first year to 16.5% in the final year of payment. If the note is paid at maturity, the maximum payment premium of 16.5% is required. The expected repayment premium is being amortized to interest expense straight-line, over the term of the note which approximates the effective interest method. The resulting liability is included in other long-term liabilities on the consolidated balance sheet. In July 2001, we received proceeds of $30.0 million in consideration for the issuance of the note. The discount of $1.3 million is being amortized to interest expense using the effective interest method. The amount available for borrowing under the note is limited to the loan value of oil and gas properties pledged under the note, as determined by the purchaser. The purchaser has the right to make a redetermination of the borrowing base at least once every six months. We have not been notified of any change in the borrowing base in 2003. On May 13, 2003, we entered into an amendment with the purchaser, effective March 31, 2003, to remove the requirement of a positive working capital position for the period January 2003 through September 29, 2003, and re-establish the requirement for the quarter ending September 30, 2003 and thereafter. If our outstanding balance exceeds the borrowing base at any time, we are required to repay such excess within 10 days subject to the provisions of the agreement. A material reduction in the borrowing base by the lender would have a material negative impact on our cash flows and our ability to fund future obligations. As of March 31, 2003, all of our borrowing base under the agreement was outstanding.

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As of March 31, 2003, we had a negative working capital under both our credit agreement and note payable agreement, as such term is defined in such agreements. The amendments executed on May 13, 2003, which removed the requirement for a positive working capital as of March 31, 2003, eliminated the non-compliance with the working capital covenants under both agreements that existed as of such date. We expect that we will be in compliance with the financial covenants under our credit facility and note payable, as amended, for the next twelve months.

Note 4 — 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 loss per share is computed based on the following information (in thousands, except per share amounts):

Note 5 — Derivative Instruments and Price Risk Management Activities

On January 1, 2001, we adopted SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (“SFAS 133”), as amended. The standard requires that all derivatives be recorded on the balance sheet at fair value and establishes criteria for documentation and measurement of hedging activities.

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.

Prior to July 1, 2002, we had not attempted to qualify our derivatives for the hedge accounting provisions under SFAS 133. Accordingly, we accounted for the changes in market value of these derivatives through current earnings. Gains and losses on all derivative instruments prior to July 1, 2002 were included in other income (expense) on the consolidated financial statements.

As of July 1, 2002, we performed the requisite steps to qualify our existing derivative instruments for hedge accounting treatment under the provisions of SFAS 133. Derivative instruments designated as cash flow hedges are reflected at fair value on our consolidated balance sheet. Changes in fair value, to the extent the hedge is effective, are recognized in other comprehensive income (loss) until the hedged item is settled and is recognized in earnings. Any ineffective portion of the derivative instrument’s change in fair value is recognized in revenues in the current period. Hedge effectiveness is measured at least quarterly. 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 other income (expense) in the current period.

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At March 31, 2003, a $1.3 million loss ($0.8 million after tax) was recorded to accumulated other comprehensive loss for the effective portion of the change in fair market during the first quarter of 2003. All of this deferred loss will be reversed during the next nine months as the forecasted transactions actually occur, assuming no further changes in fair market value. All forecasted transactions currently being hedged are expected to occur by December 2003. As of March 31, 2003, the fair value of the outstanding derivative instruments was a current liability of $9.2 million. This amount represents the difference between contract prices and future market prices on contracted volumes of the commodities as of March 31, 2003.

As of March 31, 2003, we had derivative contracts in place for the following natural gas and oil volumes:

In addition to these derivative instruments, we also manage our exposure to oil and gas price risks by periodically entering into fixed-price delivery contracts. As of March 31, 2003, we had fixed-price contracts in place for the following natural gas and oil volumes:

The following table summarizes all derivative instruments and fixed-price contracts as of March 31, 2003:

Additionally, in the first quarter of 2003, we entered into a costless collar arrangement for 300,000 MMBtu of our natural gas production for the months of January through March 2004 with a floor of $4.40 per MMBtu and a ceiling of $5.80 MMBtu. Collar arrangements are put and call options used to establish floor and ceiling commodity prices for a fixed volume of production during a certain time period. They provide for payments to counterparties if the index price exceeds the ceiling and payments from the counterparties if the index price is below the floor.

