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SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-K

For the Fiscal Year Ended December 31, 2003

Commission file number: 000-32261

OR

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 ¨ No þ

The aggregate market value of the voting and non-voting common stock held by non-affiliates of the Registrant as of June 30, 2003 (the last business day of the Registrant’s most recently completed second fiscal quarter) was approximately $68,762,875. The number of shares of the Registrant’s common stock outstanding as of March 19, 2004 was 24,523,356.

DOCUMENTS INCORPORATED BY REFERENCE: The information required in Part III of the Annual Report on Form 10-K is incorporated by reference to the Registrant’s definitive proxy statement to be filed pursuant to Regulation 14A for the Registrant’s Annual Meeting of Stockholders.

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ATP OIL & GAS CORPORATION AND SUBSIDIARIES

2003 FORM 10-K ANNUAL REPORT

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Cautionary Statement About Forward-Looking Statements

As used in this 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 on Form 10-K 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 natural gas or oil reserves that is not a development well.

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.

Net feet of natural gas and condensate is the true vertical thickness of reservoir rock estimated to both contain hydrocarbons and be capable of contributing to producing rates.

PV-10 is the estimated future net revenue to be generated from the production of proved reserves discounted to present value using an annual discount rate of 10%. These amounts are calculated net of estimated production costs and future development and abandonment costs, using prices and costs in effect as of a certain date, without escalation and without giving effect to non-production related expenses, such as general and administrative expenses, debt service, future income tax expense, or depreciation, depletion, and amortization.

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 completion.

Reserve life index is a measure of the productive life of a natural gas and oil property or a group of natural gas and oil properties, expressed in years. Reserve life equals the estimated net proved reserves attributable to property or group of properties divided by production from the property or group of properties for the four fiscal quarters preceding the date as of which the proved reserves were estimated.

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 natural gas and oil properties in the Gulf of Mexico and the North Sea. We primarily focus our efforts on natural gas and oil properties with proved undeveloped reserves that are economically attractive to us but are not strategic to major or exploration-oriented independent oil and gas companies. Our strategy provides assets for us to develop and produce without the risk, cost or time of exploration. 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.

We increase our reserves and production primarily through acquisitions and the subsequent development of proved reserves. During 2003 we added proved reserves of approximately 103.5 Bcfe, of which 97.2 Bcfe were through acquisitions in the Gulf of Mexico and 6.3 Bcfe were through acquisitions in the Dutch Sector – North Sea.

At December 31, 2003, we had estimated net proved reserves of 302.7 Bcfe, of which approximately 201.7 Bcfe (67%) was in the Gulf of Mexico and 101.0 Bcfe (33%) was in the North Sea. Year-end reserves were comprised of 231.1 Bcf of natural gas and 11.9 MMBbls of oil. All of our oil reserves are located in the Gulf of Mexico and approximately 56% 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 reserves at December 31, 2003 was $776.0 million. See Supplemental Information On Oil and Gas Producing Activities under Item 15 of this Form 10-K.

At December 31, 2003, we had leasehold and other interests in 50 offshore blocks, 26 platforms and 62 wells, including six subsea wells, in the Gulf of Mexico. We operate 50 of these 62 wells, including all of the subsea wells, and 85% of our offshore platforms. We also had interests in seven blocks and one company-operated subsea well in the U.K. Sector – North Sea. Our average working interest in our properties at December 31, 2003 was approximately 82%. For more information regarding our operations and assets in the Gulf of Mexico and North Sea, see Note 15, “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 proved natural gas and oil reserves in areas that have:

We believe our strategy significantly reduces the risks associated with traditional natural gas and oil exploration. Our focus is to acquire properties that have been explored by others and found to contain proved reserves. From the inception of operations through March 30, 2004, we have successfully brought to production 35 out of 36 projects with proved undeveloped reserves on properties that were not producing, 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, 2003, we have added 483.1 Bcfe of proved natural gas and oil reserves through acquisitions at a total cost of $77.5 million or $0.16 per Mcfe. Development costs for this same period were approximately $366.5 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 natural gas and oil production under price sensitive or market price contracts. Our revenues, profitability and future growth depend substantially on prevailing prices for natural gas and oil. The price received by us for our natural gas and oil production can fluctuate widely. Changes in the prices of natural gas and oil 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 natural gas and oil to end users through various non-affiliated gas marketing companies. Historically, we have sold our natural gas and oil 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 natural gas and oil markets and because natural gas and oil 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 natural gas and oil 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.

