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UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-K

For the Fiscal Year Ended December 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)

(Registrant’s telephone number, including area code): (713) 622-3311

Securities Registered Pursuant to Section 12 (b) of the Act:

Securities Registered Pursuant to Section 12 (g) of the Act: None

Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities exchange Act of 1934 during the preceding 12 months (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 if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of Registrant’s knowledge, in definitive proxy or information statements incorporated by Reference in Part III of this Form 10-K or any amendment to this Form 10-K. ¨

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

The aggregate market value of the voting and non-voting common stock held by non-affiliates of the Registrant as of June 30, 2004 (the last business day of the Registrant’s most recently completed second fiscal quarter) was approximately $94,935,548. The number of shares of the Registrant’s common stock outstanding as of March 25, 2005 was 28,966,358.

DOCUMENTS INCORPORATED BY REFERENCE: Selected portions of the ATP Oil & Gas Corporation’s definitive Proxy Statement, which will be filed with the Securities and Exchange Commission within 120 days after December 31, 2004, are incorporated by reference in Part III of this Form 10-K.

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ATP OIL & GAS CORPORATION AND SUBSIDIARIES

2004 FORM 10-K ANNUAL REPORT

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Cautionary Statement About Forward-Looking Statements

As used in this Annual Report on Form 10-K, the terms “ATP”, “we”, “us”, “our” and similar terms refer to ATP Oil & Gas Corporation and its subsidiaries, unless the context indicates otherwise.

This annual report includes assumptions, expectations, projections, intentions or beliefs about future events. These statements are intended as “forward-looking statements” under the Private Securities Litigation Reform Act of 1995. We caution that assumptions, expectations, projections, intentions and beliefs about future events may and often do vary from actual results and the differences can be material.

All statements in this document that are not statements of historical fact are forward looking statements. Forward looking statements include, but are not limited to:

When used in this document, the words “anticipate,” “estimate,” “project,” “forecast,” “may,” “should,” and “expect” reflect forward-looking statements.

There can be no assurance that actual results will not differ materially from those expressed or implied in such forward looking statements. Some of the key factors which could cause actual results to vary from those expected include:

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CERTAIN DEFINITIONS

As used herein, the following terms have specific meanings as set forth below:

Crude oil and other liquid hydrocarbons are converted into cubic feet of gas equivalent based on six Mcf of gas to one barrel of crude oil or other liquid hydrocarbons.

Development well is a well drilled within the proved area of an oil or natural gas field to the depth of a stratigraphic horizon known to be productive.

Dry hole is a well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.

Exploratory well is a well drilled to find and produce oil or natural gas reserves in an unproved area, to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir, or to extend a known reservoir.

Farm-in or farm-out is an agreement whereby the owner of a working interest in an oil and gas lease or license assigns the working interest or a portion thereof to another party who desires to drill on the leased or licensed acreage. Generally, the assignee is required to drill one or more wells in order to earn its interest in the acreage. The assignor usually retains a royalty or reversionary interest in the lease. The interest received by an assignee is a “farm-in,” while the interest transferred by the assignor is a “farm-out.”

Field is an area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature or stratigraphic condition.

PV-10 is the pre-tax present value, discounted at 10% per year, of estimated future net revenues from the production of proved reserves, computed by applying sales prices in effect as of the dates of such estimates and held constant throughout the productive life of the reserves (except for consideration of price changes to the extent provided by contractual arrangements), and deducting the estimated future costs to be incurred in developing, producing and abandoning the proved reserves (computed based on current costs and assuming continuation of existing economic conditions).

Productive well is a well that is producing or is capable of production, including natural gas wells awaiting pipeline connections to commence deliveries and oil wells awaiting connection to production facilities.

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Proved reserves are the estimated quantities of oil and gas which geological and engineering data demonstrate, with reasonable certainty, can be recovered in future years from known reservoirs under existing economic and operating conditions. Reservoirs are considered proved if shown to be economically producible by either actual production or conclusive formation tests.

Proved developed reserves are the portion of proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.

Proved undeveloped reserves are the portion of proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

Working interest is the operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and a share of production.

Workover is operations on a producing well to restore or increase production.

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PART I

General

ATP Oil & Gas Corporation was incorporated in Texas in 1991. We are engaged in the acquisition, development and production of oil and natural gas properties in the Gulf of Mexico and the North Sea. We primarily focus our efforts on oil and natural gas properties where previous drilling has encountered reservoirs that appear to contain commercially productive quantities of oil and gas. Many of these properties contain proved undeveloped reserves that are economically attractive to us but are not strategic to major or exploration-oriented independent oil and gas companies. Our management team has extensive engineering, geological, geophysical, technical and operational expertise in successfully developing and operating properties in both our current and planned areas of operation.

At December 31, 2004, we had estimated net proved reserves of 275.2 Bcfe, of which approximately 180.7 Bcfe (66%) was in the Gulf of Mexico and 94.5 Bcfe (34%) was in the North Sea. Year-end reserves were comprised of 205.2 Bcf of natural gas and 11.7 MMBbls of oil. The majority of our oil reserves are located in the Gulf of Mexico and approximately 54% of our natural gas reserves are located in the Gulf of Mexico with the balance located in the North Sea. The estimated pre-tax PV-10 of our proved reserves at December 31, 2004 was $732.8 million. See “Item 2. Properties – Oil and Natural Gas Reserves” for a reconciliation to after-tax PV-10.

At December 31, 2004, we had leasehold and other interests in 52 offshore blocks, 26 platforms and 68 wells, including five subsea wells, in the Gulf of Mexico. We operate 56 of these 68 wells, including all of the subsea wells, and 85% of our offshore platforms. We also had interests in ten blocks and one company-operated subsea well in the North Sea. Our average working interest in our properties at December 31, 2004 was approximately 79%. For more information regarding our operations and assets in the Gulf of Mexico and North Sea, see Note 14, “Segment Information,” to the Notes to Consolidated Financial Statements.

Our Business Strategy

Our business strategy is to enhance shareholder value primarily through the acquisition, development and production of properties that we believe contain oil and natural gas in commercial quantities in areas that have:

We believe our strategy significantly reduces the risks associated with traditional oil and natural gas exploration. Our focus is to acquire properties that have been explored by others and found to contain proved reserves. Occasionally we will acquire properties where previous drilling has encountered reservoirs that appear to contain commercially productive quantities of oil and gas even though the reservoirs do not meet the SEC definition of proved reserves. From the inception of operations through March 25, 2005, we have successfully brought to production 37 out of 38 projects from previously undeveloped reservoirs, a 97% success ratio.

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We focus on acquiring properties that contain proved undeveloped reserves that have become non-core or non-strategic to their original owners for various reasons. For example, larger oil companies from time to time adjust their capital spending or shift their focus to exploration prospects with greater reserve potential. Some projects provide lower economic returns to a larger company due to its cost structure. Also, due to timing or budget constraints, a company may be unable or unwilling to develop a property before the expiration of the lease and desire to sell the property before it forfeits its lease rights. Because of our cost structure, expertise in our areas of focus and our ability to develop projects efficiently, these properties may be economically attractive to us.

By focusing on properties that are not strategic to other companies and properties that are primarily proved but as yet undeveloped, we are able to minimize up front acquisition costs and concentrate available capital on the development phase of these properties. Since our inception in 1991 through December 31, 2004, we have added 483.1 Bcfe of proved oil and natural gas reserves through acquisitions at a total cost of $78.7 million or $0.16 per Mcfe. Development costs for this same period were approximately $453.1 million.

We focus on developing projects in the shortest time possible between initial investment and first revenue generated in order to maximize our rate of return. Since we operate a significant number of the properties in which we acquire a working interest, we are able to significantly influence the time of a project’s development. We typically initiate new development projects by simultaneously obtaining the various required components such as the pipeline and the production platform or subsea well completion equipment. We believe this strategy, combined with our ability to evaluate and implement a project’s requirements, allows us to efficiently complete the development project and commence production quickly.

Our Strengths

Marketing and Delivery Commitments

We sell our oil and natural gas production under price sensitive or market price contracts. Our revenues, profitability and future growth depend substantially on prevailing prices for oil and natural gas. The price received by us for our oil and natural gas production can fluctuate widely. Changes in the prices of oil and natural gas will affect the carrying value of our proved reserves as well as our revenues, profitability and cash flow. Although we are not currently experiencing any significant involuntary curtailment of our natural gas or oil production, market, economic and regulatory factors may in the future materially affect our ability to sell our natural gas or oil production.