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Note 6 — Stock Options

We apply Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees” (“APB 25”) and related interpretations in accounting for stock options. Under APB 25, no compensation expense is recognized when the exercise price of options equals the fair value (market price) of the underlying stock on the date of grant. The following table illustrates the effect on net income and earnings per share if we had applied the fair value recognition provisions of 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”), to stock based compensation:

In the first quarter of 2002, we recorded a non-cash charge to compensation expense of approximately $0.2 million for options granted since September 1999 through the date of our initial public offering (“IPO”) on February 5, 2001 (the “measurement date”). The total expected expense as of the measurement date was recognized in the periods in which the option vested. Each option was divided into three equal portions corresponding to the three vesting dates (April 10, 2001, February 9, 2002, and February 9, 2003), with the related compensation cost for each portion amortized straight-line over the period to the vesting date.

Note 7 — 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. Development has been completed on our Helvellyn property and future development is planned on the other two properties. First commercial production from the Helvellyn property is expected to occur during the second quarter of 2003 and accordingly, contingent consideration has been accrued for payment and capitalized as acquisition costs.

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Litigation

ATP filed suit against Legacy Resources Co., LLP and agent (“Legacy”) in the District Court of Harris County, Texas in a dispute over a contract for the sale by Legacy of an oil and gas property to ATP. The court has abated the litigation pursuant to an arbitration provision in the contract. In the arbitration proceedings Legacy alleges that ATP owes it $12.3 million plus interest and expenses. ATP intends to vigorously defend against these claims. The judge has abated the litigation, until arbitration pursuant to the underlying agreements between the sellers and ATP is completed. A date of May 19, 2003 has been scheduled for the arbitration with an alternative date in September 2003. Due to the uncertainties of the legal and arbitration proceedings, a prediction of the outcome cannot be made with any degree of certainty and we have not accrued any amount related to this matter. Payments totaling $3.0 million made to Legacy in October of 2001 under the original contract were charged to earnings in 2001 along with all other costs related to this matter.

In August 2001, Burlington Resources Inc. filed suit against ATP alleging formation of a contract with ATP and our breach of the alleged contract. The complaint seeks compensatory damages of approximately $1.1 million. We intend to defend against these claims vigorously. It is not possible to predict with certainty whether we will incur any liability or to estimate the possible range of loss, if any, that we might incur in connection with this lawsuit.

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 8 — 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, 2003 and 2002 (in thousands):

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Note 9 — Subsequent Events

In April 2003, we received $8.1 million from a working interest participant related to development costs on one of our properties. We agreed to develop the property within 60 months from receipt of the funds or return the funds with interest if development had not been completed at the expiration of such time. At March 31, 2003, this transaction is not reflected in the financial statements.

On May 14, 2003, we completed a private placement of four million shares of common stock to accredited investors for a total consideration of $11.8 million ($11.1 million net of fees and expenses). The issuance of the common stock was exempt from registration under Section 4 (2) of the Securities Act of 1933, as amended, and we have agreed to register the resale of the common stock with the SEC on Form S-3.

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ATP OIL & GAS CORPORATION AND SUBSIDIARIES

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Overview

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. We attempt to achieve a high return on our investment in these properties by limiting our up-front acquisition costs, developing the properties in a relatively short period of time and by operating the properties efficiently.

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 2002 Annual Report on Form 10-K includes a discussion of our critical accounting policies.

Results of Operations

The following table sets forth selected financial and operating information for our natural gas and oil operations inclusive of the effects of price risk management activities:

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Three Months Ended March 31, 2003 Compared with Three Months Ended March 31, 2002

For the three months ended March 31, 2003, we reported net income of $2.4 million, or $0.12 per share on total revenue of $20.5 million, as compared with net loss of $6.4 million, or $0.31 per share on total revenue of $18.6 million in the first quarter of 2002.

Oil and Gas Revenue. Excluding the effects of settled derivatives, revenue from natural gas and oil production for the first quarter of 2003 increased over the same period in 2002 by approximately 38%, from $18.6 million to $25.7 million. This increase was primarily due to an approximate 94% increase in our average sales price per Mcfe from $2.65 in 2002 to $5.14 in 2003. The increase was partially offset by a 29% decrease in production volumes from 7.0 Bcfe to 5.0 Bcfe due primarily to natural declines and shut-ins due to Hurricane Lili in the fourth quarter of 2002.

Lease Operating Expense. Lease operating expenses for the first quarter of 2003 decreased to $3.6 million ($0.73 per Mcfe) from $3.8 million ($0.54 per Mcfe) in the first quarter of 2002. The increase per Mcfe was attributable to workover activities performed on three of our properties and the effect of fixed costs on those properties which produced less in the first quarter of 2003 than the first quarter of 2002.

General and Administrative Expense. General and administrative expense increased to $3.2 million for the first quarter of 2003 compared to $2.5 million for the same period in 2002. The primary reason for the increase was the result of higher compensation related costs and professional fees.

