Form 10-K

Indicate by check mark if the Registrant is a well-known seasoned issuer as defined in Rule 405 of the Securities Act. Yes x No ¨

Indicate by check mark if the Registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ¨ No x

Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨

Indicate by check mark 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 a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act.

Indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ Nox

The aggregate market value of the voting and non-voting common stock held by non-affiliates of the Registrant as of June 30, 2006 (the last business day of the Registrant’s most recently completed second fiscal quarter) was approximately $869,175,188. The number of shares of the Registrant’s common stock outstanding as of February 20, 2007 was 30,198,970.

Selected portions of ATP Oil & Gas Corporation’s definitive Proxy Statement, which will be filed with the Securities and Exchange Commission within 120 days after December 31, 2006, are incorporated by reference in Part III of this Form 10-K.

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

This annual report includes assumptions, expectations, projections, intentions or beliefs about future events. These statements are intended as “forward-looking statements” under the Private Securities Litigation Reform Act of 1995, Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Act of 1934. 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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Crude oil and other liquid hydrocarbons are converted into cubic feet of gas equivalent based on six Mcf of gas to one barrel of crude oil or other liquid hydrocarbons.

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

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

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

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

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

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

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

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. See Regulation S-X, Rule 4-10(a)(2), (3) and (4), (Reg. § 210.4-10) available on the Internet at www.sec.gov/about/forms/regs-x.pdf.

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

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

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

Index to Financial Statements

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

At December 31, 2006, we had estimated net proved reserves of 636.9 Bcfe, of which approximately 359.4 Bcfe (56%) was in the Gulf of Mexico and 277.5 Bcfe (44%) was in the North Sea. Year-end reserves were comprised of 329.2 Bcf of natural gas (52%) and 51.3 MMBbls of oil (48%). The majority of our oil reserves (66%) are located in the Gulf of Mexico, with the balance located in the North Sea. The majority of our natural gas reserves (52%) are located in the North Sea, with the balance located in the Gulf of Mexico. Of our total proved reserves, 129.6 MMcfe (20%) were producing, 84.3 MMcfe (13%) were developed and not producing and 423.0 MMcfe (66%) were undeveloped. The estimated pre-tax PV-10 of our proved reserves at December 31, 2006 was $1.3 billion. See “Item 2. Properties—Oil and Natural Gas Reserves” for a reconciliation to after-tax PV-10.

At December 31, 2006, we had leasehold and other interests in 72 offshore blocks, 44 platforms and 112 wells, including 14 subsea wells, in the Gulf of Mexico. We operate 94 (84%) of these wells, including all of the subsea wells, and 86% of our offshore platforms. We also had interests in 11 blocks and 2 company-operated subsea wells in the North Sea. Our average working interest in our properties at December 31, 2006 was approximately 81%. For more information regarding our operations and assets in the Gulf of Mexico and North Sea, see Note 14, “Segment Information,” to the Notes to Consolidated Financial Statements.

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

We believe our strategy significantly reduces the risks associated with traditional oil and natural gas exploration. Our focus is to acquire properties that have been explored by others and have reservoirs that appear to contain commercially productive quantities of oil and gas. Many of the properties contain proved undeveloped reserves. Occasionally we will acquire properties where previous drilling has encountered reservoirs that appear to contain commercially productive quantities of oil and gas even though the reservoirs do not meet the SEC definition of proved reserves. Some of our acquisitions contain proved producing reserves.

We focus on acquiring properties 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 perceived reserve potential. Also, 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. Some projects may provide lower economic returns after initial exploration to a larger

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company due to cost structure. 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, we are able to minimize up-front acquisition costs and concentrate available capital on the development phase of these properties. For the three year period ending December 31, 2006, we have added 243.5 Bcfe of proved oil and natural gas reserves through acquisitions at a total cost of $120.4 million. Development costs for this same period were approximately $978.8 million.

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 influence the 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 quickly.

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

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

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

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

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

The Outer Continental Shelf Lands Act, which the FERC implements with regard to transportation and pipeline issues, requires that all pipelines operating on or across the Outer Continental Shelf provide open-access, non-discriminatory service. Previously the FERC enforced this provision pursuant to its authority under both the Natural Gas Act and the Outer Continental Shelf Lands Act. In 2003 the courts determined that the FERC had only limited authority to enforce its open access rules on the Outer Continental Shelf and decided, instead, that such authority primarily rested with others. 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. It should be noted, however, that the FERC has before it pending rulemaking to consider whether to reformulate the test it applies for defining whether an entity is engaged in non-jurisdictional gathering in the shallow waters of the Outer Continental Shelf. Further, the Minerals Management Service, or MMS, has asked for comments on whether it should implement regulations under its Outer Continental Shelf Lands Act authority on gatherers and other entities to ensure open and non-discriminatory access on gathering systems and production facilities on the Outer Continental Shelf. Although we have no way of knowing whether the MMS will proceed with implementing regulations of this nature, we do not believe that any FERC action taken under its Outer Continental Shelf Lands Act jurisdiction will affect us in a way that materially differs from the way it affects other natural gas producers, gatherers and marketers.

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

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

Index to Financial Statements

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. Under some circumstances, the MMS may require any of our operations on federal leases to be suspended or terminated. Any such suspension or termination could materially adversely affect our financial condition and results of operations.

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

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

Regulated pipelines that transport crude oil, condensate, and natural gas liquids are subject to common carrier obligations that generally ensure non-discriminatory access. With respect to interstate pipeline transportation subject to regulation of the FERC under the Interstate Commerce Act, rates generally must be cost-based, although market-based rates or negotiated settlement rates are permitted in certain circumstances. Pursuant to FERC Order No. 561, issued in October 1993, the FERC implemented regulations generally grandfathering all previously unchallenged interstate pipeline rates and made these rates subject to an indexing methodology. Under this indexing methodology, pipeline rates are subject to changes in the Producer Price Index for Finished Goods. A pipeline can seek to increase its rates above index levels provided that the pipeline can establish that there is a substantial divergence between the actual costs experienced by the pipeline and the rate resulting from application of the index. A pipeline can seek to charge market-based rates if it establishes that it lacks significant market power. In addition, a pipeline can establish rates pursuant to settlement if agreed upon by all current shippers. A pipeline can seek to establish initial rates for new services through a cost-of-service proceeding, a market-based rate proceeding, or through an agreement between the pipeline and at least one shipper not affiliated with the pipeline. As provided for in Order No. 561, the FERC’s indexing methodology is subject to review at five year intervals.

