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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

For the quarterly period ended September 30, 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 November 3, 2004, was 24,801,627.

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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 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 oil and gas 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 oil and gas 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 hereto should be read in conjunction with our 2003 Annual Report on Form 10-K. The results of operations for the nine months ended September 30, 2004 are not necessarily indicative of results to be expected for the entire year.

Note 2 — Recent Accounting Pronouncements

On March 31, 2004, the Financial Accounting Standards Board (“FASB”) issued a proposed statement, “Share-Based Payment”, that addresses the accounting for share-based payment transactions (for example, stock options and awards of restricted stock) in which an employer receives employee-services in exchange for equity securities of the company or liabilities that are based on the fair value of the company’s equity securities. The new standard, as proposed, would eliminate the use of APB Opinion No. 25, Accounting for Stock Issued to Employees, and generally would require such transactions be accounted for using a fair-value-based method and recording compensation expense rather than the optional pro forma disclosure of what expense amounts might be. Public companies with calendar year-ends would be required to adopt the provisions of the standard effective for periods beginning after June 15, 2005, rather than January 1, 2005 as originally proposed.

On September 2, 2004, the FASB issued FASB Staff Position No. FAS 142-2, “Application of FASB Statement No. 142, Goodwill and Other Intangible Assets, to Oil and Gas Producing Entities, (“FSP FAS 142-2”) addressing whether the scope exception within Statement of Financial Accounting Standards (“SFAS”) No. 142, “Goodwill and Other Intangible Assets” (“SFAS 142”) includes the balance sheet classification and disclosures for drilling and mineral rights of oil and gas producing properties. The FASB staff concluded that the accounting framework for oil and gas entities is based on the level of established reserves, not whether an asset is tangible or intangible, and thus the scope exception extended to the balance sheet classification and disclosure provisions for such 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. SFAS 143 requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. The associated asset retirement 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 SFAS 143, 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 September 30, 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 January 1, 2004 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 (5.2% of our GOM reserves), 94% 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. Upon finalization of the sale, the purchase price was adjusted by $0.3 million for certain amounts owed to the purchaser.

The $19.2 million in net proceeds was allocated among the fair values of the properties sold in both stages. We recorded a gain of approximately $6.0 million in the first half of 2004.

Note 5 — Long-Term Debt

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

On March 29, 2004, we entered into a new $185.0 million term loan (“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. 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.

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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 the lender to purchase 750,000 shares of our common stock. The warrants were issued with an exercise price of $6.75 per share, had an expiration of February 16, 2009 and were accounted for as additional paid-in-capital. 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. On March 29, 2004 these warrants were repurchased for $750,000 and retired with a decrease to additional paid-in-capital.

The Term Loan was issued on March 29, 2004 at an average annual interest rate of 10.8%. The $150.0 million term loan bore 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. The $35.0 million term loan bore interest at the base rate plus a margin of 9.0% or LIBOR (with a 2% floor) plus a margin of 10.0% at our election.

In connection with the issuance of the Term Loan, we paid fees and expenses of $8.6 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 on March 29, 2004, was approximately $4.2 million and was 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 is being accreted over the life of the loan as additional interest expense.

On September 24, 2004, the Term Loan was amended to effect the following:

In addition, under the first and second lien facilities, the lender consented to the repurchase by the borrower of 1,926,837 of the 2,432,336 outstanding second lien facility warrants for a price not to exceed $11,561,022. The warrants were repurchased on September 24, 2004 for $6.00 per warrant which, in management’s estimation, represented the current fair value of the unregistered warrants as of that date. The $11.6 million partial repurchase was recorded as a decrease to additional paid in capital while the debt discount will continue to be amortized over the life of the loan.

Net proceeds from the additional borrowing were $18.4 million after the warrant repurchase and fees and expenses of $5.0 million. Of the $5.0 million, $4.9 million paid to the Lender was capitalized and will be amortized over the remaining life of the loan and $0.1 million of third party legal fees was expensed.

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The terms of the Term Loan, as amended September 24, 2004, require us to maintain certain covenants. Capitalized terms are defined in the credit agreement for the Term Loan. The covenants include:

As of September 30, 2004, we were in compliance with all of the financial covenants of our Term Loan. Significant adverse changes in our expected production levels, commodity prices and reserves or material delays or cost overruns 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.

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,” 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 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 (in thousands, except per share amounts):

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Note 7 — Earnings Per Share

Basic earnings per share is computed by dividing net income 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 and warrants have been converted using the average price for the period.

Basic and diluted net income 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 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 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 current 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 September 30, 2004, Accumulated Other Comprehensive Income included $2.1 million of unrealized losses on our natural gas sales swaps. Gains and losses are reclassified from Accumulated Other Comprehensive Income to the consolidated statement of operations as a component of oil and gas revenues in the period the hedged production occurs. If any ineffectiveness occurs, amounts are recorded directly to the consolidated statement of operations as a component of oil and gas revenues. All of this deferred loss will be reversed during the period in which the forecasted transactions actually occur.

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At September 30, 2004, we had three natural gas swaps that qualified as cash flow hedges 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 September 30, 2004, we had fixed-price contracts in place for the following oil and gas 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 threshold of first commercial production has been achieved for one property, such related contingent consideration has been accrued for payment in the consolidated financial statements. Upon achievement of the second threshold for the one property, the remaining contingent consideration will be accrued and capitalized at that time. Future development is planned on the other two properties and when they reach their respective thresholds, the appropriate consideration will be recorded.

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.

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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. Segment activity for the three and nine months ended September 30, 2004 and 2003 is as follows (in thousands):

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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 oil and gas properties in the Gulf of Mexico and the North Sea. We seek to acquire and develop properties with proved undeveloped reserves 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 primarily through the acquisition and development of proved oil and gas reserves in areas that have:

Source of Revenue

We derive our revenues from the sale of oil and gas that is produced from our oil and gas properties. Revenues are a function of the volume produced and the prevailing market price at the time of sale. The price of oil and 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 oil and natural gas production. The use of certain types of derivative instruments may prevent us from realizing the full benefit of upward price movements.

Third Quarter 2004 Highlights

Our financial and operating performance for the third 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 September 30, 2004 Compared to Three Months Ended September 30, 2003

For the three months ended September 30, 2004, we reported net income of $0.6 million, or $0.03 per share, on total revenue of $26.3 million as compared with a net loss of $15.0 million, or $0.61 per share, on total revenue of $17.2 million for the three months ended September 30, 2003.

Oil and Gas Revenues

Revenues presented in the table and discussion below represent revenue from sales of our oil and natural gas production volumes. Production sold under fixed price delivery contracts, which have been designated for the normal purchase and sale exemption under SFAS 133, are also included in these amounts. Approximately 65% and 17% of our oil production was sold under these contracts for the three months ended September 30, 2004 and 2003, respectively. Approximately 63% and 43% of our natural gas production was sold under these contracts for the comparable periods. The realized prices below may differ from the market prices in effect during the periods depending on when the fixed price delivery contract was executed.