Non-Cash Compensation Expense. In the first quarter of 2002, we recorded a non-cash charge to compensation expense of approximately $0.2 million for options granted since September 1999 through the date of our initial public offering (“IPO”) on February 5, 2001 (the “measurement date”). The total expected expense as of the measurement date was recognized in the periods in which the option vested. Each option was divided into three equal portions corresponding to the three vesting dates (April 10, 2001, February 9, 2002, and February 9, 2003), with the related compensation cost for each portion amortized straight-line over the period to the vesting date.

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Depreciation, Depletion and Amortization Expense. Depreciation, depletion and amortization expense decreased 8% from the first quarter 2002 amount of $11.9 million to the first quarter 2003 amount of $7.8 million. The average DD&A rate was $1.55 per Mcfe in the first quarter of 2003 compared to $1.69 per Mcfe in the same quarter of 2002. This decrease was due primarily to upward reserve revisions on several of our significant properties and a decrease in production. In addition, production commenced subsequent to the first quarter 2002 on one of our properties with lower development costs in relation to higher reserves.

Other Income (Expense). In the first quarter of 2003, we recorded an unrealized loss of $0.1 million on a costless collar which does not qualify for hedge accounting treatment. In the first quarter of 2002, we recorded a net loss on derivative instruments of $7.4 million. The net loss in 2002 is comprised of a realized gain of $1.3 million for derivative contracts settled in the quarter and an unrealized loss of $8.7 million representing the change in fair market value of the open derivative positions at March 31, 2002.

Interest expense decreased to $2.3 million in the first quarter of 2003 from $2.7 million in the comparable quarter of 2002 primarily due to lower borrowing levels.

Liquidity and Capital Resources

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 equity offering 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 and recent equity offering 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.

Future cash flows are subject to a number of variables including changes in the borrowing base, the level of production from our properties, oil and natural gas prices and the impact, if any, of commitments and contingencies. Future borrowings under credit facilities are subject to variables including the lenders’ practices and policies, changes in the prices of oil and natural gas and changes in our oil and gas reserves. A material reduction in the borrowing base or the institution of a monthly reduction amount by our lenders would have a material negative impact on our cash flows and our ability to fund future obligations. No assurance can be given that operations and other capital resources will provide cash in sufficient amounts to maintain planned levels of operations and capital expenditures. Historically, in periods of reduced availability of funds from either cash flows or credit sources we have delayed planned capital expenditures and will continue do to so when necessary. While the delay decreases the amount of capital expenditures in the current period, it could negatively impact our future revenues and cash flows.

Cash Flows

Cash provided by operating activities in the first quarter of 2003 and 2002 was $20.3 million and $7.2 million, respectively. Cash flow from operations increased primarily due to the increase in oil and gas prices from the first quarter of 2002, somewhat offset by the 29% decrease in production.

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Cash used in investing activities in the first quarter of 2003 and 2002 was $20.8 million and $5.8 million, respectively. We incurred no costs for Dutch Sector—North Sea acquisition made in the first quarter of 2003. Developmental capital expenditures in the Gulf of Mexico and North Sea were approximately $18.0 million and $4.3 million, respectively. In the first quarter of 2002, total developmental expenditures of $5.7 million related to the Gulf of Mexico.

Cash used in financing activities in the first quarter of 2003 and 2002 represents principal payments on our credit facility.

Credit Facilities

We have a $100.0 million senior-secured revolving credit facility which is secured by substantially all of our U.S. oil and gas properties, as well as by approximately two-thirds of the capital stock of our foreign subsidiaries and is guaranteed by our wholly owned subsidiary, ATP Energy, Inc. The amount available for borrowing under the credit facility is limited to the loan value, as determined by the bank, of oil and gas properties pledged under the facility. If our outstanding balance exceeds our borrowing base at any time, we are required to repay such excess within 30 days and our interest rate during the time an excess exists is increased by 2.00%.

On March 25, 2003, we entered into an agreement with our lenders to defer our scheduled borrowing base redetermination until the next scheduled redetermination in May 2003, reaffirm the current borrowing base of $56.0 million and the borrowing base reduction amount of zero and to reduce the amount outstanding under our borrowing base by $6.0 million between March 28, 2003 and May 31, 2003. On May 13, 2003, we entered into an amendment to our credit facility under which the borrowing base was redetermined and was established at $50.0 million with the borrowing base reduction amount re-established at zero until the next redetermination in July 2003. As part of the May 13, 2003 amendment, the lenders removed the requirement of a positive working capital position, effective as of March 31, 2003, and re-established the amount we could advance to our foreign subsidiaries to a maximum of $17.0 million. Under the amendment, we agreed to maintain a positive working capital, calculated pursuant to our lenders’ requirements, commencing June 30, 2003. At the next scheduled redetermination in July 2003, the lenders can increase or decrease the borrowing base and re-establish the monthly reduction amount. A material reduction in the borrowing base or a material increase in the monthly reduction amount by the lender would have a material negative impact on our cash flows and our ability to fund future operations.