With 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.

Index to Financial Statements

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

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

The Oil Pollution Act of 1990, also known as “OPA,” and related regulations impose a variety of regulations on “responsible parties” related to the prevention of oil spills and liability for damages resulting from such spills in U.S. waters. A “responsible party” includes the owner or operator of a facility or vessel, or the lessee or permittee of the area in which an offshore facility is located. The OPA assigns liability to each responsible party for the costs of cleaning up an oil spill and for a variety of public and private damages resulting from a spill. While liability limits apply in some circumstances, a party cannot take advantage of liability limits if the spill was caused by a party’s gross negligence or willful misconduct, a violation of a federal safety, construction or operating regulation, or a failure to report a spill or to cooperate fully in a cleanup. Even if applicable, the liability limits for offshore facilities require the responsible party to pay all removal costs, plus up to $75.0 million in other damages. Few defenses exist to the liability imposed by the Oil Pollution Act of 1990.

The OPA also requires a responsible party to submit proof of its financial responsibility to cover environmental cleanup and restoration costs that could be incurred in connection with an oil spill. Under this Act, parties responsible for offshore facilities must provide financial assurance of at least $35.0 million to address oil spills and associated damages, with this financial assurance amount increasing up to $150.0 million in certain limited circumstances if the MMS determines that a higher amount is warranted. The OPA also imposes other requirements, such as the preparation of an oil spill contingency plan, which we have in place.

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

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

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

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

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

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

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offshore production facilities. Health and safety offshore is further governed by the Health and Safety at Work Act 1974 and applicable regulations.

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

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

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

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

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.

At December 31, 2006 we had 52 full-time employees in our Houston office, 5 full-time employees in our U.K. office and 2 full-time employees in our Netherlands office. None of our employees is covered by a collective bargaining agreement. We regularly use the services of independent consultants and contractors to perform various professional services, particularly in the areas of construction, design, well-site supervision, permitting and environmental assessment. Independent contractors usually perform field and on-site production operation services for us, including gauging, maintenance, dispatching, inspection and well testing.

Our Internet website is 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

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reports filed or furnished pursuant to Section 13 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.

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

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

Estimates of our oil and natural gas reserves and the costs and timing associated with developing these reserves may not be accurate. Additionally, approximately 66% of our total proved reserves are undeveloped. Development of these reserves may not yield the expected results, or the development may be delayed or the development costs may exceed our estimates, any of which may materially affect our financial position and results of operations. Development activity may result in downward adjustments in reserves or higher than estimated costs.

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

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

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

The size of our operations and our capital expenditure budget limits the number of properties that we can develop in any given year. Complications in the development of any single material well may result in a material adverse effect on our financial condition and results of operations. For instance, during 2006, we experienced production delays and increased development costs in connection with the development of our Tors wells in the North Sea. In late 2005, we experienced delays and increased development costs in developing our Gomez project in the Gulf of Mexico as a result of hurricanes Katrina and Rita.

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 effect on our financial condition and results of operations.

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

Shortages or an increase in cost of drilling rigs, equipment, supplies or personnel could delay or adversely affect our operations, which could have a material adverse effect on our business, financial condition and results of operations. In periods of increased drilling activity in the Gulf of Mexico and the North Sea, we may experience increases in associated costs, including those related to drilling rigs, equipment, supplies and personnel and the services and products of other vendors to the industry. Increased drilling activity in the Gulf of Mexico and the North Sea also decreases the availability of offshore rigs and associated equipment. These

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costs may increase further and necessary equipment and services may not be available to us at economical prices.

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, 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. Cash paid for capital expenditures for oil and gas properties was approximately $585.5 million, $420.5 million and $87.4 million for the years ended December 31, 2006, 2005 and 2004, respectively. Because we have experienced a negative working capital position in past years, we have been dependent on debt and equity financing to meet our working capital requirements that were not funded from operations.

For 2007, we plan to finance anticipated expenses, debt service and acquisition and development requirements with available cash, funds generated from cash provided by operating activities and net cash proceeds from the potential sale of assets, issuance of debt or new equity offerings. If these anticipated funds are less than our requirements, we may have to forego or reduce our capital program.

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.

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

Our revenues, profitability and future growth and the carrying value of our properties depend substantially on the prices we realize for our oil and natural gas production. Our realized prices also affect the amount of cash flow available for capital expenditures and our ability to borrow and raise additional capital.

Historically, the markets for oil and natural gas have been volatile, and they are likely to continue to be volatile in the future. For example, oil and natural gas prices increased significantly in late 2000 and early 2001 and then steadily declined in 2001, only to climb again in recent years to near all-time highs before declining again in late 2006. Among the factors that can cause this volatility are:

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

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

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As required by our lenders, we periodically utilize financial derivative instruments and fixed price forward sales contracts with respect to a portion of our expected production, generally not less than 40% or more than 80% of such production. These instruments expose us to risk of financial loss if:

Our results of operations may be negatively impacted in the future by our financial derivative instruments and fixed price forward sales contracts—our fixed forward sales are designated as normal sales under derivative accounting rules—and these instruments may limit any benefit we would receive from increases in the prices for oil and natural gas. For the years ended December 31, 2006, 2005 and 2004, we realized a loss on settled financial derivatives of $3.2 million, $0.7 million and $1.2 million, respectively.