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We sell a portion of our oil and natural gas to end users through various non-affiliated gas marketing companies. Historically, we have sold our oil and natural gas to a relatively few number of purchasers. However, we are not dependent upon, or confined to, any one purchaser or small group of purchasers. Due to the nature of oil and natural gas markets and because oil and natural gas are commodities and there are numerous purchasers in the areas in which we sell production, we do not believe the loss of a single purchaser, or a few purchasers, would materially affect our ability to sell our production.

Competition

We compete with major and independent oil and natural gas companies for property acquisitions. We also compete for the equipment and labor required to operate and to develop these properties. Some of our competitors have substantially greater financial and other resources and may be able to sustain wide fluctuations in the economics of our industry more easily than we can. Since we are in a highly regulated industry, they may be able to absorb the burden of any changes in federal, state and local laws and regulations more easily than we can. Our ability to acquire and develop additional properties in the future will depend upon our ability to conduct operations, to evaluate and select suitable properties, to secure adequate financing and to consummate transactions in this highly competitive environment.

Regulation

Gulf of Mexico

Federal Regulation of Sales and Transportation of Natural Gas. Historically, the transportation and sale for resale of natural gas in interstate commerce has been regulated pursuant to the Natural Gas Act of 1938 (“the Natural Gas Act”), the Natural Gas Policy Act of 1978 and Federal Energy Regulatory Commission (“FERC”) regulations. In the past, the federal government has regulated the prices at which natural gas could be sold. Deregulation of natural gas sales by producers began with the enactment of the Natural Gas Policy Act of 1978. In 1989, Congress enacted the Natural Gas Wellhead Decontrol Act, which removed all remaining Natural Gas Act and Natural Gas Policy Act of 1978 price and non-price controls affecting producer sales of natural gas effective January 1, 1993.

Our sales of natural gas are affected by the availability, terms and cost of pipeline transportation. The price and terms for access to pipeline transportation are subject to extensive federal regulation. The FERC requires interstate pipelines to provide open-access transportation on a not unduly discriminatory basis for all natural gas shippers. The FERC frequently reviews and modifies its regulations regarding the transportation of natural gas, with the stated goal of fostering competition within all phases of the natural gas industry. We cannot predict what further action the FERC will take with regard to its regulations and open-access policies, nor can we accurately predict whether the FERC’s actions will achieve the goal of increasing competition in markets in which our natural gas is sold. However, we do not believe that any action taken will affect us in a way that materially differs from the way it affects other natural gas producers, gatherers and marketers.

The Outer Continental Shelf Lands Act, which the FERC implements with regard to transportation and pipeline issues, requires that all pipelines operating on or across the Outer Continental Shelf provide open-access, non-discriminatory service. There are currently no regulations implemented by FERC under its Outer Continental Shelf Lands Act authority on gatherers and other entities outside the reach of its Natural Gas Act jurisdiction. The Minerals Management Service, or MMS, has asked for comments on whether it should implement regulations under its Outer Continental Shelf Lands Act authority on gatherers and other entities to ensure open and non-discriminatory access on gathering systems and production facilities on the Outer Continental Shelf. Although we have no way of knowing whether the MMS will proceed with implementing regulations of this nature, we do not believe that any FERC action taken under its Outer Continental Shelf Lands Act jurisdiction will affect us in a way that materially differs from the way it affects other natural gas producers, gatherers and marketers.

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The natural gas industry historically has been very heavily regulated; therefore, there is no assurance that the current regulatory approach by the FERC and Congress will continue. Additional proposals and proceedings that might affect the natural gas industry are pending before Congress, the FERC and the courts.

Federal Leases. A substantial portion of our operations is located on federal oil and natural gas leases, which are administered by the MMS pursuant to the Outer Continental Shelf Lands Act. These leases are issued through competitive bidding and contain relatively standardized terms. These leases require compliance with detailed MMS regulations and orders that are subject to interpretation and change by the MMS.

For offshore operations, lessees must obtain MMS approval for exploration, development and production plans prior to the commencement of such operations. In addition to permits required from other agencies such as the Coast Guard, the Army Corps of Engineers and the Environmental Protection Agency, lessees must obtain a permit from the MMS prior to the commencement of drilling. The MMS has promulgated regulations requiring offshore production facilities located on the Outer Continental Shelf to meet stringent engineering and construction specifications. The MMS also has regulations restricting the flaring or venting of natural gas, and has proposed to amend such regulations to prohibit the flaring of liquid hydrocarbons and oil without prior authorization. Similarly, the MMS has promulgated other regulations governing the plugging and abandonment of wells located offshore and the installation and removal of all production facilities.

To cover the various obligations of lessees on the Outer Continental Shelf, the MMS generally requires that lessees have substantial net worth or post bonds or other acceptable assurances that such obligations will be satisfied. The cost of these bonds or assurances can be substantial, and there is no assurance that they can be obtained in all cases. We currently have several supplemental bonds in place. Under some circumstances, the MMS may require any of our operations on federal leases to be suspended or terminated. Any such suspension or termination could materially adversely affect our financial condition and results of operations.

The MMS also administers the collection of royalties under the terms of the Outer Continental Shelf Lands Act and the oil and gas leases issued under the Act. The amount of royalties due is based upon the terms of the oil and gas leases as well as of the regulations promulgated by the MMS. The MMS regulations governing the calculation of royalties and the valuation of crude oil produced from federal leases currently rely on arm’s-length sales prices and spot market prices as indicators of value. On May 5, 2004, the MMS issued a final rule that changed certain components of its valuation procedures for the calculation of royalties owed for crude oil sales. The changes include changing the valuation basis for transactions not at arm’s-length from spot to NYMEX prices adjusted for locality and quality differentials, and clarifying the treatment of transactions under a joint operating agreement. We believe this rule will not have a material impact on our financial condition, liquidity or results of operations.

Oil Price Controls and Transportation Rates. Sales of crude oil, condensate and natural gas liquids by us are not currently regulated and are made at market prices. In a number of instances, however, the ability to transport and sell such products is dependent on pipelines whose rates, terms and conditions of service are subject to FERC jurisdiction under the Interstate Commerce Act. In other instances, the ability to transport and sell such products is dependent on pipelines whose rates, terms and conditions of service are subject to regulation by state regulatory bodies under state statutes.

The regulation of pipelines that transport crude oil, condensate and natural gas liquids is generally more light-handed than the FERC’s regulation of gas pipelines under the Natural Gas Act. Regulated pipelines that transport crude oil, condensate, and natural gas liquids are subject to common carrier obligations that generally ensure non-discriminatory access. With respect to interstate pipeline transportation subject to regulation of the FERC under the Interstate Commerce Act, rates generally must be cost-based, although market-based rates or negotiated settlement rates are permitted in certain circumstances. Pursuant to FERC Order No. 561, issued in October 1993, the FERC implemented regulations generally grandfathering all previously unchallenged interstate pipeline rates and made these rates subject to an indexing methodology. Under this indexing methodology, pipeline rates are subject to changes in the Producer Price Index for Finished Goods. A pipeline can seek to increase its rates above index levels provided that the pipeline can establish that there is a substantial divergence between the actual costs experienced by the pipeline and the rate resulting from application of the index. A pipeline

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can seek to charge market-based rates if it establishes that it lacks significant market power. In addition, a pipeline can establish rates pursuant to settlement if agreed upon by all current shippers. A pipeline can seek to establish initial rates for new services through a cost-of-service proceeding, a market-based rate proceeding, or through an agreement between the pipeline and at least one shipper not affiliated with the pipeline. As provided for in Order No. 561, the FERC’s indexing methodology is subject to review at five year intervals, with the next review scheduled for July 2005.

With respect to intrastate crude oil, condensate and natural gas liquids pipelines subject to the jurisdiction of state agencies, such state regulation is generally less rigorous than the regulation of interstate pipelines. State agencies have generally not investigated or challenged existing or proposed rates in the absence of shipper complaints or protests. Complaints or protests have been infrequent and are usually resolved informally.

We do not believe that the regulatory decisions or activities relating to interstate or intrastate crude oil, condensate, or natural gas liquids pipelines will affect us in a way that materially differs from the way it affects other crude oil, condensate, and natural gas liquids producers or marketers.