Royalty Relief

In November 2001, we received notification from the U.S. Minerals Management Service (“MMS”) that our application for deepwater royalty relief for the Garden Banks 409 property had been approved under a federal law that was enacted in November 1995. The royalty relief provides for the abatement of federal royalty on the first 52.5 MMBoe of oil and gas production from the property. The royalty abatement continues in effect for each calendar year, unless realized prices exceed certain prescribed thresholds. If the prescribed threshold prices are exceeded by actual prices for a calendar year, then royalty relief is suspended and we would be required to pay royalties for that calendar year. For 2003, the price threshold for natural gas was exceeded and royalty relief was suspended. Royalties for 2003 will be paid to the MMS in March 2004.

Garden Banks 186 and Garden Banks 187 are leases that are also eligible for royalty relief. Upon commencement of production, we will submit a notice of that event to the MMS at which time they will respond with a confirmation of the relief volume. As per MMS regulations, the smallest that volume can be is 17.5 MMBOE. First production commenced during the latter part of March 2004.

Regulation

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. Beginning in April 1992, the FERC issued Order No. 636 and a series of related orders, which required interstate pipelines to provide open-access transportation on a not unduly discriminatory basis for all natural gas shippers. Although the regulations instituted by Order No. 636 do not directly apply to our production and marketing activities, they do affect how buyers and sellers gain access to the necessary transportation facilities and how we and our competitors sell natural gas in the marketplace. The FERC continues to modify its regulations regarding the

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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 on these or related matters, 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 FERC retains authority under the Outer Continental Shelf Lands Act to exercise jurisdiction over gatherers and other entities outside the reach of its Natural Gas Act jurisdiction if necessary to insure non-discriminatory access to service on the Outer Continental Shelf. 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.

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

Federal Leases. A substantial portion of our operations is located on federal natural gas and oil 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 August 20, 2003, the MMS issued a proposed rule that would change certain components of its valuation procedures for the calculation of royalties owed for crude oil sales. The proposed 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. Final comments on the proposed rule were due on November 10, 2003. We cannot predict whether this proposed rule will take effect as written, nor

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can we predict whether the proposed rule, if it takes effect, will be challenged in federal court and whether it will withstand such a challenge. We believe this rule, as proposed, 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, minus one percent. 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 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, in July 2000, the FERC issued a Notice of Inquiry seeking comment on whether to retain or to change the existing oil rate-indexing method. In December 2000, the FERC issued an order concluding that the rate index reasonably estimated the actual cost changes in the pipeline industry and should be continued for another 5-year period, subject to review in July 2005. In February 2003, on remand of its December 2000 order from the D.C. Circuit, the FERC changed the rate indexing methodology to the Producer Price Index for Finished Goods, but without the subtraction of 1% as had been done previously. The FERC made the change prospective only, but did allow oil pipelines to recalculate their maximum ceiling rates as though the new rate indexing methodology had been in effect since July 1, 2001. A challenge to FERC’s remand order is currently pending before the D.C. Circuit.

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 numerous laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. Public interest in the protection of the environment has increased dramatically in recent years. Offshore drilling in some areas has been opposed by environmental groups and, in some areas, has been restricted. To the extent laws are enacted or other governmental action is taken that prohibits or restricts offshore drilling or imposes

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environmental protection requirements that result in increased costs to the natural gas and oil industry in general and the offshore drilling industry in particular, our business and prospects could be adversely affected.

The Oil Pollution Act of 1990 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 Oil Pollution Act of 1990 assigns liability to each responsible party for oil removal costs and a variety of public and private damages. While liability limits apply in some circumstances, a party cannot take advantage of liability limits if the spill was caused by gross negligence or willful misconduct or resulted from violation of a federal safety, construction or operating regulation. If the party fails to report a spill or to cooperate fully in the cleanup, liability limits likewise do not apply. Even if applicable, the liability limits for offshore facilities require the responsible party to pay all removal costs, plus up to $75.0 million in other damages. Few defenses exist to the liability imposed by the Oil Pollution Act of 1990.