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

In November 2006, we amended our Second Amended and Restated credit agreement, dated June 22, 2006 (the “Previous First Lien Credit Agreement”) and entered into a Second Lien Credit Agreement (the “Second Lien Credit Agreement”). In December 2006, we entered into the Third Amended and Restated Credit Agreement (the “First Lien Credit Agreement”) which amends and restates the Previous First Lien Credit Agreement and all prior amendments thereto. As amended, the First Lien Credit Agreement provides for aggregate outstanding borrowings of $900.0 million (the “First Lien Term Loans”) and up to $50.0 million under a Senior Secured Revolving Credit Facility (the “Revolver”). The Second Lien Credit Agreement provides for aggregate outstanding borrowings of $175.0 million (the “Second Lien Term Loans” and, together with the First Lien Term Loans, the “Term Loans”). The First Lien Term Loans mature in April 2010 and the Second Lien Term Loans mature in October 2010. The Revolver matures in October 2009. The Term Loans and the Revolver are secured by substantially all of our oil and gas assets in the Gulf of Mexico and a pledge of 65% of the capital stock of our subsidiaries, ATP (UK) and ATP Oil & Gas (Netherlands) B.V., and are guaranteed by our wholly owned subsidiary ATP Energy, Inc. As of December 31, 2006, we had an aggregate $1.071 billion principal outstanding under the Term Loans, and no amounts outstanding under the Revolver. The Term Loans contain 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 must maintain specified financial requirements under the terms of our Term Loans and the Revolver including the following, as defined in the First Lien Credit Agreement and the Second Lien Credit Agreement:

These restrictions may make it difficult for us to successfully execute our business strategy or to compete in our industry with companies not similarly restricted. While we were in compliance with all of the financial covenants applicable to our Term Loans at December 31, 2006, 2005 and 2004, during 2003 and in February 2004, we were required to obtain waivers for certain of our financial covenants in our prior credit facility. If

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we are unable to meet the requirements of our Term Loans or any new financial transaction that we may enter into, we may be required to seek waivers from our lenders and there is no assurance that such waivers would be granted.

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

Our debt, trade payables, and related interest payment requirements may have important consequences. For instance, they 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 Gulf of Mexico properties are subject to rapid production declines. Therefore, we are required to replace our reserves at a faster rate than companies whose onshore reserves have longer production periods. We may not be able to identify or complete the acquisition of properties with sufficient proved reserves to implement our business strategy.

Production of reserves from reservoirs in the Gulf of Mexico generally declines more rapidly than production from reservoirs in many other producing regions of the world. While this results in recovery of a relatively higher percentage of reserves from properties in the Gulf of Mexico during the initial years of production, we must incur significant capital expenditures to replace declining production.

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

If management’s estimates of the recoverable reserves on a property are revised downward, if development costs exceed previous estimates or if oil and natural gas prices decline, we may be required to record additional noncash impairment write-downs 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

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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 an impairment of $19.5 million for the year ended December 31, 2006 and no impairments in 2005 and 2004.

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

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

Our development activities may be unsuccessful for many reasons, including cost overruns, equipment shortages and mechanical difficulties. Moreover, the successful drilling of a natural gas or oil well does not ensure a profit on investment. A variety of factors, both technical 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.

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

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

Index to Financial Statements

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

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

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

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

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

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

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

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

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The net assets, net earnings and cash flows from our wholly owned subsidiaries in the U.K. and the Netherlands are based on the U.S. dollar equivalent of such amounts measured in the applicable functional currency. These foreign operations have the potential to impact our financial position due to fluctuations in the local currency arising from the process of re-measuring the local functional currency in the U.S. dollar. Any increase in the value of the U.S. dollar in relation to the value of the local currency will adversely affect our revenues from our foreign operations when translated into U.S. dollars. Similarly, any decrease in the value of the U.S. dollar in relation to the value of the local currency will increase our development costs in our foreign operations, to the extent such costs are payable in foreign currency, when translated into U.S. dollars. We have not utilized derivatives or other financial instruments to hedge the risk associated with the movement in foreign currencies.

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

Our success will depend on our ability to retain and attract experienced geoscientists and other professional staff. As of December 31, 2006, we had 22 engineers, geologist/geophysicists and other technical personnel in our Houston office, two engineers, geologist/geophysicists and other technical personnel in our U.K. location and one engineer in our Netherlands office. We depend to a large extent on the efforts, technical expertise and continued employment of these personnel and members of our management team. If a significant number of them resign or become unable to continue in their present role and if they are not adequately replaced, our business operations could be adversely affected.

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 30% of our outstanding shares of common stock as of February 20, 2007. 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.

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

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

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

Development, production and sale of oil and natural gas in the 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:

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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.

We are engaged in the acquisition, development and production of oil and natural gas properties in the Gulf of Mexico and the North Sea. At December 31, 2006, we owned leasehold and other interests in 72 offshore blocks, 44 platforms and 112 wells, including 14 subsea wells, in the Gulf of Mexico. We operate 94 (84%) of these wells, including all of the subsea wells, and 86% of our offshore platforms. We also had interests in 11 blocks and 2 company-operated subsea wells in the North Sea. Our average working interest in our properties at December 31, 2006 was approximately 81%. As of December 31, 2006, we had leasehold interests located in the Gulf of Mexico and North Sea covering approximately 456,331 gross and 380,743 net acres, of which 257,102 gross acres were developed and 187,428 net acres were developed.

Acquisitions—We closed three transactions with companies for the purchase of minerals in place during 2006. These purchases, which total $30.0 million in acquisition costs, resulted in recording 136.3 Bcfe of proved reserves from acquisitions.

During the second and third quarter of 2006, we acquired in two separate transactions a 100% working interest in Mississippi Canyon Blocks 941, 942 and Atwater Valley Block 63, collectively called the Telemark Hub. At December 31, 2006, as noted above, our independent third party reservoir engineers estimated 134.9 Bcfe of proved undeveloped reserves at the Telemark Hub. In addition to the reservoirs with proved undeveloped reserves, we have identified other reservoirs which we believe could contain recoverable hydrocarbons based on previous drilling as well as selected exploratory opportunities. As of December 31, 2006, we had begun engineering and construction of a floating drilling and production facility for the Telemark Hub which is expected to be installed in mid-2008. Costs incurred, excluding acquisition costs, during 2006 at the Telemark Hub were approximately $11.0 million. We serve as operator of each of the blocks.

At Ship Shoal 351, we increased our ownership from 50% to 100% in exchange for the assumption of future abandonment liability. There are no proved reserves associated with this acquisition; however, previous drilling has indicated the presence of recoverable hydrocarbons. At December 31, 2006, we were installing a platform at Ship Shoal 351 and in February 2007 we began drilling the first of at least two planned wells. We hold a 100% working interest and serve as operator at Ship Shoal 351.