Environmental Regulations. Our operations are subject to stringent laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. These laws and regulations may require the acquisition of a permit before drilling commences, restrict the types, quantities and concentration of various substances that can be released into the environment, and impose substantial liabilities for pollution. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations, and the issuance of injunctive relief. Offshore drilling in some areas has been opposed by environmental groups and, in some areas, has been restricted by governmental entities. Moreover, changes in environmental laws and regulations have increased in recent years. Any laws that are enacted or other governmental actions that are taken to prohibit or restrict offshore drilling or to impose more stringent or costly environmental protection requirements could have a material adverse affect on the natural gas and oil industry in general and our offshore operations in particular. While we believe that we are in substantial compliance with current environmental laws and regulations and that continued compliance with existing requirements will not materially affect us, there is no assurance that this trend will continue in the future.

The Oil Pollution Act of 1990, also known as “OPA,” and related regulations impose a variety of regulations on “responsible parties” related to the prevention of oil spills and liability for damages resulting from such spills in U.S. waters. A “responsible party” includes the owner or operator of a facility or vessel, or the lessee or permittee of the area in which an offshore facility is located. The OPA assigns liability to each responsible party for the costs of cleaning up an oil spill and for a variety of public and private damages resulting from a spill. While liability limits apply in some circumstances, a party cannot take advantage of liability limits if the spill was caused by a party’s gross negligence or willful misconduct, a violation of a federal safety, construction or operating regulation, or a failure to report a spill or to cooperate fully in a cleanup. Even if applicable, the liability limits for offshore facilities require the responsible party to pay all removal costs, plus up to $75 million in other damages. Few defenses exist to the liability imposed by the Oil Pollution Act of 1990.

The OPA also requires a responsible party to submit proof of its financial responsibility to cover environmental cleanup and restoration costs that could be incurred in connection with an oil spill. Under this Act, parties responsible for offshore facilities must provide financial assurance of at least $35 million to address oil spills and associated damages, with this financial assurance amount increasing up to $150 million in certain limited circumstances if the MMS determines that a higher amount is warranted. The OPA also imposes other requirements, such as the preparation of an oil spill contingency plan, which we have in place.

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We are also regulated by the Clean Water Act, which prohibits any discharge of pollutants into waters of the U.S. except in strict conformance with discharge permits issued by federal or state agencies. We have obtained, and are in material compliance with, the discharge permits necessary for our operations. We are also subject to similar state and local water quality laws and regulations for any production or drilling activities that occur in state coastal waters. Failure to comply with the ongoing requirements of the Clean Water Act or analogous state laws may subject a responsible party to administrative, civil or criminal enforcement actions.

In addition, the Outer Continental Shelf Lands Act authorizes regulations relating to safety and environmental protection applicable to lessees and permittees operating on the Outer Continental Shelf. Specific design and operational standards may apply to Outer Continental Shelf vessels, rigs, platforms and structures. Violations of lease conditions or regulations issued pursuant to the Outer Continental Shelf Lands Act can result in substantial civil and criminal penalties, as well as potential court injunctions curtailing operations and the cancellation of leases. Such enforcement liabilities can result from either governmental or private prosecution

The Comprehensive Environmental Response, Compensation, and Liability Act, or “CERCLA,” also known as the “Superfund” law, imposes liability, without regard to fault or the legality of the original conduct, on certain classes of persons that are considered to have contributed to the release of a “hazardous substance” into the environment. These persons include the owner or operator of the disposal site or sites where the release occurred and companies that disposed or arranged for the disposal of the hazardous substances found at the site. Under CERCLA, responsible persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources, and it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment.

We may also incur liability under the Resource Conservation and Recovery Act, or “RCRA,” which imposes requirements relating to the management and disposal of solid and hazardous wastes. While there exists an exclusion from the definition of hazardous wastes for “drilling fluids, produced waters, and other wastes associated with the exploration, development, or production of crude oil, natural gas or geothermal energy,” in the course of our operations, we may generate ordinary industrial wastes, including paint wastes, waste solvents, and waste compressor oils that may be regulated as hazardous substances or hazardous waste. Consequently, we may incur liability for such hazardous substances and hazardous waste under CERCLA, RCRA, and analogous state laws. Under such laws, we could be required to remediate previously disposed wastes or to perform remedial operations to prevent future contamination.

Our operations are also subject to regulation of air emissions under the Clean Air Act and the Outer Continental Shelf Lands Act. Implementation of these laws could lead to the gradual imposition of new air pollution control requirements on our operations. Therefore, we may incur capital expenditures over the next several years to upgrade our air pollution control equipment. We could also become subject to similar state and local air quality laws and regulations in the future if we conduct production or drilling activities in state coastal waters. However, we do not believe that our operations would be materially affected by any such requirements, nor do we expect such requirements to be anymore burdensome to us than to other companies our size involved in similar natural gas and oil development and production activities.

North Sea

Regulation of Natural Gas and Oil Production. Pursuant to the Petroleum Act 1998, all natural gas and oil reserves contained in properties located in the U.K. are the property of the U.K. government. The development and production of natural gas and oil reserves in the U.K. Sector - North Sea requires a petroleum production license granted by the U.K. government. Prior to developing a field, we are required to obtain from the Secretary of State for Trade and Industry (the “Secretary of State”) a consent to develop that field. We would be required to obtain the consent of the Secretary of State prior to transferring an interest in a license.

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The terms of the U.K. petroleum production licenses are based on model license clauses applicable at the time of the issuance of the license. Licenses frequently contain regulatory provisions governing matters such as working method, pollution and training, and reserve to the Secretary of State the power to direct some of the licensee’s activities. For example, a licensee may be precluded from carrying out development or production activities other than with the consent of the Secretary of State or in accordance with a development plan which the Secretary of State for Trade and Industry has approved. Breach of these requirements may result in the revocation of the license. In addition, licenses that we acquire may require us to pay fees and royalties on production and also impose certain other duties on us.

Our operations in the U.K. are subject to the Petroleum Act 1998, which imposes a health and safety regime on offshore natural gas and oil production activities. The Petroleum Act 1998 also regulates the abandonment of facilities by licensees. In addition, the Mineral Workings (Offshore Installations) Act provides a framework in which the government can impose additional regulations relating to health and safety. Since its enactment, a number of regulations have been promulgated relating to offshore construction and operation of offshore production facilities. Health and safety offshore is further governed by the Health and Safety at Work Act 1974 and applicable regulations.

Our operations are also subject to environmental laws and regulations imposed by both the European Union and the U.K. government. The offshore industry in the U.K. is regulated with regard to the environment both before activity commences and during the conduct of exploration and production activities. The licensing regime seeks to employ a preventive and precautionary approach. This is evident in the consultation which takes place before a U.K. licensing round begins, whereby the Secretary of State, acting through the Department of Trade and Industry (“DTI”), will consult with various public bodies having responsibility for the environment. Applicants for production licenses are required to submit a statement of the general environmental policy of the operator in respect of the contemplated license activities and a summary of its management systems for implementation of that policy and how those systems will be applied to the proposed work program. In addition, the Offshore Petroleum Production and Pipe-lines (Assessment of Environmental Effects) Regulations 1999, require the Secretary of State to exercise his licensing powers under the Petroleum Act 1998 in such a way to ensure that an environmental assessment is undertaken and considered before consent is given to certain projects.

We believe that our operations in the North Sea are in substantial compliance with current applicable environmental laws and regulations. While we expect that continued compliance with existing environmental requirements will not have a material adverse impact on us, there is no assurance that this trend will continue in the future.

Petroleum production licenses require the prior approval of the Secretary of State of a licensee to act as operator. The operator under a license organizes or supervises all or any of the development and production operations of natural gas and oil properties subject thereto. As an operator, we may obtain operational services from third parties, but will remain fully responsible for the operations as if we conduct them ourselves.

Our operations in the U.K. may entail the construction of offshore pipelines, which are subject to the provisions of the Petroleum Act 1998 and other legislation. The Petroleum Act 1998 requires a license to construct and operate a pipeline in U.K. North Sea, including its continental shelf. Easements to permit the laying of pipelines must be obtained from the Crown Estate Commissioners prior to their construction. We plan to use capacity in existing offshore pipelines in order to transport our gas. However, access to the pipelines of a third party would need to be obtained on a negotiated basis, and there is no assurance that we can obtain access to existing pipelines or, if access is obtained, it may only be on terms that are not favorable to us.