The Oil Pollution Act of 1990 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. As amended by the Coast Guard Authorization Act of 1996, the Oil Pollution Act of 1990 requires parties responsible for offshore facilities to provide financial assurance in the amount of $35.0 million to cover potential Oil Pollution Act of 1990 liabilities. This amount can be increased up to $150.0 million if a study by the MMS indicates that an amount higher than $35.0 million should be required. On August 11, 1998, the MMS adopted a rule implementing the Oil Pollution Act of 1990 financial responsibility requirements. We are in compliance with this rule.

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 Oil Pollution Act of 1990 also imposes other requirements, such as the preparation of an oil spill contingency plan. We have such a plan in place. We are also regulated by the Clean Water Act, which prohibits any discharge 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 inadequate cooperation during a spill event may subject a responsible party to civil or criminal enforcement actions.

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 some 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. Persons who are or were responsible for releases of hazardous substances under CERCLA 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 could be subject to liability under CERCLA because our drilling and production activities generate relatively small amounts of liquid and solid wastes that may be subject to classification as hazardous substances under CERCLA. These wastes must be brought to shore for proper

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disposal under the Resource Conservation and Recovery Act. We minimize this potential liability by selecting reputable contractors to dispose of our wastes at government-approved landfills or other types of disposal facilities.

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 instate coastal waters. 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.

In addition, legislation has been proposed in Congress from time to time that would reclassify some natural gas and oil exploration and production wastes as “hazardous wastes,” which would make the reclassified wastes subject to much more stringent handling, disposal and clean-up requirements. If Congress were to enact this legislation, it could increase our operating costs, as well as those of the natural gas and oil industry in general. Initiatives to further regulate the disposal of natural gas and oil wastes are also pending in some states, and these various initiatives could have a similar impact on us.

Our management believes that we are in substantial compliance with current applicable environmental laws and regulations and that continued compliance with existing requirements will not have a material adverse impact on us.

U.K. 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.

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.

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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.

Our management believes that we are in substantial compliance with current applicable environmental laws and regulations and that continued compliance with existing requirements will not have a material adverse impact on us.

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.

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.

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.

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

Our current term loan, established in March 2004, 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 meet specified financial ratios under the terms of our term loan. 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 required to seek waivers under our new term loan, there is no assurance that such waivers will be obtained. 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.

Our offshore properties are subject to rapid production declines and we require significant capital expenditures 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. Also, our return on capital for a particular property depends significantly on prices prevailing during the production period of that property.

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 natural gas and oil 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.

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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 drilling costs that are greater than estimated in our reserve reports. Such differences may be material.

Estimates of our natural gas and oil 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 natural gas and oil reserves and the estimated future net revenues from such reserves are based upon various assumptions, including assumptions required by the SEC relating to natural gas and oil 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. For example, we incurred higher than estimated costs in the development of our Helvellyn property in the North Sea as a result of unforeseen delays and development complications.

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 natural gas and oil 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 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.

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.

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 were approximately $83.8 million during 2003, $34.9 million during 2002 and $110.3 million during 2001. 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.

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For 2004, we plan to finance anticipated expenses, debt service and acquisition and development requirements with funds generated from the following sources:

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.

Natural gas and oil 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 natural gas and oil production. Because approximately 76% of our estimated proved reserves as of December 31, 2003 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 natural gas and oil have been volatile, and they are likely to continue to be volatile in the future. For example, natural gas and oil prices increased significantly in late 2000 and early 2001 and steadily declined in 2001, only to climb again in 2002 and 2003. Among the factors that can cause this volatility are:

It is impossible to predict natural gas and oil price movements with certainty. Lower natural gas and oil prices may not only decrease our revenues on a per unit basis but also may reduce the amount of natural gas and oil that we can produce economically. A substantial or extended decline in natural gas and oil 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.

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

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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 natural gas and oil. For the years ended December 31, 2003, 2002 and 2001, we realized a loss on settled financial derivatives of $16.6 million, $3.4 million and $19.7 million, respectively. See Note 13 to the Consolidated Financial Statements for volume and price information on our price risk management activities.

We may incur substantial impairment writedowns.

If management’s estimates of the recoverable reserves on a property are revised downward or if natural gas and oil 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 impairments of $11.7 million, $6.8 million and $24.9 million for the years ended December 31, 2003, 2002 and 2001, 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 natural gas and oil 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 natural gas and oil 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 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 impact that future terrorist attacks or regional hostilities (particularly in the Middle East) may have on the energy industry in general, and on us in particular, is not known at the time. 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. Moreover, we have incurred additional costs since the terrorist attacks of September 11, 2001 to safeguard certain of our assets and we may be required to incur significant additional costs in the future.