Additionally, we acquired three blocks for $4.3 million at the Gulf of Mexico Offshore Lease Sales held in 2006. Two of the blocks have been previously drilled and encountered logged hydrocarbons. We hold a 100% working interest and serve as operator of each of the blocks.

Development—On the Gulf of Mexico Shelf during 2006, five wells were drilled, all of which were successful. Four of the wells, located at West Cameron 663, High Island 74, South Marsh Island 233 and

Index to Financial Statements

West Cameron 237, were completed and placed on production in 2006. The remaining well at South Timbalier 77 is expected to be placed on production in the first half of 2007 upon completion of the platform and pipeline.

Mississippi Canyon 711 (“MC 711”) and the Gomez Hub—After delays experienced in 2005 due to Hurricanes Katrina and Rita, two wells in the southern portion of the block were placed on production late in the first quarter of 2006. A third well in the northern portion of the block was drilled and made ready for production. This well, along with another well to be drilled in the early part of 2007, is expected to be placed on production in the first half of 2007. Due to the performance of the two producing wells and the anticipated production from the new wells, plans were made in 2006 to expand the production capacity at the floating production facility that serves the Gomez Hub. This expansion is planned for mid-2007. During 2006, production from Gomez averaged approximately 70.8 MMcfe per day for its essentially nine months of production reaching a high of 117.4 MMcfe per day. We operate MC 711 with a 100% working interest.

Garden Banks 409 (“Ladybug”)—In the fourth quarter 2006, we completed a new well at Ladybug and moved up-hole to complete a behind-pipe zone in a second well. The wells at Ladybug were placed on production during February 2007.

Acquisitions—Wenlock – During the fourth quarter of 2006, our wholly-owned subsidiary, ATP Oil & Gas (UK) Limited, or “ATP (UK),” acquired a 100% working interest in Block 49/12b in the Southern Gas Basin of the U.K. North Sea. Block 49/12b is an exploratory opportunity offsetting our Wenlock development. Wenlock is located in 75 feet of water and has been defined by two vertical wells that have tested at rates of 35 MMcf per day and 74 MMcf per day, respectively.

Development—Tors (Kilmar and Garrow) – During 2006, we drilled and placed on production two wells at Kilmar and at December 31, 2006 were drilling a third well at Tors in the Garrow reservoir. This well was completed and placed on production during February 2007. Previously in 2006, we completed the installation of the platform at Garrow and connected the 23-kilometer pipeline from Garrow to Kilmar. During 2006, we increased North Sea production by 10.9 Bcfe to 12.2 Bcfe, primarily due to the new production from Tors field, which we operate with an 85% working interest.

L-06d—On February 27, 2006, we announced first production at L-06d in the Dutch North Sea. With that achievement, ATP recorded flowing production in all three of its core areas: the U.S. Gulf of Mexico, the U.K. North Sea, and Dutch North Sea. ATP operates L-06d with a 50% working interest.

The following table sets forth additional information on our most significant properties as of December 31, 2006:

References below to various classifications of oil and natural gas reserves have the meaning set forth under the caption “Certain Definitions” at the front of this report.

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

The following table presents our estimated net proved oil and natural gas reserves at December 31, 2006 based on reserve reports prepared by Ryder Scott Company, L.P., Collarini Associates and DeGolyer and MacNaughton for our Gulf of Mexico reserves, Ryder Scott Company, L.P. for our Netherlands reserves and RPS Energy for our U.K. reserves.

At December 31, 2006 our standardized measure of discounted future net cash flows was $1.015 billion. The present value of future net cash flows attributable to estimated net proved reserves, discounted at 10% per annum, (“PV-10”) is a computation of the standardized measure of discounted future net cash flows on a pre-tax basis. The table below provides a reconciliation of PV-10 to the standardized measure of discounted future net cash flows at December 31, 2006. PV-10 may be considered a non-GAAP financial measure under the SEC’s regulations. We believe PV-10 to be an important measure for evaluating the relative significance of our natural gas and oil properties. PV-10 is computed on the same basis as the standardized measure of discounted future net cash flows but without deducting income taxes. We further believe investors and creditors may utilize our PV-10 as a basis for comparison of the relative size and value of our reserves to other companies. However, PV-10 is not a substitute for the standardized measure. Our PV-10 measure and the standardized measure of discounted future net cash flows (shown below in thousands) do not purport to present the fair value of our natural gas and oil 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. 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 SEC standards, the estimated costs may be inaccurate, development may not occur as scheduled and results may not be as estimated. Therefore, estimates of natural gas and oil reserves are inherently imprecise. Estimates of reserves may increase or decrease as a result of future operations.

Index to Financial Statements

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

At December 31, 2006 we had 1.0 gross development well (0.9 net development well) in the North Sea and 1.0 gross exploratory well (1.0 net exploratory well) in the Gulf of Mexico in the process of being drilled. As noted above, these two wells came on production during February 2007.

The following table presents the number of productive oil and natural gas wells in which we owned an interest as of December 31, 2006:

Index to Financial Statements

The following table summarizes our developed and undeveloped acreage holdings at December 31, 2006. Acreage in which ownership interest is limited to royalty, overriding royalty and other similar interests is excluded (in acres):

The terms of leases on undeveloped acreage are scheduled to expire as shown in the table below. The term of a lease may be extended by drilling and production operations.

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”.

We are, in the ordinary course of business, involved in various legal proceedings from time to time. Management does not believe that the outcome of these legal proceedings, individually, or 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 2006.

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Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.

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 30,198,970 shares of common stock and no shares of preferred stock outstanding as of February 20, 2007. Our common stock is traded on the NASDAQ Global Select Market under the ticker symbol ATPG.

The following table sets forth the range of high and low sales prices for the common stock as reported on the NASDAQ National Market for the periods indicated below. Such over-the-counter market quotations reflect inter-dealer prices, without retail mark-up, mark-down or commission and may not necessarily represent actual transactions.

We have never declared or paid 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 cash dividends on our common stock in the foreseeable future. Payment of any future dividends will be at the discretion of our board of directors after taking into account many factors, including our financial condition, operating results, current and anticipated cash needs and plans for expansion. In addition, our current term loan prohibits us from paying cash dividends on our common stock. Any future dividends may also be restricted by any loan agreements which we may enter into from time to time.