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The natural gas we produce may be transported through the U.K.’s onshore national gas transmission system, or NTS. The NTS is owned by a licensed gas transporter, BG Transco plc (“Transco”). The terms on which Transco must transport gas are governed by the Gas Acts of 1986 and 1995, the gas transporter’s license issued to Transco under those Acts and a network code. For us to use the NTS, we must obtain a shipper’s license under the Gas Acts and arrange to have gas transported by Transco within the NTS. We will therefore be subject to the network code, which imposes obligations to payment, gas flow nominations, capacity booking and system imbalance. Applying for and complying with a shipper’s license, and acting as a gas shipper, is expensive and administratively burdensome. Alternatively, we may sell natural gas ‘at the beach’ before it enters the NTS or arrange with an existing gas shipper for them to ship the gas through the NTS on our behalf.

Risk Factors

You should carefully consider the following risk factors in addition to the other information included in this report. Each of these risk factors could adversely affect our business, operating results and financial condition, as well as adversely affect the value of an investment in our common stock or other securities.

Our actual development results are likely to differ from our estimates of our proved reserves. We may experience production that is less than estimated and development costs that are greater than estimated in our reserve reports. Such differences may be material.

Estimates of our oil and natural gas reserves and the costs associated with developing these reserves may not be accurate. Development of our reserves may not occur as scheduled and the actual results may not be as estimated. Development activity may result in downward adjustments in reserves or higher than estimated costs.

Our estimates of our proved oil and natural gas reserves and the estimated future net revenues from such reserves are based upon various assumptions, including assumptions required by the SEC relating to oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. This process requires significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir. Therefore, these estimates are inherently imprecise and the quality and reliability of this data can vary.

Any significant variance could materially affect the estimated quantities and PV-10 of reserves that we disclose publicly. Our properties may also be susceptible to hydrocarbon drainage from production by other operators on adjacent properties. In addition, we will likely adjust estimates of proved reserves to reflect production history, results of development, prevailing oil and natural gas prices and other factors, many of which are beyond our control. Actual production, revenues, taxes, development expenditures and operating expenses with respect to our reserves may vary materially from our estimates.

Delays in the development of or production curtailment at our material properties may adversely affect our financial position and results of operations.

The size of our operations and our capital expenditure budget limits the number of wells that we can develop in any given year. Complications in the development of any single material well may result in a material adverse affect on our financial condition and results of operations. For instance, during 2003, we experienced unforeseen production delays and increased development costs in connection with the development of our Helvellyn well in the North Sea which, combined with our significant capital requirements for the development of several of our Gulf of Mexico properties, contributed to our constrained liquidity position at the end of 2003.

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In addition, a relatively few number of wells contribute to a substantial portion of our production. If we were to experience operational problems resulting in the curtailment of production in any of these wells, our total production levels would be adversely affected, which would have a material adverse affect on our financial condition and results of operations.

The unavailability or increased cost of drilling rigs, equipment, supplies, personnel and oilfield services could adversely affect our ability to execute on a timely basis our development plans within our budget.

Shortages or an increase in cost of drilling rigs, equipment, supplies or personnel could delay or adversely affect our operations, which could have a material adverse effect on our business, financial condition and results of operations. In periods of increased drilling activity in the Gulf of Mexico and the North Sea, we may experience increases in associated costs, including those related to drilling rigs, equipment, supplies and personnel and the services and products of other vendors to the industry. Increased drilling activity in the Gulf of Mexico and the North Sea also decreases the availability of offshore rigs. These costs may increase further and necessary equipment and services may not be available to us at economical prices.

Our offshore properties are subject to rapid production declines. Therefore, we are required to replace our reserves at a faster rate than companies whose onshore reserves have longer production periods. We may not be able to identify or complete the acquisition of properties with sufficient proved reserves to implement our business strategy.

Production of reserves from reservoirs in the Gulf of Mexico generally declines more rapidly than production from reservoirs in many other producing regions of the world. This results in recovery of a relatively higher percentage of reserves from properties in the Gulf of Mexico during the initial years of production. As our reserves decline from production, we must incur significant capital expenditures to replace declining production. As a result, in order to increase our reserves, we must replace our reserves with newly-acquired properties.

We may not be able to identify or complete the acquisition of properties with sufficient proved undeveloped reserves to implement our business strategy. As we produce our existing reserves, we must identify, acquire and develop properties through new acquisitions or our level of production and cash flows will be adversely affected. The availability of properties for acquisition depends largely on the divesting practices of other oil and natural gas companies, commodity prices, general economic conditions and other factors that we cannot control or influence. A substantial decrease in the availability of proved oil and gas properties in our areas of operation, or a substantial increase in the cost to acquire these properties, would adversely affect our ability to replace our reserves.

If we are not able to generate sufficient funds from our operations and other financing sources, we may not be able to finance our planned development activity or acquisitions or service our debt.

We have historically needed and will continue to need substantial amounts of cash to fund our capital expenditure and working capital requirements. Our ongoing capital requirements consist primarily of funding acquisition, development and abandonment of oil and gas reserves and to meet our debt service obligations. Our capital expenditures for oil and gas properties were approximately $87.4 million, $83.8 million and $34.9 million for the years ended December 31, 2004, 2003 and 2002, respectively. Because we have experienced a negative working capital position in past years, we have depended on debt and equity financing to meet our working capital requirements that were not funded from operations.

For 2005, we plan to finance anticipated expenses, debt service and acquisition and development requirements with available cash, funds generated from cash provided by operating activities and net cash proceeds from the potential sale of assets, debt or equity.

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Low commodity prices, production problems, disappointing drilling results and other factors beyond our control could reduce our funds from operations and may restrict our ability to obtain additional financing. Furthermore, we have incurred losses in the past that may affect our ability to obtain financing. In addition, financing may not be available to us in the future on acceptable terms or at all. In the event additional capital is not available, we may curtail our acquisition, drilling, development and other activities or be forced to sell some of our assets on an untimely or unfavorable basis. In addition, we may not be able to pay interest and principal on our debt obligations.

Our debt instruments impose restrictions on us that may affect our ability to successfully operate our business.

In March 2004, we entered into a new term loan, which was subsequently amended in September 2004 (the “Term Loan”), consisting of a $185.0 million Senior Secured First Lien Term Loan Facility and a $35.0 million Senior Secured Second Lien Term Loan Facility. The Term Loan matures in March 2009 and 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. As of December 31, 2004, we had $218.4 million principal amount outstanding under the Term Loan. The Term Loan contains customary restrictions, including covenants limiting our ability to incur additional debt, grant liens, make investments, consolidate, merge or acquire other businesses, sell assets, pay dividends and other distributions and enter into transactions with affiliates. We also are required to maintain specified financial requirements under the terms of our Term Loan including the following, as defined in the Term Loan:

These restrictions may make it difficult for us to successfully execute our business strategy or to compete in our industry with companies not similarly restricted. While we were in compliance with all of the financial covenants in our Term Loan at December 31, 2004, during 2003 and in February 2004, we were required to obtain waivers for certain of our financial covenants in our prior credit facility. If we are unable to meet the requirements of our Term Loan or any new financial transaction that we may enter into, we may be required to seek waivers from our lenders and there is no assurance that such waivers would be granted.

We have debt, trade payables and related interest payment requirements that may restrict our future operations and impair our ability to meet our obligations.

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Our debt, trade payables and related interest payment requirements may have important consequences. For instance, it could:

Our ability to satisfy our obligations and to reduce our total debt depends on our future operating performance and on economic, financial, competitive and other factors, many of which are beyond our control. We cannot provide assurance that our business will generate sufficient cash flow or that future financings will be available to provide sufficient proceeds to meet these obligations. The successful execution of our business strategy and the maintenance of our economic viability are also contingent upon our ability to meet our financial obligations.

Oil and natural gas prices are volatile, and low prices have had in the past and could have in the future a material adverse impact on our business.

Our revenues, profitability and future growth and the carrying value of our properties depend substantially on the prices we realize for our oil and natural gas production. Because approximately 75% of our estimated proved reserves as of December 31, 2004 were natural gas reserves, our financial results are more sensitive to movements in natural gas prices. Our realized prices also affect the amount of cash flow available for capital expenditures and our ability to borrow and raise additional capital.

Historically, the markets for oil and natural gas have been volatile, and they are likely to continue to be volatile in the future. For example, oil and natural gas prices increased significantly in late 2000 and early 2001 and then steadily declined in 2001, only to climb again in recent years to near all time highs. Among the factors that can cause this volatility are:

It is impossible to predict oil and natural gas price movements with certainty. Lower oil and natural gas prices may not only decrease our revenues on a per unit basis but also may reduce the amount of oil and natural gas that we can produce economically. A substantial or extended decline in oil and natural gas prices may materially and adversely affect our future business, financial condition, results of operations, liquidity and ability to finance planned capital expenditures. Further, oil prices and natural gas prices do not necessarily move together.