The terrorist attacks on September 11, 2001 and the changes in the insurance markets attributable to such attacks have made certain types of insurance more difficult for us to obtain. There can be no assurance that insurance will be available to us without significant additional costs. A lower level of economic activity could also result in a decline in energy consumption which could adversely affect our revenues or restrict our future growth. Instability in the financial markets as a result of terrorism or war could also affect our ability to raise capital.

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Our insurance coverage may not be sufficient to cover some liabilities or losses which 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 drilling contractors are used to drill our wells, 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.

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.

The unavailability or high 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, 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 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.

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 natural gas and oil 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 natural gas and oil 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.

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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, 2003, we had 12 engineers, geologist/geophysicists and other technical personnel in our Houston office and four engineers, geologist/geophysicists and other technical personnel in our London location. 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.

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 natural gas and oil 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.

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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 51% 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.

Employees

At December 31, 2003 we had 41 full-time employees in our Houston office, seven full-time employees in our London office and one full-time employee in our Netherlands office. None of our employees are covered by a collective bargaining agreement. From time to time, we 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 natural gas and oil properties primarily in the Gulf of Mexico and the North Sea. At December 31, 2003, we had leasehold and other interests in 50 offshore blocks, 26 platforms and 62 wells, including six subsea wells, in the Gulf of Mexico. We operate 50 of these 62 wells, including all of the subsea wells, and 85% of our offshore platforms. We also held interests in eight blocks and one company-operated subsea well located in the North Sea. Our average working interest in our properties at December 31, 2003 was approximately 82%. As of December 31, 2003, we had leasehold interests located in the Gulf of Mexico and North Sea covering approximately 264,592 gross and 209,424 net acres.

Gulf of Mexico

During 2003, we brought to production a total of five wells in the Gulf of Mexico – two wells at West Cameron 284, and one well each at Eugene Island 30/71, West Cameron 101 and Garden Banks 142. At the end of 2003, we were drilling the first of two wells at Ship Shoal 358 and our Garden Banks 186 well. The first well at Ship Shoal 358 and Garden Banks 186 were placed on production in March 2004.

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In 2003, we acquired Mississippi Canyon 711, which is our largest acquisition to date based on third party engineers’ estimates of proved reserves and expected future development costs. In consideration for this acquisition, we granted to the seller an overriding royalty interest after a certain amount of production is achieved. In addition, we shall assume all of the abandonment liability for each temporarily abandoned well for which we conduct well operations. Upon reaching a certain amount of production from the lease, we shall assume all of the abandonment liability for any remaining temporarily abandoned wells.

Also during 2003, we acquired interests in six other blocks for approximately $1.3 million. At December 31, 2003, two of these blocks had estimated proved reserves based on third party engineer estimates. Four of the blocks are currently being evaluated for recoverable reserves, three of which are contiguous to an existing producing lease. The cost of these unproved properties ($0.8 million) is included in oil and gas properties at December 31, 2003. In addition, we increased our ownership interest in two other offshore blocks for approximately $0.6 million.

In 2003, we sold interests in three projects on a promoted basis to reduce the amount of capital employed. In 2004, we sold 25% of our interest in seven projects containing ten offshore blocks in the Gulf of Mexico for $19.5 million. We have used this technique of developing projects to a value creation point and then selling or bringing in partners during the high capital development phase on a promoted basis. We could use a similar approach in the Mississippi Canyon project and some North Sea projects.

North Sea

We successfully tested the Helvellyn well in January 2003. During the second half of 2003, required modifications on the host platform were substantially completed by the host platform operator, however we encountered further delays in our efforts to commence production. During investigative procedures we learned that the well had incurred a down-hole problem, which required us to sidetrack the original well. In January 2004, we completed a successful sidetrack of the well and on February 10, 2004, the well was placed on production at approximately 30 MMcf/day (net).

In July 2003, we were offered two licenses by the U.K. Department of Trade and Industry (“DTI”) for Blocks 2/10b and 3/11b. In February 2004, we were awarded these two blocks and in an out-of-round award, we were awarded a third block, Block 2/15a. These three blocks comprise the Emerald field, which contains several undeveloped oil and gas discoveries and additional upside potential. We received a 100% working interest and are the operator of the field.