The information set forth in the graph and table below compares the value of ATP’s Common Stock to the NASDAQ Market Index and to a “Peer Group Index”, which is comprised of the following eight independent oil and gas exploration and production companies with operations and assets focused in the Gulf of Mexico region: Energy Partners, Ltd., Houston Exploration Company, Newfield Exploration Company, Noble Energy Inc., Pogo Producing Company, Remington Oil and Gas Corporation (“Remington”) through 12/31/05, Helix Energy Solutions Group Inc. (successor to Remington) for 2006 only, Stone Energy Corporation and Callon Petroleum Company.

Each of the total cumulative returns presented assumes a $100 investment beginning February 6, 2001, the date ATP commenced trading, and ending December 31, 2006. The performance of the indices is shown on a total return (dividend reinvestment) basis; however, we paid no dividends on our Common Stock during the period shown. The graph lines merely connect the beginning and end of the measuring periods and do not reflect fluctuations between those dates.

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

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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

ATP Oil & Gas Corporation is engaged in the acquisition, development and production of oil and natural gas properties in the Gulf of Mexico and the North Sea. We seek to acquire and develop properties with proved undeveloped reserves (“PUD”) that are economically attractive to us but are not strategic to major or large exploration-oriented independent oil and gas companies. Occasionally we will acquire properties that are already producing or where previous drilling has encountered reservoirs that appear to us to contain commercially productive quantities of oil and gas even though the reservoirs do not meet the SEC definition of proved reserves. We believe that our strategy provides assets for us to develop and produce without the risk, cost or time of traditional exploration.

We seek to create value and reduce operating risks through the acquisition and subsequent development of properties in areas that have:

Our focus is on acquiring properties that have become non-core or non-strategic to their original owners for a variety of reasons. For example, larger oil companies from time to time adjust their capital spending or shift their focus to exploration prospects which they believe offer greater reserve potential. Some projects provide lower economic returns to a company due to its cost structure within that company. Also, due to timing or budget constraints, a company may be unwilling or unable to develop a property before the expiration of the lease. Because of our cost structure, expertise in our areas of focus and ability to develop projects, the properties may be more financially attractive to us than the seller. Given our strategy of acquiring properties that contain proved reserves or where previous drilling indicates to us the presence of recoverable hydrocarbons, our operations typically are lower risk than exploration-focused Gulf of Mexico and North Sea operators.

Index to Financial Statements

simultaneously obtaining the various required components such as the pipeline and the production platform or subsea well completion equipment. We believe this strategy, combined with our strong technical abilities to evaluate and implement a project’s requirements, allows us to efficiently complete the development project and commence production.

To enhance the economics and return on investment of a project, we sometimes develop the project to a value creation point and either sell an interest or bring in partners on a promoted basis during the high capital development phase. In 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 per Mcfe for proved reserves, of which 93.5% were proved undeveloped reserves. In 2005 we sold a 15% interest on a promoted basis in our Tors project in the U.K. Sector of the North Sea after the field development plan was obtained.

The year 2006 was another year of major growth in proved reserves and a step change in production rates for ATP. The growth in reserves was accomplished primarily through acquisitions (136.3 Bcfe) during a period of historically high oil and gas prices. Also of significance in 2006 was a marked increase in proved developed reserves, growing from 128.4 Bcfe at the end of 2005 to 213.8 Bcfe at December 31, 2006. Our growth in production from an average of 55 MMcfe per day during 2005 to an average of 139 MMcfe per day during 2006 was primarily a result of new production from our Mississippi Canyon 711 (Gomez) project in the Gulf of Mexico and our Tors project in the North Sea.

At December 31, 2006, we had proved reserves of 636.9 Bcfe, of which 56% are located in the Gulf of Mexico and the remaining 44% are in the North Sea. The pre-tax PV-10 of our proved reserves at December 31, 2006 was $1.3 billion. See “Item 2. Properties—Oil and Natural Gas Reserves” for reconciliation to our after-tax PV-10 of $1.0 billion. In addition, we have scheduled for drilling or completion, properties where previous drilling into the targeted reservoirs indicates to the Company the presence of commercially productive quantities of hydrocarbons even though the reservoirs do not meet the SEC definition of proved reserves. Upon completion of drilling, completion or testing of wells on these blocks and similar properties in the Company’s portfolio, the Company anticipates that it may be able to record proved reserves associated with several of these properties.

We closed three transactions with companies for the purchase of minerals in place during 2006. These purchases, which total $30.0 million in acquisition costs, resulted in recording 136.3 Bcfe of proved reserves from acquisitions.

During the second and third quarter of 2006, ATP acquired in two separate transactions a 100% working interest in Mississippi Canyon Blocks 941, 942 and Atwater Valley Block 63, collectively called the Telemark Hub. At December 31, 2006, as noted above, ATP’s independent third party reservoir engineers estimated 134.9 Bcfe of proved undeveloped reserves at the Telemark Hub. In addition to the reservoirs with proved undeveloped reserves, ATP has identified other reservoirs which it believes could contain recoverable hydrocarbons based on previous drilling as well as selected exploratory opportunities. As of December 31, 2006, ATP had begun engineering and construction of a floating drilling and production facility for the Telemark Hub which is expected to be installed in mid-2008. Costs incurred excluding acquisition costs during 2006 at the Telemark Hub were approximately $11.0 million. We serve as operator of each of the blocks.

Index to Financial Statements

Wenlock—During the fourth quarter of 2006, ATP (UK) acquired a 100% working interest in Block 49/12b in the Southern Gas Basin of the U.K. North Sea. Block 49/12b is an exploratory opportunity offsetting our Wenlock development. Wenlock is located in 75 feet of water and has been defined by two vertical wells that have tested at rates of 35 MMcf per day and 74 MMcf per day. During 2006 we designed and constructed a production platform at Wenlock and installed a pipeline to the host platform. Drilling and subsequent production is planned at Wenlock for the first half of 2007 with development at Block 49/12b scheduled for 2008.

Gulf of Mexico Shelf—On the Gulf of Mexico Shelf during 2006, five net wells were drilled and all were successful. Four of the wells at West Cameron 663, High Island 74, South Marsh Island 233 and West Cameron 237 were completed and placed on production in 2006. The remaining well at South Timbalier 77 is expected to be placed on production in the first half of 2007 upon completion of the platform and pipeline.