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Our price risk management decisions may reduce our potential gains from increases in commodity prices and may result in losses.

We periodically utilize financial derivative instruments and fixed price forward sales contracts with respect to a portion of our expected production. These instruments expose us to risk of financial loss if:

Our results of operations may be negatively impacted by our financial derivative instruments and fixed price forward sales contracts in the future and these instruments may limit any benefit we would receive from increases in the prices for oil and natural gas. For the years ended December 31, 2004, 2003 and 2002, we realized a loss on settled financial derivatives of $1.2 million, $16.6 million and $3.4 million, respectively.

We may incur substantial impairment writedowns.

If management’s estimates of the recoverable reserves on a property are revised downward, if development costs exceed previous estimates or if oil and natural gas prices decline, we may be required to record additional non-cash impairment writedowns in the future, which would result in a negative impact to our financial position. We review our proved oil and gas properties for impairment on a depletable unit basis when circumstances suggest there is a need for such a review. To determine if a depletable unit is impaired, we compare the carrying value of the depletable unit to the undiscounted future net cash flows by applying management’s estimates of future oil and gas prices to the estimated future production of oil and gas reserves over the economic life of the property. Future net cash flows are based upon our independent reservoir engineers’ estimates of proved reserves. In addition, other factors such as probable and possible reserves are taken into consideration when justified by economic conditions. For each property determined to be impaired, we recognize an impairment loss equal to the difference between the estimated fair value and the carrying value of the property on a depletable unit basis. Fair value is estimated to be the present value of the aforementioned expected future net cash flows. Any impairment charge incurred is recorded in accumulated depreciation, depletion, impairment and amortization to reduce our recorded basis in the asset. Each part of this calculation is subject to a large degree of judgment, including the determination of the depletable units’ estimated reserves, future cash flows and fair value. We recorded no impairments in 2004 and impairments of $11.7 million and $6.8 million for the years ended December 31, 2003 and 2002, respectively.

Management’s assumptions used in calculating oil and gas reserves or regarding the future cash flows or fair value of our properties are subject to change in the future. Any change could cause impairment expense to be recorded, impacting our net income or loss and our basis in the related asset. Any change in reserves directly impacts our estimate of future cash flows from the property, as well as the property’s fair value. Additionally, as management’s views related to future prices change, the change will affect the estimate of future net cash flows and the fair value estimates. Changes in either of these amounts will directly impact the calculation of impairment.

The oil and natural gas business involves many uncertainties and operating risks that can prevent us from realizing profits and can cause substantial losses.

Our development activities may be unsuccessful for many reasons, including cost overruns, equipment shortages and mechanical difficulties. Moreover, the successful drilling of a natural gas or oil well does not ensure a profit on investment. A variety of factors, both geological and market-related, can cause a well to become uneconomical or only marginally economic. In addition to their cost, unsuccessful wells can hurt our efforts to replace reserves.

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The oil and natural gas business involves a variety of operating risks, including:

If we experience any of these problems, it could affect well bores, platforms, gathering systems and processing facilities, which could adversely affect our ability to conduct operations. We could also incur substantial losses in excess of our insurance coverage as a result of:

Offshore operations are also subject to a variety of operating risks peculiar to the marine environment, such as capsizing, collisions and damage or loss from hurricanes or other adverse weather conditions. These conditions can cause substantial damage to facilities and interrupt production. As a result, we could incur substantial liabilities that could reduce or eliminate the funds available for development or leasehold acquisitions, or result in loss of equipment and properties.

Terrorist attacks or similar hostilities may adversely impact our results of operations.

The terrorist attacks that took place in the United States on September 11, 2001 were unprecedented events that have created many economic and political uncertainties, some of which may materially adversely impact our business. Uncertainty surrounding military strikes or a sustained military campaign may affect our operations in unpredictable ways, including disruptions of fuel supplies and markets, particularly oil, and the possibility that infrastructure facilities, including pipelines, production facilities, processing plants and refineries, could be direct targets of, or indirect casualties of, an act of terror or war. The continuation of these developments may subject our operations to increased risks and, depending on their ultimate magnitude, could have a material adverse effect on our business, results of operations, financial condition and prospects.

Our insurance coverage may not be sufficient to cover some liabilities or losses that we may incur.

The occurrence of a significant accident or other event not fully covered by our insurance could have a material adverse effect on our operations and financial condition. Our insurance does not protect us against all operational risks. We do not carry business interruption insurance at levels that would provide enough funds for us to continue operating without access to other funds. For some risks, we may not obtain insurance if we believe the cost of available insurance is excessive relative to the risks presented. Because third party contractors and other service providers are used in our offshore operations, we may not realize the full benefit of workmen’s compensation laws in dealing with their employees. In addition, pollution and environmental risks generally are not fully insurable.

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We may be unable to identify liabilities associated with the properties that we acquire or obtain protection from sellers against them.

The acquisition of properties with proved undeveloped reserves requires us to assess a number of factors, including recoverable reserves, development and operating costs and potential environmental and other liabilities. Such assessments are inexact and inherently uncertain. In connection with the assessments, we perform a review of the subject properties, but such a review will not reveal all existing or potential problems. In the course of our due diligence, we may not inspect every well, platform or pipeline. We cannot necessarily observe structural and environmental problems, such as pipeline corrosion, when an inspection is made. We may not be able to obtain contractual indemnities from the seller for liabilities that it created. We may be required to assume the risk of the physical condition of the properties in addition to the risk that the properties may not perform in accordance with our expectations.

Competition in our industry is intense, and we are smaller and have a more limited operating history than some of our competitors in the Gulf of Mexico and in the North Sea.

We compete with major and independent oil and natural gas companies for property acquisitions. We also compete for the equipment and labor required to operate and to develop these properties. Some of our competitors have substantially greater financial and other resources than us. In addition, larger competitors may be able to absorb the burden of any changes in federal, state and local laws and regulations more easily than we can, which would adversely affect our competitive position. These competitors may be able to pay more for oil and natural gas properties and may be able to define, evaluate, bid for and acquire a greater number of properties than we can. Our ability to acquire additional properties and develop new and existing properties in the future will depend on our ability to conduct operations, to evaluate and select suitable properties and to consummate transactions in this highly competitive environment. In addition, some of our competitors have been operating in the Gulf of Mexico and in the North Sea for a much longer time than we have and have demonstrated the ability to operate through industry cycles.

We may suffer losses as a result of foreign currency fluctuations.

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. Any increase in the value of the U.S. dollar in relation to the value of the local currency will adversely affect our revenues from our foreign operations when translated into U.S. dollars. Similarly, any decrease in the value of the U.S. dollar in relation to the value of the local currency will increase our development costs in our foreign operations, to the extent such costs are payable in foreign currency, when translated into U.S. dollars. We have not utilized derivatives or other financial instruments to hedge the risk associated with the movement in foreign currencies.

Our success depends on our management team and other key personnel, the loss of any of whom could disrupt our business operations.

Our success will depend on our ability to retain and attract experienced geoscientists and other professional staff. As of December 31, 2004, we had 18 engineers, geologist/geophysicists and other technical personnel in our Houston office, three engineers, geologist/geophysicists and other technical personnel in our London location and one engineer in our Netherlands office. We depend to a large extent on the efforts, technical expertise and continued employment of these personnel and members of our management team. If a significant number of them resign or become unable to continue in their present role and if they are not adequately replaced, our business operations could be adversely affected.

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Rapid growth may place significant demands on our resources.

We have experienced rapid growth in our operations and expect that significant expansion of our operations will continue. Our rapid growth has placed, and our anticipated future growth will continue to place, a significant demand on our managerial, operational and financial resources due to:

If we have not made adequate allowances for the costs and risks associated with this expansion or if our systems, procedures or controls are not adequate to support our operations, our business could be adversely impacted.

We are subject to complex laws and regulations, including environmental regulations that can adversely affect the cost, manner or feasibility of doing business.