In February 2003, we acquired a 50% working interest in a block located in the Dutch Sector - North Sea. The remaining 50% interest is owned by a Dutch company who participates on behalf of the Dutch state. In April 2003, we received $8.1 million from the Dutch company related to development costs on this block. We agreed to develop the property within 60 months from receipt of the funds or return the funds with interest if commercial production is not achieved at the expiration of such time. At December 31, 2003, this obligation is reflected as a long-term liability in the financial statements.

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Natural Gas and Oil Reserves

The following table presents our estimated net proved natural gas and oil reserves and the net present value of our reserves at December 31, 2003 based on reserve reports prepared by Ryder Scott Company, L.P. for our Gulf of Mexico and Netherlands reserves and Troy-Ikoda Limited for our U.K. reserves.

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. Therefore, estimates of natural gas and oil reserves are inherently imprecise.

Our business strategy is to acquire proved reserves, usually proved undeveloped, and to bring those reserves on production as rapidly as possible. At December 31, 2003, approximately 80% of our estimated equivalent net proved reserves in the Gulf of Mexico and 84% of our estimated equivalent net proved reserves in North Sea were undeveloped. 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.

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. We did not drill or complete any exploratory wells in any period presented.

At December 31, 2003 we had 2 development wells (1.3 net) that were in the process of being drilled.

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Productive Wells

The following table presents the number of productive natural gas and oil wells in which we owned an interest as of December 31, 2003.

Acreage

The following table summarizes our developed and undeveloped acreage holdings at December 31, 2003. 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”.

ATP and Legacy Resources Co., LLP and agent (“Legacy”) were in a dispute over a contract for the sale of an oil and gas property. ATP paid $3.0 million to Legacy on October 9, 2001 to extend the closing date on a proposed acquisition of a property by ATP to October 31, 2001. The amended purchase agreement contained an arrangement whereby if ATP did not close on the property, and if Legacy sold the property to a third party with a sale that met specific contract requirements, ATP would be required to execute a six month note for the payment of the differential.

While working on the closing of the property with ATP after October 31, 2001, Legacy sold the property to a third party without informing ATP until after the closing. ATP filed a lawsuit alleging improper sale and seeking the return of its $3.0 million earlier payment. Legacy filed suit seeking $12.3 million plus interest at 16%. The matter was referred to arbitration and in the May 2003 arbitration proceedings Legacy sought a total claim of over $17.0 million through the end of 2003. On December 19, 2003, ATP was notified by the arbitration panel of its decision to award $8.2 million to Legacy. Interest on that amount accrues from the date of the award by the panel until the date of payment. At December 31, 2003, this amount is reflected as a short term obligation in the financial statements. ATP paid Legacy an initial payment of $1.0 million on March 29, 2004. Legacy and ATP have agreed that the balance of the award will be paid on or before April 16, 2004.

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In August 2001, Burlington Resources Inc. filed suit for $1.1 million in damages against ATP alleging formation of a contract with ATP and the breach of the alleged contract. On December 23, 2003, the lawsuit and another matter were settled for an inconsequential amount and Burlington Resources signed a dismissal of the lawsuit which precluded its re-filing.

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 2003.

Executive Officers of the Company

Set forth below are the names, ages (as of March 19, 2004) 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 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. He was also named Senior Vice President in August 2000. 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.

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Leland E. Tate has served as our Senior Vice President, Operations, 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.

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.

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 24,523,356 shares of common stock and no shares of preferred stock outstanding as of March 19, 2004. There were 67 holders of record of our common stock as of March 19, 2004. 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 credit facility 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 selected historical financial information was derived from, and is qualified by reference to our consolidated financial statements, including the notes thereto, appearing elsewhere in this report. 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 natural gas and oil properties in the Gulf of Mexico and the North Sea. We seek to acquire and develop properties with proved undeveloped reserves (“PUD”) that are economically attractive to us but are not strategic to major or large exploration-oriented independent oil and gas companies. We believe that our strategy provides assets for us to develop and produce without the risk, cost or time of exploration.

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

We focus on acquiring properties that contain proved undeveloped reserves 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 larger 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 efficient 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 are lower risk than exploration-focused Gulf of Mexico and North Sea operators. As a result of this strategy, we have successfully brought 35 out of 36 (97%) proved undeveloped reserve projects to commercial production since our inception.