MC 711 and the Gomez Hub—After delays experienced in 2005 due to Hurricanes Katrina and Rita, two wells in the southern portion of the block were placed on production late in the first quarter of 2006. A third well in the northern portion of the block was drilled and made ready for production. This well, along with another well to be drilled in the early part of 2007, are expected to be placed on production in the first half of 2007. Due to the performance of the two producing wells and the anticipated production from the new wells, plans were made in 2006 to expand the production capacity at the ATP Innovator, the floating production facility that serves the Gomez Hub. This expansion is planned for 2007. During 2006, production from Gomez averaged approximately 70.8 MMcfe per day for its essentially nine months of production reaching a high of 117.4 MMcfe per day. ATP operates MC 711 with a 100% working interest.

Ladybug—In the fourth quarter 2006, we completed a new well at Ladybug and moved up hole to complete a behind pipe zone in a second well. During February 2007, the wells at Ladybug were placed on production.

Development—Tors (Kilmar and Garrow)—During 2006, we drilled and placed on production two wells at Kilmar and at December 31, 2006 were drilling a third well at Tors in the Garrow reservoir. This well was completed and placed on production during February 2007. Previously in 2006, we completed the installation of the platform at Garrow and connected the 23-kilometer pipeline from Garrow to Kilmar. During 2006, we increased North Sea production by 10.9 Bcfe to 12.2 Bcfe, primarily due to the new production from Tors field, which we operate with an 85% working interest.

The acquisitions, significant increase in proved reserves and proved developed reserves coupled with additional recoverable hydrocarbons identified by ATP and the increase in production allowed us to complete three new financings in 2006. During the first quarter, we issued $150.0 million of 12.5% non-convertible perpetual preferred stock, which raised net proceeds of $145.5 million. During the second quarter, we amended

Index to Financial Statements

and improved the terms of our Senior Secured Credit Facility by expanding it to $525.0 million and reducing the interest rate. Net of transaction costs, this amendment added $167.7 million in additional liquidity.

In the fourth quarter, we redeemed all of our outstanding preferred shares by expanding our first lien term loan by $375.0 million, adding a new revolving credit facility for up to $50.0 million and adding a new second lien facility of $175.0 million. Subsequent to the closings, ATP has first lien debt of $898.7 million at a rate of LIBOR plus 3.5% with a maturity of April 14, 2010, an additional $50.0 million revolving credit facility with a rate of LIBOR plus 3.5% with a maturity of October 14, 2009, and a new second lien tranche of $175.0 million at a rate of LIBOR plus 4.75% with a maturity of October 14, 2010. The collateral package for these facilities is similar to the previous first lien facility. The new financings added $155.5 million in additional liquidity and reduced the overall cost of capital (preferred dividends plus interest) by approximately 200 basis points.

Cash flow from operating activities was $258.5 million for the year ended December 31, 2006, compared to $43.6 million in 2005. We had working capital at December 31, 2006 of $77.5 million, an increase of approximately $76.9 million from December 31, 2005. This increase is primarily attributable to fourth quarter 2006 financings discussed in the previous paragraph.

We had $182.6 million in cash and cash equivalents on hand at December 31, 2006, compared to $65.6 million at December 31, 2005. Cash paid for acquisition and development activities for the year 2006 was $577.0 million, compared to $420.5 million in 2005.

We will continue to pursue acquisitions that meet our criteria as well as devote considerable resources to our developments in 2007. In January 2007, we acquired additional blocks at our Gomez Hub and at our King’s Peak/Canyon Express Hub. The Gomez Hub addition is expected to add proved undeveloped reserves, an interest in two adjacent blocks and a commitment to process up to a designated amount of production from these two blocks beginning in 2009. The blocks at our King’s Peak/Canyon Express Hub included an increase in our ownership percentage in the Canyon Express Pipeline System and one producing property, which will add proved reserves. The technical evaluation of these properties is being refined and no reserves from these 2007 acquisitions were included in our year-end 2006 reserve report.

During 2007, efforts will be spent completing and bringing to production at least two more wells at Gomez, the wells at Ship Shoal 351 and South Timbalier 77. As noted earlier, the third well at Tors (the Garrow #1) and the two wells at Ladybug began producing during February 2007.

In addition to these developments, we have projects with proved undeveloped reserves at December 31, 2006 that are scheduled for 2007 development and production. We also have scheduled for drilling or completion properties in which previous drilling into targeted reservoirs indicates to the Company the presence of commercially productive quantities of hydrocarbons, although these reservoirs did not meet the SEC definition of proved reserves at the end of 2006. For example, the previously discussed Ship Shoal 351 is a property that the Company believes to have commercially productive hydrocarbons that is not included in our year-end 2006 reserve report.

We have commenced engineering and procurement activities on our Cheviot property in the U.K. North Sea. Cheviot, our largest property in terms of proved reserves, is a multi-year development with first production targeted in late 2009 or 2010. We have also begun engineering, procurement and construction at our Telemark Hub in the Gulf of Mexico. Installation of the floating drilling and production facility is planned for mid-2008 with first anticipated production in late 2008 or early 2009. Other potential developments for 2007 in the Gulf of Mexico and North Sea are currently being evaluated. We believe that 2007 production will exceed that of 2006 as a result of our recent development programs and projects scheduled for development in 2007.

Index to Financial Statements

Our production may command lower realized oil and gas prices in 2007 than in recent years as a result of current strip prices compared to recent years. Our 2007 hedge prices are currently in excess of many of the 2007 strip prices which should provide a realized price in excess of the strip prices for those volumes covered by hedges, if prices do not increase. Our revenues, profitability and cash flows are highly dependent upon many factors, particularly our production results and the price of oil and natural gas. To mitigate future price volatility, we may hedge additional production.

For the years ended December 31, 2006 and 2005, we reported net loss available to common shareholders of $39.3 million and $12.6 million, or $1.33 and $0.43 per share, respectively, and for the year ended December 31, 2004 we reported net income available to common shareholders of $1.4 million or $0.05 per share.