Development, production and sale of oil and natural gas in the U.S., especially in the Gulf of Mexico and in the North Sea, are subject to extensive laws and regulations, including environmental laws and regulations. We may be required to make large expenditures to comply with environmental and other governmental regulations. Matters subject to regulation include:

Under these laws and regulations, we could be liable for personal injuries, property damage, oil spills, discharge of hazardous materials, remediation and clean-up costs and other environmental damages. Failure to comply with these laws and regulations also may result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties. Moreover, these laws and regulations could change in ways that substantially increase our costs. Accordingly, any of these liabilities, penalties, suspensions, terminations or regulatory changes could materially adversely affect our financial condition and results of operations.

Members of our management team own a significant amount of common stock, giving them influence or control in corporate transactions and other matters, and the interests of these individuals could differ from those of other shareholders.

Members of our management team beneficially own approximately 37% of our outstanding shares of common stock. As a result, these shareholders are in a position to significantly influence or control the outcome of matters requiring a shareholder vote, including the election of directors, the adoption of an amendment to our articles of incorporation or bylaws and the approval of mergers and other significant corporate transactions. Their control of ATP may delay or prevent a change of control of ATP and may adversely affect the voting and other rights of other shareholders.

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Employees

At December 31, 2004 we had 43 full-time employees in our Houston office, five full-time employees in our London office and two full-time employees in our Netherlands office. None of our employees are covered by a collective bargaining agreement. We regularly use the services of independent consultants and contractors to perform various professional services, particularly in the areas of construction, design, well-site supervision, permitting and environmental assessment. Independent contractors usually perform field and on-site production operation services for us, including gauging, maintenance, dispatching, inspection and well testing.

Available Information

Our Internet website is http://www.atpog.com and you may access, free of charge, through the Investor Relations portion of our website our annual reports on Form 10-K, current reports on Form 8-K and amendments to such reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC. Information contained on our website is not part of this report.

General

We are engaged in the acquisition, development and production of oil and natural gas properties primarily in the Gulf of Mexico and the North Sea. At December 31, 2004, we had leasehold and other interests in 52 offshore blocks, 26 platforms and 68 wells, including five subsea wells, in the Gulf of Mexico. We operate 56 of these 68 wells, including all of the subsea wells, and 85% of our offshore platforms. We also held interests in ten blocks and one company-operated subsea well located in the North Sea. Our average working interest in our properties at December 31, 2004 was approximately 79%. As of December 31, 2004, we had leasehold interests located in the Gulf of Mexico and North Sea covering approximately 317,028 gross and 249,361 net acres.

Gulf of Mexico

During 2004, we successfully completed 13 wells in the Gulf of Mexico – four wells at Ship Shoal 358, three wells at West Cameron 237, two wells each at Eugene Island 30/71 and Matagorda Island 704/709 and one well each at West Cameron 101 and Garden Banks 186.

Also during 2004, we acquired interests in five other blocks for approximately $1.2 million. All of the blocks, three of which are contiguous to an existing producing lease, do not currently meet the definition of proved reserves; however; previous drilling on three of the blocks indicated that the reservoirs contained commercially productive quantities of oil and gas. The cost of these unproved properties is included in oil and gas properties at December 31, 2004.

In 2004, we sold 25% of our interest in seven projects containing ten offshore blocks in the Gulf of Mexico for $19.5 million and recognized a gain of $6.0 million. Developing projects to a value creation point and then selling or bringing in partners on a promoted basis during the high capital development phase is a technique we have used. We may use a similar approach in the future for other Gulf of Mexico and North Sea projects.

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North Sea

In January 2004, we completed a successful sidetrack of the Helvellyn well and on February 10, 2004, the well was placed on production. In February 2004, we were awarded Blocks 2/10b and 3/11b by the U.K. Department of Trade and Industry (“DTI”) and in an out-of-round award, we were awarded a third block, Block 2/15a. These three blocks comprise the Cheviot field, which contain several undeveloped oil and gas discoveries and additional upside potential. We received a 100% working interest and are the operator of the field.

Oil and Natural Gas Reserves

Our business strategy is to acquire proved reserves, usually proved undeveloped, and to bring those reserves on production as rapidly as possible. Occasionally we will acquire properties where previous drilling has encountered reservoirs that appear to contain commercially productive quantities of oil and gas even though the reservoirs do not meet the SEC definition of proved reserves.

The following table presents our estimated net proved oil and natural gas reserves at December 31, 2004 based on reserve reports prepared by Ryder Scott Company, L.P. for our Gulf of Mexico and Netherlands reserves and RSP Troy-Ikoda Limited for our U.K. reserves.

In 2004 our standardized measure of discounted future net cash flows was $520.3 million. The present value of future net cash flows attributable to estimated net proved reserves, discounted at 10% per annum, (“PV10”) is a computation of the standardized measure of discounted future net cash flows on a pre-tax basis. The table below provides a reconciliation of PV10 to the standardized measure of discounted future net cash flows at December 31, 2004. PV10 may be considered a non-GAAP financial measure as defined by the SEC’s Regulation G. We believe PV10 to be an important measure for evaluating the relative significance of our natural gas and oil properties. PV10 is computed on the same basis as the standardized measure of discounted future net cash flows but without deducting income taxes. We further believe investors and creditors may utilize our PV10 as a basis for comparison of the relative size and value of our reserves to other companies. However, PV10 is not a substitute for the standardized measure. Our PV10 measure and the standardized measure of discounted future net cash flows do not purport to present the fair value of our natural gas and oil reserves.

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The estimates of proved reserves in the table above do not differ from those we have filed with other federal agencies. The process of estimating natural gas and oil reserves is complex. It requires various assumptions, including assumptions relating to natural gas and oil prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. We must project production rates and timing of development expenditures. We analyze available geological, geophysical, production and engineering data, and the extent, quality and reliability of this data can vary. Recovery of undeveloped reserves generally requires significant capital expenditures and successful drilling and completion operations. The reserve data assumes that we will make these expenditures. Although the reserves and the costs associated with developing them are estimated in accordance with industry standards, the estimated costs may be inaccurate, development may not occur as scheduled and results may not be as estimated. Therefore, estimates of natural gas and oil reserves are inherently imprecise.

Drilling Activity

The following table shows our drilling and completion activity. In the table, “gross” refers to the total wells in which we have a working interest and “net” refers to gross wells multiplied by our working interest in such wells.

At December 31, 2004 we had one development well (0.75 net) and one exploratory well (0.75 net) that were in the process of being drilled.

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Productive Wells

The following table presents the number of productive oil and natural gas wells in which we owned an interest as of December 31, 2004:

Acreage

The following table summarizes our developed and undeveloped acreage holdings at December 31, 2004. Acreage in which ownership interest is limited to royalty, overriding royalty and other similar interests is excluded (in acres):

Production and Pricing Data

Information on production and pricing data is contained in Item 7. – “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations”.

During 2002 and 2003, ATP was in a dispute over a contract for the sale of an oil and gas property. The dispute was subsequently resolved for $8.2 million. We recorded a charge to income in the fourth quarter of 2003 and paid the amount in the first quarter of 2004. 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 from time to time. 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.

No matters were submitted to a vote of security holders during the fourth quarter of 2004.

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Executive Officers of the Company and Other Key Employees

Set forth below are the names, ages (as of March 25, 2005) and titles of the persons currently serving as executive officers of the Company. All executive officers hold office until their successors are elected and qualified.

T. Paul Bulmahn has served as our Chairman and President since he founded the company in 1991. From 1988 to 1991, Mr. Bulmahn served as President and Director of Harbert Oil & Gas Corporation. From 1984 to 1988, Mr. Bulmahn served as Vice President, General Counsel of Plumb Oil Company. From 1978 to 1984, Mr. Bulmahn served as counsel for Tenneco’s interstate gas pipelines and as regulatory counsel in Washington, D.C. From 1973 to 1978, he served the Railroad Commission of Texas, the Public Utility Commission and the Interstate Commerce Commission as an administrative law judge.

Gerald W. Schlief has served as our Senior Vice President since 1993 and is primarily responsible for acquisitions. Between 1990 and 1993, Mr. Schlief acted as a consultant for the onshore and offshore independent oil and gas industry. From 1984 to 1990, Mr. Schlief served as Vice President, Offshore Land for Plumb Oil Company, and its successor Harbert Energy Corporation, where he managed the acquisition of interests in over 35 offshore properties. From 1983 to 1984, Mr. Schlief served as Offshore Land Consultant for Huffco Petroleum Corporation. He served as Treasurer and Landman for Huthnance Energy Corporation from 1981 to 1983. In addition, from 1974 to 1978, Mr. Schlief conducted audits of oil and gas companies for Arthur Andersen & Co., and from 1978 to 1981, he conducted audits of oil and gas companies for Spicer & Oppenheim.