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, 2003, we have added 483.1 Bcfe of proved natural gas and oil reserves through acquisitions at a total cost of $77.5 million or $0.18 per Mcfe. Development costs for this same period were approximately $366.5 million.

At December 31, 2003, we had net proved reserves of 302.7 Bcfe, of which 67% are located in the Gulf of Mexico and the remaining 33% in the North Sea. The pre-tax PV-10 of our proved reserves at December 31, 2003 was $776.0 million. Of the total proved reserves, approximately 247.0 Bcfe are proved undeveloped reserves, which represent more than three years of future development opportunities based on current expectations. We currently have nineteen properties that have proved undeveloped reserves scheduled for future development, including sixteen in the Gulf of Mexico, two in the U.K. Sector – North Sea and one in the Dutch Sector – North Sea.

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 ability to evaluate and implement a project’s requirements, allows us to efficiently complete the development project and commence production.

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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 during the high capital development phase on a promoted basis. 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% are proved undeveloped reserves.

Review of 2003

2003 was a transitional year for ATP. Most of our development activities during the year were focused on positioning us for success in the future. A considerable amount of our capital expenditures during the year will result in significantly enhanced production in 2004 and beyond. We began activities at our Matia/Cabrito and Ship Shoal 358 (“SS358”) developments in the first quarter of 2003, with significant expenditures beginning late in the second quarter through the end of the year. There are two initial wells at each of the two developments. The well at Matia had been completed and was producing at year end. Another significant portion of our capital outlay was devoted to our first North Sea development, Helvellyn, originally scheduled to be placed on production during the spring of 2003 after a successful well test in January 2003 of 30 MMcf/day (net). However, due to delays that were beyond our control, expected first production was pushed back to the fall of 2003. At that time a down hole problem was encountered ultimately requiring a side track of the well from approximately 7,500’. The Helvellyn well was successfully completed and placed on production on February 10, 2004 and is currently producing approximately 30 MMcf/day (net).

The significant capital required to develop our Matia/Cabrito and SS358 properties combined with the additional costs of unexpected delays in establishing first production from Helvellyn resulted in a constrained liquidity position for us. Further compounding this position was the decrease in production due to natural declines in our producing Gulf of Mexico properties. This decrease was not offset with production from new developments due to the relatively small amount of capital, $8.1 million, spent on our Gulf of Mexico drilling operations in 2002 compared to $55.6 million spent in 2001. Generally, capital spent on drilling in one year will result in increased production the following year. Consequently, natural gas and oil production decreased approximately 35% from 2002 to 17.1 Bcfe. We received an average realized price of $3.82 per Mcfe, $0.97 less than the average market sales price, due to our hedging positions throughout the year.

In order to improve our liquidity position and fund the current developments already in progress, we took several proactive steps throughout the year. In May of 2003 we received $10.9 million in net proceeds through an equity offering of four million shares of our common stock. In August 2003, we materially modified our then existing credit agreement and expanded our borrowing base from approximately $86.0 million to $110.0 million. In November and December 2003, we amended the credit agreement and increased the borrowing base to $125.0 million by pledging our assets in the U.K. Sector - North Sea.

Even with a constrained liquidity position during the year, we were able to significantly add to our reserve base and we are proud of this accomplishment. During 2003 we added proved reserves, primarily through acquisitions, of approximately 97.2 Bcfe in the Gulf of Mexico and approximately 6.3 Bcfe in the North Sea resulting in a 526% net reserve replacement and an overall increase of 32% in proved reserves from the end of 2002.

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In a private transaction with a third party we acquired a 99% working interest in Mississippi Canyon 711 (“Gomez”), the largest acquisition we have made in the Gulf of Mexico. Gomez, comprising approximately 40% of our Gulf of Mexico reserves with initial development costs of approximately $90.0 million, will be part of our development program primarily in 2005. Prior to our ownership, six wells were drilled on Gomez. Four wells are temporarily abandoned and are re-enterable. We plan to re-enter two wells in the southern portion and establish production from two reservoirs in 2005. Subsequently, we plan to re-enter two wells in the northern portion of the block. As we develop this property we may, as we have done with other projects, elect to bring in partners on a promoted basis to reduce our portion of the capital commitment. In 2003 we expanded our North Sea operation into the Dutch Sector with the acquisition of Block L-06d. This block is scheduled to be part of our 2004 and 2005 development program. We also expanded our inventory of properties in the UK Sector - North Sea with the offering by the DTI of two licenses in the 21^st Licensing Round for two blocks in the Emerald field. These blocks are currently being evaluated by ATP and accordingly no reserves have been recorded at December 31, 2003. As we complete the development plans for the Emerald field in 2005, we expect to record proved reserves associated with this property upon completion of our evaluation. See Note 6, “Acquisitions”, to the Consolidated Financial Statements.