Advances under the credit facility can be in the form of either base rate loans or Eurodollar loans. The interest on a base rate loan is a fluctuating rate equal to the higher of the Federal funds rate plus 0.5% and the bank base rate, plus a margin of 0.25%, 0.50%, 0.75% or 1.00% depending on the amount outstanding under the credit agreement. The interest on a Eurodollar loan is equal to the Eurodollar rate, plus a margin of 2.25%, 2.50%, 2.875%, or 3.125% depending on the amount outstanding under the credit facility. The credit facility matures in May 2004. Our credit facility contains conditions and restrictive provisions, among other things, (1) limiting us to enter into any arrangement to sell or transfer any of our material property, (2) prohibiting a merger into or consolidation with any other person or sell or dispose of all or substantially all of our assets, (3) maintaining certain financial ratios and (4) limitations on advances to our foreign subsidiaries.

Note Payable

Effective June 29, 2001, we issued a note payable to a purchaser for a face principal amount of $31.3 million which matures in June 2005 and bears interest at a fixed rate of 11.5% per annum. The note is secured by second priority liens on substantially all of our U.S. oil and gas properties and is subordinated in right of payment to our existing senior indebtedness. We executed an agreement in connection with the note which contains conditions and restrictive provisions and requires the maintenance of certain financial ratios. Upon consent of the purchaser, which shall not be unreasonably withheld, the note may be repaid prior to the maturity date with an additional repayment premium based on the percentage of the principal amount paid, ranging from 4.5% during the first year to 16.5% in the final year of payment. If the note is paid at maturity, the maximum payment premium of 16.5% is required. The expected repayment premium is being amortized to interest expense straight-line, over the term of the note which approximates the effective interest method. The resulting liability is included in other long-term liabilities on the consolidated balance sheet. In July 2001, we received proceeds of $30.0 million in consideration for the issuance of the note. The discount of $1.3 million is

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being amortized to interest expense using the effective interest method. The amount available for borrowing under the note is limited to the loan value of oil and gas properties pledged under the note, as determined by the purchaser. The purchaser has the right to make a redetermination of the borrowing base at least once every six months. We have not been notified of any change in the borrowing base in 2003. On May 13, 2003, we entered into an amendment with the purchaser, effective March 31, 2003, to remove the requirement of a positive working capital position for the period January 2003 through September 29, 2003, and re-establish the requirement for the quarter ending September 30, 2003 and thereafter. If our outstanding balance exceeds the borrowing base at any time, we are required to repay such excess within 10 days subject to the provisions of the agreement. A material reduction in the borrowing base by the lender would have a material negative impact on our cash flows and our ability to fund future obligations. As of March 31, 2003, all of our borrowing base under the agreement was outstanding.

As of March 31, 2003, we had a negative working capital under both our credit agreement and note payable agreement, as such term is defined in such agreements. The amendments executed on May 13, 2003, which removed the requirement for a positive working capital as of March 31, 2003, eliminated the non-compliance with the working capital covenants under both agreements that existed as of such date. We expect that we will be in compliance with the financial covenants under our credit facility and note payable, as amended, for the next twelve months.

Working Capital

At March 31, 2003, we had a working capital deficit of approximately $34.0 million. In compliance with the definition of working capital in our credit facility, which excludes current maturities of long-term debt, the current portion of assets and liabilities from derivatives and the current portion of asset retirement obligations, we had a working capital deficit of approximately $14.9 million at March 31, 2003. In accordance with the definition of working capital under our note payable agreement, we had a working capital deficit of $22.3 million. This calculation excludes current maturities of long-term debt and the current portion of assets and liabilities from derivatives. We believe the cash flows from operating activities and our recent equity offering 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 and comply with our debt covenant requirements in future periods. We are taking necessary steps to manage the business to meet such requirements.