Albert L. Reese, Jr. has served as our Chief Financial Officer since March 1999 and, in a consulting capacity, as our director of finance from 1991 until March 1999. From 1986 to 1991, Mr. Reese was employed with the Harbert Corporation where he established a registered investment bank for the company to conduct project and corporate financings for energy, co-generation, and small power activities. From 1979 to 1986, Mr. Reese served as chief financial officer of Plumb Oil Company and its successor, Harbert Energy Corporation. Prior to 1979, Mr. Reese served in various capacities with Capital Bank in Houston, the independent accounting firm of Peat, Marwick & Mitchell, and as a partner in Arnold, Reese & Swenson, a Houston-based accounting firm specializing in energy clients.

Leland E. Tate has served as our Chief Operations Officer since August 2000. Prior to joining ATP, Mr. Tate worked for over 30 years with Atlantic Richfield Company (“ARCO”). From 1998 until July 2000, Mr. Tate served as the President of ARCO North Africa. He also was Director General of Joint Ventures at ARCO from 1996 to 1998. From 1994 to 1996, Mr. Tate served as ARCO’s Vice President Operations & Engineering, where he led technical negotiations in field development. Prior to 1994, Mr. Tate’s positions with ARCO included Director of Operations, ARCO British Ltd.; Vice President of Engineering, ARCO International; Senior Vice President Marketing and Operations, ARCO Indonesia; and for three years was Vice President and District Manager in Lafayette, Louisiana.

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John E. Tschirhart joined us in November 1997 and has served as our General Counsel since March 1998. Mr. Tschirhart was named Senior Vice President International in July 2001 and served as Managing Director of ATP Oil & Gas (UK) Limited from May 2000 to May 2001. He has served on the board of directors of ATP Oil & Gas (UK) Limited and ATP Oil & Gas (Netherlands) B.V. since the formation of those corporations and currently serves as the Managing Director of ATP Oil & Gas (Netherlands) B.V. From 1993 to November 1997, Mr. Tschirhart worked as a partner at the law firm of Tschirhart and Daines, a partnership in Houston, Texas. From 1985 to 1993 Mr. Tschirhart was in private practice handling civil litigation matters including oil and gas and employment law. From 1979 to 1985, he was with Coastal Oil & Gas Corporation and from 1974 to 1979 he was with Shell Oil Company.

Isabel M. Plume has served as our Chief Communications Officer since 2004 and Corporate Secretary since 2003. Ms. Plume currently serves on the board of directors of ATP Oil & Gas (UK) Limited. From 1996 to 1998, she was employed by Oasis Pipe Line Company, a midstream transporter of natural gas, responsible for implementing accounting and reporting systems. From 1982 to 1995 Ms. Plume served in a financial reporting capacity for Dow Hydrocarbons & Resources, Inc. and the Dow Chemical Company.

Keith R. Godwin has served as our Chief Accounting Officer since April 2004. He served as Controller and Vice President from August 2000 to March 2004 and Controller from 1997 to July 2000. From 1995 to 1997, Mr. Godwin was the Corporate Accounting Manager with Champion Healthcare Corporation. From 1990 to 1995, Mr. Godwin was employed as an accountant with Coopers & Lybrand L.L.P. where he conducted audits primarily in the energy industry.

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PART II

Our authorized capital stock consists of 100,000,000 shares of common stock, par value $0.001 per share, and 10,000,000 shares of preferred stock, par value $0.001 per share. There were 28,966,358 shares of common stock and no shares of preferred stock outstanding as of March 25, 2005. There were 101 holders of record of our common stock as of March 25, 2005. Our common stock is traded on the Nasdaq National Market under the ticker symbol ATPG.

The following table sets forth the range of high and low closing sales prices for the common stock as reported on the Nasdaq National Market for the periods indicated below:

We have never declared or paid any cash dividends on our common stock. We currently intend to retain future earnings and other cash resources, if any, for the operation and development of our business and do not anticipate paying any cash dividends on our common stock in the foreseeable future. Payment of any future dividends will be at the discretion of our board of directors after taking into account many factors, including our financial condition, operating results, current and anticipated cash needs and plans for expansion. In addition, our current term loan prohibits us from paying cash dividends on our common stock. Any future dividends may also be restricted by any loan agreements which we may enter into from time to time.

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(In thousands, except per share data)

The following data should be read in conjunction with “Item 7. – Management’s Discussion and Analysis of Financial Condition and Results of Operations”.

Table and footnotes continued on following page

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Executive Overview

General

ATP Oil & Gas Corporation is engaged in the acquisition, development and production of oil and natural gas 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. Occasionally we will acquire properties where previous drilling has encountered reservoirs that appear to us to contain commercially productive quantities of oil and gas even though the reservoirs do not meet the SEC definition of proved reserves. We believe that our strategy provides assets for us to develop and produce without the risk, cost or time of traditional exploration.

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

Our focus is on acquiring properties that have become non-core or non-strategic to their original owners for a variety of reasons. For example, larger oil companies from time to time adjust their capital spending or shift their focus to exploration prospects which they believe offer greater reserve potential. Some projects provide lower economic returns to a company due to its cost structure within that company. Also, due to timing or budget constraints, a company may be unwilling or unable to develop a property before the expiration of the lease. Because of our cost structure, expertise in our areas of focus and ability to develop projects, the properties may be more financially attractive to us than the seller. Given our strategy of acquiring properties that contain proved reserves, our operations typically are lower risk than exploration-focused Gulf of Mexico and North Sea operators. As a result of this strategy, we have successfully brought 37 out of 38 (97%) projects with proved undeveloped reserve to production since our inception.

We focus on developing projects in the shortest time possible between initial significant investment and first revenue generated in order to maximize our rate of return. Since we operate a significant number of the properties in which we acquire a working interest, we are able to significantly influence the development concept and timing of a project’s development. We typically initiate new development projects by simultaneously obtaining the various required components such as the pipeline and the production platform or subsea well completion equipment. We believe this strategy, combined with our strong technical abilities to evaluate and implement a project’s requirements, allows us to efficiently complete the development project and commence production.

To enhance the economics and return on investment of a project, we sometimes develop the project to a value creation point and either sell an interest or bring in partners on a promoted basis during the high capital development phase. In 2002, we sold a 50% interest in our Helvellyn project in the U.K. Sector – North Sea after we had obtained field development approval for the project and finalized contractual commitments. In 2003, we sold interests in three projects in the Gulf of Mexico on a promoted basis to reduce the amount of capital employed. We continued this practice into 2004 whereupon we sold 25% of our interest in seven projects containing ten offshore blocks in the Gulf of Mexico for $19.5 million, approximately $1.85/Mcfe for proved reserves, of which 93.5% were proved undeveloped reserves.

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Review of 2004

The year 2004 was a year of major financial improvement and development success for ATP. We completed three financing transactions, two debt and one equity, improved working capital by $114.8 million and ended 2004 with $102.8 million of cash and cash equivalents. These financing transactions and cash from operating activities provided us the liquidity to enjoy our most active development year since becoming a publicly traded company in February 2001.

The three financing transactions for ATP in 2004 were instrumental in providing the funds needed to complete our 2004 developments and provide us the initial financial resources for our 2005 program. In March 2004, we replaced our previous $110.0 million revolving credit facility with a new $185.0 million term loan comprised of a first lien of $150.0 million and a second lien of $35 million. The new five year term loan improved our liquidity position by $56.0 million and allowed us to aggressively begin our 2004 development program. In September 2004 we amended the term loan by adding $35.0 million to the first lien, reducing the interest rate on the first lien by 325 basis points and amending certain covenants of the facility to provide us more flexibility. As a result of putting in place a term facility and its subsequent amendment, interest expense increased to $22.3 million for 2004, compared to $9.7 million for 2003. After repurchasing 79% of outstanding warrants that were issued in conjunction with the March 2004 transaction, the amendment provided us with an additional $18.0 million of liquidity. By December 1, 2004, our share price had risen from $6.28 at the beginning of the year to approximately $14.00 per share, an increase of over 120%. As a result, we elected to issue four million shares of common stock for net proceeds of $53.1 million. The financing transactions net of costs and repayments of previously outstanding amounts provided us with approximately $123.0 million of liquidity and collectively were the catalysts in achieving such a productive year.