Revenues presented in the table and the discussion below represent revenues from sales of our oil and natural gas production volumes. Production sold under fixed price delivery contracts, which have been designated for the normal purchase and sale exemption under SFAS 133, are also included in these amounts. Approximately 67%, 61% and 47% of our oil production was sold under these contracts for the years ended December 31, 2006, 2005 and 2004, respectively. Approximately 19%, 54% and 46% of our natural gas production was sold under these contracts for the comparable periods. The realized prices below may differ from the market prices in effect during the periods depending on when the fixed price delivery contract was executed.

Oil and gas revenue increased 183% in 2006 compared to 2005 primarily as a result of increased production volumes and a stronger oil price. Natural gas volumes increased 100% and oil and condensate

Index to Financial Statements

volumes increased more than three-fold. Our realized sales price per Mcfe in 2006 was 11% higher as compared to 2005.

Oil and gas revenue increased 26% in 2005 compared to 2004 primarily as a result of increased commodity prices. Our realized sales price per Mcfe in 2005 was 41% higher as compared to 2004. The increase was partially offset by an 11% decrease in production.

Other revenues for the year ended December 31, 2006 are comprised of amounts realized under our Loss of Production Income insurance policy as a result of disruptions caused by the 2005 hurricanes.

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, 2006, 2005 and 2004 was as follows ($ in thousands):

The 207% increase in 2006 compared to 2005 was primarily attributable to costs incurred in the Gulf of Mexico due to the increased production levels in 2006 compared to 2005. The 19% increase in such costs on a per unit basis reflects the price spikes we experienced for materials and labor in the Gulf of Mexico after the 2005 hurricanes.

The 37% increase per Mcfe in 2005 compared to 2004 was primarily attributable to costs incurred in the Gulf of Mexico for uninsured costs incurred as a result of the tropical storm activity during 2005, and certain fixed costs relative to our lower production volumes in 2005.

During 2006, exploration expense includes the costs of geological and geophysical studies totaling approximately $2.2 million. Exploration expense in 2005 included the dry hole costs of a step-out well at our producing Eugene Island 30/71 complex. This well found non-commercial quantities of hydrocarbons, resulting in exploration and dry hole expense of approximately $5.3 million in 2005.

General and administrative expenses are overhead-related expenses, including among others, wages and benefits, legal and accounting fees, insurance, and investor relations expenses. General and administrative expense for the years ended December 31, 2006, 2005 and 2004 was as follows ($ in thousands):

The decrease in 2006 compared to 2005 was primarily due to the prior year inclusion of the ATP Employee Volvo Challenge and other compensation related costs.

The increase in 2005 compared to 2004 was primarily due to a $7.9 million increase in compensation related costs.

Index to Financial Statements

In the first quarter of 2004, we incurred non-recurring costs of $1.9 million to maintain compliance with the requirements of our previous lender. These costs primarily consisted of legal and professional fees of $1.6 million.

Depreciation, depletion and amortization expense (“DD&A”) for the years ended December 31, 2006, 2005 and 2004 was as follows ($ in thousands):

DD&A expense increased 165% in 2006 as compared to 2005 primarily due to the ramp-up in production. The increase in DD&A on a per unit basis was due to some relatively higher cost properties placed in service late in 2005.

DD&A expense increased 15% in 2005 as compared to 2004 primarily due to the increased cost for the properties placed in production during 2003 and 2004 and decreased production from two of our older lower cost properties.

We recorded an impairment of oil and gas properties for 2006 totaling $19.5 million related to certain producing properties acquired during 2005 and a few smaller end-of-life properties and one unproved property in the Gulf of Mexico. This amount represents the excess carrying costs over the discounted present values of the estimated future production from those properties. These impairments were the result of reductions in estimates of recoverable reserves. Restoration of a previously recognized impairment loss is prohibited.

During 2006, we recognized an aggregate loss on abandonment of $9.6 million covering eighteen properties. The losses were the result of actual abandonment costs exceeding the previously accrued estimates, due to unforeseen circumstances that required additional work or the use of equipment more expensive than anticipated, and vendor price increases.

During 2005 and 2004, we recognized small net gains on the abandonment of certain properties which we were able to abandon at an aggregate cost less than the asset retirement obligation previously accrued.

During 2005 we recognized a net gain of $2.7 million on the sales of 15% of our interest in Tors fields in the Southern Gas Basin of the U.K. Sector—North Sea and one property in the Gulf of Mexico. In 2004, we sold 25% of our interest in seven projects containing ten offshore blocks in the Gulf of Mexico and recognized a gain of $6.0 million.

Interest income varies directly with the amount of temporary cash investments. The increase in interest income from period to period is the result of the increase in cash on hand from the Company’s aforementioned funding activities.

Interest expense increased $22.3 million, to $58.0 million for 2006 from $35.7 million for 2005 as a result of an increase in outstanding borrowings under the Term Loans, partially offset by a lower average effective floating interest rate on such borrowings.

Index to Financial Statements

Interest expense increased $13.5 million, to $35.7 million for 2005 from $22.3 million for 2004 as a result of an increase in outstanding borrowings under the Term Loan plus a higher average effective floating interest rate on such borrowings.

In the fourth quarter of 2006, we recognized a noncash loss of $28.1 million on the extinguishment of debt related to our prior credit agreement, including deferred financing costs of $23.2 million and unamortized debt discount of $4.9 million.

In the first quarter of 2004, we recognized a noncash loss of $3.3 million on the extinguishment of debt related to our prior credit facility agreement.

During 2006 we recognized current tax expense of $2.5 million primarily due to our Netherlands operations and alternative minimum tax on our U.S. net income before dividends. We recognized $14.3 million of deferred tax expense related to our U.K. and Netherlands operations.

During 2005 we recognized current tax expense of $4.0 million primarily due to an asserted tax assessment resulting from an audit of our Netherlands subsidiary. The expense related to the expected assessment was offset by a corresponding deferred tax benefit created by the timing difference on this revenue recognition item. As this benefit resulted from the timing difference, no valuation allowance was made for this asset. The remainder of our deferred tax assets recorded during the year were provided for with a valuation allowance. During 2004, we provided a valuation allowance against all of our deferred tax assets recorded during the year. The income tax expense of $21.2 million in 2003 was primarily due to the Company recording a valuation allowance of $33.6 million against our deferred tax asset as required by SFAS 109. See Note 10 “Income Taxes” to the Consolidated Financial Statements.