2004 Operational and Financial Objectives

We believe that 2004 production will exceed that of 2003 as a result of our 2003 development program in the Gulf of Mexico and the commencement of production from Helvellyn in the North Sea during February 2004. With the initial production from Helvellyn, we achieved commercial production from our first North Sea development. The projected production should also command a higher realized price than in recent years due to the expiration of our relatively low priced hedging contracts, most of which were put in place in 2001. Our revenues, profitability and cash flows are highly dependent upon many factors, particularly our production results and the price of natural gas and oil. Price volatility in the natural gas market has remained prevalent in the last few years. Throughout 2002 and 2003, the NYMEX futures market reported relatively high natural gas and oil contract prices. To lock in these attractive prices, we currently have derivative instruments in place which hedge 9.3 Bcfe and 3.0 Bcfe of estimated volumes for 2004 and 2005, respectively, at an average price of $5.25 per Mcfe and $5.62 Mcfe, respectively.

The income tax expense of $21.2 million in 2003 was primarily due the Company 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 11 “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. We have incurred net operating losses in 2003 and prior 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 2004, we may reverse a portion of the valuation allowance in an amount at least sufficient to eliminate any tax provision in that period. We expect a significant increase in 2004 production over 2003 as a result of the development activities at our Helvellyn, Matia/Cabrito and SS358 developments during 2003 and the first quarter of 2004. This increased production combined with higher realized prices should result in a substantial increase in our 2004 results of operations.

We have budgeted approximately $50.0 to $60.0 million for 2004 development operations on nine properties with undeveloped reserves in the Gulf of Mexico and approximately $5.0 to $10.0 million in the North Sea. Of particular note is that eight of the nine 2004 Gulf of Mexico developments are on properties with existing infrastructure (platforms and pipelines) which should significantly decrease the time from initial capital expenditures to first production. In the first quarter of 2004, 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% are proved undeveloped reserves.

Recent Developments

In order improve our liquidity position and to ensure we are able to develop our reserves as projected, we entered into a new Senior Secured Term Loan on March 29, 2004. As more fully disclosed in “Liquidity and Capital Resources – New Term Loan”, our new term loan is $185.0 million of which $150.0 million is a Senior Secured First Lien Term Loan Facility and $35.0 million is a Senior Secured Second Lien Term Loan Facility (“Term Loan”). The Term Loan matures in March 2009 and is secured by substantially all of our oil and gas assets in the Gulf of Mexico and the U.K. Sector – North Sea. We used $116.2 million of the proceeds of the Term Loan to repay in full our previous credit facility and recognized a non-cash loss on extinguishment of debt of approximately $2.6 million in the first quarter of 2004. At closing, we received net proceeds of approximately $56.0 million after repaying our previous credit facility and fees associated with the transaction.

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Results of Operations

For the years ended December 31, 2003, 2002 and 2001, we reported net losses of $50.8 million ($2.21 per share), $4.7 million ($0.23 per share) and $21.4 million ($1.09 per share), respectively.

Oil and Gas Revenues

Sales volumes, averaged realized prices and oil and gas production revenue for the years ended December 31, 2003, 2002 and 2001 were as follows:

Excluding the effects of risk management activities, the decrease in oil and gas revenue in 2003 compared to 2002 was the result of a decrease in production volumes as a result of natural decline, adverse weather conditions and repairs on pipelines and host platform facilities. The decrease was partially offset by an increase in our price realizations.

Excluding the effects of risk management activities, the decrease in oil and gas revenue in 2002 compared to 2001 was primarily the result of lower gas prices and gas volumes partially offset by an increase in oil prices and oil volumes. Two properties were completed and began production in 2002 and one property was completed in September 2001 but did not contribute a full year of production until 2002.

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Lease Operating Expense

Lease operating expenses include costs incurred to operate and maintain wells and related equipment and facilities. These costs include, among others, workover expenses, operator fees, processing fees, insurance and transportation. Lease operating expense for the years ended December 31, 2003, 2002 and 2001 was as follows ($ in thousands):