In the first quarter of 2004, we completed and placed on production Helvellyn, our first well in the North Sea. We initially drilled this well in late 2002, encountered delays beyond our control during early and mid 2003, and ultimately made the decision to side-track the well to achieve first production in February 2004. Total development costs related to Helvellyn in 2004 were $3.0 million and other North Sea properties accounted for $5.8 million. The impact of Helvellyn was a contributing factor to our 31% increase in production, the largest annual increase in production as a publicly traded company.

In the Gulf of Mexico we completed 13 wells at six different properties. At Garden Banks 186, adjacent to our Garden Banks 142 property and the host platform for Garden Banks 186, we placed on production one well. Development at these properties, together known as Matia/Cabrito, began in 2003 when the platform was installed and the well at Garden Banks 142 was placed on production. At Ship Shoal 358, four wells were drilled and placed on production during 2004. Like Matia/Cabrito, the platform was installed during 2003 and drilling was completed in 2004. Noteworthy with both the Ship Shoal 358 and the Matia/Cabrito developments was the reuse of platforms from other ATP locations. The significance was not that platforms were reused, which often happens in the Gulf of Mexico, but that the platforms were moved to deeper water depths than originally located. This required us to install plinths, or leg extensions, to accomplish the installations. In December 2004, ATP was awarded the Offshore Energy Achievement Award for Innovation/Technology for its innovative use of plinths. The Innovation/Technology award honors a new technology that has been field-proven or an innovative application of existing technology that resulted in a material improvement in safety, throughput or cost savings.

During 2004 the Company also completed three wells at West Cameron 237, two wells at Matagorda Island 704/709, one well at West Cameron 101 and two wells at Eugene Island 30/71. In the fourth quarter 2004, we tested a well at Mississippi Canyon 711, presently our largest property in terms of proved reserves. The Mississippi Canyon 711 #4 ST1 well which logged approximately 157 total net feet of oil and gas pay in Lower Pliocene sands tested at a rate of 13,610 BOPD and 52.7 MMcf/d or 134 MMcfe/d. The multiple day flow test recorded flowing tubing pressures exceeding 3500 psi. Additional development is scheduled at Mississippi Canyon 711 during 2005 with first production currently scheduled for early in the fourth quarter 2005. Total development and exploratory costs incurred in 2004 in the Gulf of Mexico was $77.3 million.

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At the end of 2004, we were drilling two wells, one at West Cameron 432 and the other at High Island 74. The well at West Cameron 432 began production on January 31, 2005. The well at High Island 74 which was one of our properties not included in our reserve report as it did not meet the SEC definition of proved reserves is scheduled to begin production during the second quarter 2005.

As a result of the production from Helvellyn, a natural gas well, our natural gas component of production increased to 80% in 2004 from 63% in 2003. We also increased our average realized price in 2004 as a result of higher oil and natural gas prices and higher prices for those quantities we hedged. For 2004, we realized an average price including the effect of cash flow hedges for natural gas of $5.05 per Mcf, an increase of 48% over 2003, and $33.93 per barrel of oil, an increase of 25% over 2003.

At December 31, 2004, we had proved reserves of 275.2 Bcfe, of which 66% are located in the Gulf of Mexico and the remaining 34% in the North Sea. The pre-tax PV-10 of our proved reserves at December 31, 2004 was $732.8 million. See “Item 2. Properties – Oil and Natural Gas Reserves” for a reconciliation to after- tax PV-10. We currently have 18 properties that have proved undeveloped reserves totaling 214.8 Bcfe scheduled for future development including 15 properties in the Gulf of Mexico, two in the U.K. Sector – North Sea and one in the Dutch Sector – North Sea. In addition, we have scheduled for drilling or completion, properties where previous drilling into the targeted reservoirs indicates to the Company the presence of commercially productive quantities of hydrocarbons even though the reservoirs do not meet the SEC definition of proved reserves. Five blocks acquired in 2004 in the Gulf of Mexico and Cheviot in the North Sea, potentially the largest property in the Company’s portfolio, are not included in the reserve report as they did not meet the SEC definition of proved reserves at the end of 2004. Upon completion of plans which may include drilling, completion or testing of wells for these and similar properties in the Company’s portfolio, the Company anticipates that it may be able to record proved reserves associated with several of these properties.

In 2004, we sold an undivided 25% interest in seven properties on ten blocks in the Gulf of Mexico. This sale accounted for a reduction in our proved reserves of 10.6 Bcfe of which 93.5% were classified as proved undeveloped at the time of the sale. We received $19.5 million for this sale or approximately $1.85 per Mcfe and recognized a gain of $6.0 million from the transaction. After adjusting for production and the sale of the interest in the seven properties, ATP recorded net upward revisions and extensions in proved reserves during 2004 of 5.5 Bcfe.

2005 Operational and Financial Objectives

We believe that 2005 production will exceed that of 2004 as a result of our 2003 and 2004 development programs and projects scheduled for development in 2005. Development activities scheduled at Mississippi Canyon 711 during 2005 include laying approximately 27 miles of oil and gas pipelines, converting a semi-submersible drilling rig to a floating production facility, completing a second well which was previously drilled in the Southern portion of the block and connecting for production both wells. First production is currently scheduled for early in the fourth quarter 2005. In addition to Mississippi Canyon 711, developments with proved undeveloped reserves at December 31, 2004 planned in 2005 include Block L-06d in the Dutch sector of the North Sea and additional properties in the Gulf of Mexico. We also have scheduled for drilling or completion properties in which previous drilling into targeted reservoirs indicates to the Company the presence of commercially productive quantities of hydrocarbons, although these reservoirs did not meet the SEC definition of proved reserves at the end of 2004. Other potential developments for 2005 in the Gulf of Mexico and North Sea are currently being evaluated.

ATP plans to devote considerable attention in 2005 to evaluating the potential of its Cheviot property in the North Sea. This property produced from 1992 – 1996 before it was taken off production by the previous owner. We completed a 3-D seismic survey in the fourth quarter of 2004 which is currently being processed and interpreted. Once this work is completed, we will continue our evaluation utilizing not only the 3-D seismic, but also previous drilling and production information. We expect to complete a plan for the Cheviot property during 2005 with the goal of recording proved undeveloped reserves by the end of 2005. Additional locations within the Cheviot property but outside of the reservoirs that previously produced are also being evaluated for possible drilling, development or exploration.

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Our production may command higher realized oil and gas prices in 2005 than in recent years, based on our current hedge position and strong commodity prices. Our revenues, profitability and cash flows are highly dependent upon many factors, particularly our production results and the price of oil and natural gas. During the first quarter of 2005 we have been active in the futures market. We have hedged volumes for 2005-2006 of 6.0 Bcf of natural gas between $6.42 and $10.79 per MMBtu and 356 thousand barrels of crude oil between $45.35 and $51.05 per barrel. Including these recent hedges, we have hedged 12.4 Bcfe of our 2005 production at an average price of $6.34/MMBtue and 3.7 Bcfe of our 2006 production at an average price of $7.84/MMBtue. To mitigate future price volatility, we may hedge additional production, especially if commodity prices continue to rise.

In 2003, we recorded an income tax expense of $21.2 million primarily due to us recording a valuation allowance of $33.6 million against our deferred tax asset as required by SFAS No. 109 “Accounting for Income Taxes” (“SFAS 109”). See Note 10 “Income Taxes” to the Consolidated Financial Statements. SFAS 109 provides for the weighing of positive and negative evidence in determining whether a deferred tax asset is recoverable. While we recorded net income in 2004, we have incurred net operating losses in 2003 and prior consecutive years. Relevant accounting guidance suggests that cumulative losses in recent years constitute significant negative evidence, and that future expectations about income are overshadowed by such history of losses. Delays in bringing properties on to production and development cost overruns in 2003 were also significant factors considered in evaluating our deferred tax asset valuation allowance. If we achieve profitable operations in 2005, we expect to reverse a portion of the valuation allowance in an amount at least sufficient to eliminate any tax provision in that period and may also reverse a portion or all of the remaining valuation allowance if we determine that it is more likely than not that we will utilize the remaining deferred tax asset.

Results of Operations

For the year ended December 31, 2004, we recorded net income of $1.4 million or $0.05 per share and for the years ended December 31, 2003 and 2002, we reported net losses $50.8 million or $2.21 per share and $4.7 million or $0.23 per share, respectively.

Oil and Gas Revenues

Revenues presented in the table and the 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 47%, 26% and 8% of our oil production was sold under these contracts for the years ended December 31, 2004, 2003 and 2002, respectively. Approximately 46%, 45% and 14% 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.

Table and footnote on following page

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