Our 2003 planned development and acquisition programs are projected to be substantially funded by available cash flow from our 2003 operations. In addition to these measures, we are currently in preliminary discussions with potential investors to provide additional capital. These discussions involve potential increases to our current credit facilities, new credit facilities and the sale of interests in selected properties. We have also explored the possibility of the issuance of new debt. Completion of any of these potential financings would expand our capabilities to further reduce our outstanding indebtedness, improve our working capital position and may allow us to expand or accelerate our future development and acquisition programs. There can be no assurance however, that we will be successful in negotiating any of these transactions or that the form of the transaction will be acceptable to both the potential investor and our management or our board of directors.

Commitments and 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. Development has been completed on our Helvellyn property and future development is planned on the other two properties. First commercial production from the Helvellyn property is expected to occur during the second quarter of 2003 and accordingly, contingent consideration has been accrued for payment and capitalized as acquisition costs.

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In March 2003, we entered into an agreement with a working interest participant whereby they were obligated to pay us approximately $8.1 million related to the development of one of our properties. Per the agreement, we have 60 months from receipt of those funds to develop the property. If we have not developed the property prior to expiration of the 60 months, we are required to return the funds plus interest from the date the funds are received. At March 31, 2003, this amount is recorded in accounts receivable on the consolidated balance sheet. The corresponding obligation is reflected in other long-term liabilities and deferred obligations until such time as we have satisfied our obligations under the agreement. We received the funds on April 25, 2003.

ATP filed suit against Legacy Resources Co., LLP and agent (“Legacy”) in the District Court of Harris County, Texas in a dispute over a contract for the sale by Legacy of an oil and gas property to ATP. The court has abated the litigation pursuant to an arbitration provision in the contract. In the arbitration proceedings Legacy alleges that ATP owes it $12.3 million plus interest and expenses. ATP intends to vigorously defend against these claims. The judge has abated the litigation, until arbitration pursuant to the underlying agreements between the sellers and ATP is completed. A date of May 19, 2003 has been scheduled for the arbitration with an alternative date in September 2003. Due to the uncertainties of the legal and arbitration proceedings, a prediction of the outcome cannot be made with any degree of certainty and we have not accrued any amount related to this matter. Payments totaling $3.0 million made to Legacy in October of 2001 under the original contract were charged to earnings in 2001 along with all other costs related to this matter.

In August 2001, Burlington Resources Inc. filed suit against ATP alleging formation of a contract with ATP and our breach of the alleged contract. The complaint seeks compensatory damages of approximately $1.1 million. We intend to defend against these claims vigorously. It is not possible to predict with certainty whether we will incur any liability or to estimate the possible range of loss, if any, that we might incur in connection with this lawsuit.

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.

Accounting Pronouncements

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

Item 3. Quantitative and Qualitative Disclosures about Market Risks

We are exposed to various market risks, including volatility in natural gas and oil commodity prices and interest rates. To manage such exposure, we monitor our expectations of future commodity prices and interest rates when making decisions with respect to risk management. Substantially all of our derivative contracts are entered into with counter parties which we believe to be of high credit quality and the risk of credit loss is considered insignificant. We have never experienced a loss on a derivative contract due to the inability of the counter party to fulfill their portion of the contract.

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. The amount we can borrow under our bank credit facility is subject to periodic re-determination based in part on changing expectations of future prices. 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. To reduce exposure to fluctuations in natural gas and oil prices and to achieve more predictable cash flows, we periodically enter into arrangements that usually consist of swaps or price collars that are settled in cash. However, these contracts also limit the benefits we would realize if commodity prices increase. In addition to these arrangements, we also manage our exposure to oil and gas price risks by periodically entering into fixed-price delivery contracts. (See Note 5 to our Consolidated Financial Statements for a discussion of activities involving derivative

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financial instruments during 2003.) 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 will 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.

To calculate the potential effect of the derivative and fixed-price contracts on future income (loss) before taxes, we applied the NYMEX oil and gas strip prices as of March 31, 2003 to the quantity of our oil and gas production covered by those contracts as of that date. The following table shows the estimated potential effects of the derivative and fixed-price contracts on future income (loss) before taxes (in thousands):

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 agreements. 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 subsidiary 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.

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 2002 Form 10-K.

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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

A. Exhibits

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 and thereunto duly authorized.

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CERTIFICATIONS

I, T. Paul Bulmahn, certify that:

1. I have reviewed this quarterly report on Form 10-Q of ATP Oil & Gas Corporation;

2. Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report;

3. Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this quarterly report;

4. The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:

a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared;

b) evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the “Evaluation Date”); and

c) presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent function):

a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant’s auditors any material weaknesses in internal controls; and

b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and

6. The registrant’s other certifying officers and I have indicated in this quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.