We recognized and paid $46.2 million of dividends during 2006 related to the Series A 13.5% and Series B 12.5% cumulative perpetual preferred stock, issued during August 2005 and March 2006, respectively. This amount included approximately $9.3 million of prepayment premium paid to the holders of such preferred stock when all of the shares were redeemed in November 2006.

During 2005, we recognized $9.9 million of dividends in-kind related to the Series A 13.5% cumulative perpetual preferred stock, which was issued during August 2005.

At December 31, 2006, we had working capital of approximately $77.5 million, an increase of approximately $76.9 million from December 31, 2005. This increase is primarily attributable to the increase in our cash flows from operations coupled with the success of our financing programs during 2006, partially offset by higher amounts spent on capital projects and the redemption of our Series A and Series B preferred stock. Historically, we have financed our acquisition and development activities through a combination of bank borrowings and proceeds from our equity offerings as well as cash from operations and by the sell-down of a portion of our interests in selected development projects. During 2006, we completed several major projects which required significant capital expenditures through the end of the year. In order to fund these development costs, we completed a private placement of preferred stock for net proceeds of $145.5 million, and expanded our Term Loan in June and in November 2006 for an additional $167.7 million and $536.3 million, respectively, net of related costs. As operator of all of our projects in development, we have the ability to significantly control the timing of most of our capital expenditures. We believe the cash flows from operating activities, new or amended debt or equity offerings combined with our ability to control the timing of substantially all of our future development and acquisition requirements will provide us with the flexibility and liquidity to meet our future planned capital requirements.

Index to Financial Statements

Operating activities. Net cash provided by operating activities was $258.5 million for the year ended December 31, 2006 compared to $43.6 million for the year ended December 31, 2005. Cash flow from operations increased primarily due to a 155% increase in equivalent production volumes and an overall 11% increase in average realized prices per Mcfe. Gas sales, including the effects of hedging, increased by $120.0 million, or 103%, due mainly to 100% higher production volumes. Oil sales, including the effects of hedging, increased by $147.5 million, or 491%, due to a 356% increase in production volumes and a 29% increase in the average price realized for oil.

Investing activities. Cash used in investing activities in 2006 and 2005 was $591.0 million and $414.1 million, respectively, and included increases in restricted cash of $13.3 million and $12.5 million, respectively. Cash paid for acquisition, development and exploration expenditures of oil and natural gas properties in the Gulf of Mexico and North Sea totaled approximately $356.0 million and $221.0 million, respectively, in 2006. Such expenditures in the Gulf of Mexico and North Sea were approximately $296.1 million and $124.4 million, respectively, in 2005, offset by the receipt of $19.8 million in proceeds for the sale of properties.

Financing activities. Cash provided by financing activities in 2006 consisted primarily of net proceeds of $703.9 million related to our Term Loans, after deducting deferred financing costs of approximately $24.6 million related to the First Lien Term Loans, and net proceeds of $145.5 million from the issuance of preferred stock, partially offset by $381.1 million paid to redeem our preferred stock. Cash provided by financing activities in 2005 consisted primarily of net proceeds of $121.7 million related to our amendment to the Term Loan, after deducting deferred financing costs of approximately $10.4 million related to the amendment and accrued interest and $169.4 million from the issuance of preferred stock, net of issuance costs.

The Company’s restricted cash represents time deposits denominated in Pounds Sterling which secures irrevocable stand-by letters of credit for our future abandonment obligations with respect to the Tors (Garrow) and Wenlock properties in the North Sea. The Letters of Credit and Reimbursement Agreements were entered into in July 2005 and August 2006, each with an initial term of one year, to be extended for successive one-year terms unless thirty days notice is given of the intention not to extend.

Amounts borrowed under our credit agreements were as follows for the dates indicated (in thousands):

On November 22, 2006, the Company, the lenders named therein and Credit Suisse (as Administrative Agent and Collateral Agent for such lenders) entered into Amendment No. 1 and Agreement (the “Amendment”) amending the Second Amended and Restated Credit Agreement dated as of June 22, 2006; the Company, the lenders named therein and Credit Suisse (as Administrative Agent and Collateral Agent for such lenders) entered into the Second Lien Credit Agreement; and the Company, ATP Energy, Inc. and Credit Suisse (as Collateral Agent under the Previous First Lien Credit Agreement and under the Second Lien Credit Agreement) entered into an Intercreditor Agreement. Under the Second Lien Credit Agreement, the Company has second lien term loans of $175.0 million. The Second Lien Term Loans bear interest at LIBOR plus 4.75% and mature in October 2010.

Index to Financial Statements

With the Amendment, we increased our aggregate borrowings under the Previous First Lien Credit Agreement by $375.0 million. We also borrowed $175.0 million under the Second Lien Credit Agreement. From this increase in borrowings, we received net proceeds of $536.3 million, after deducting $13.7 million for fees and expenses. The net proceeds were used by the Company: (a) to redeem the Series A Preferred Stock (as defined in Note 7 below), which had an original face amount of $175.0 million; (b) to redeem the Series B Preferred Stock (as defined in Note 7 below), which had an original face amount of $150.0 million; and (c) for general corporate purposes. Concurrent with the Amendment, we incurred a noncash charge of approximately $28.1 million related to the capitalized costs of the Previous First Lien Credit Agreement and approximately $9.3 million of costs related to calling and retiring all of the preferred shares.

On December 28, 2006, the Company, the lenders named therein and Credit Suisse (as Administrative Agent and Collateral Agent for such lenders) entered into the First Lien Credit Agreement. Under the First Lien Credit Agreement, the Company has first lien term loans for $900.0 million and a revolving credit and letter of credit facility in an amount not to exceed $50.0 million at any time outstanding. The First Lien Term Loans bear interest at LIBOR plus 3.5% and mature in April 2010. The Revolver, under which no amounts were outstanding as of December 31, 2006, bears interest at LIBOR plus 3.5% and matures in October 2009.

At December 31, 2006, our borrowings were secured by substantially all of our oil and gas assets in the Gulf of Mexico and a pledge of 65% of the common stock of our wholly owned subsidiaries, ATP (UK) and ATP Oil & Gas (Netherlands) B.V., were guaranteed by our wholly owned subsidiary ATP Energy, Inc., and bore interest at a weighted average rate of approximately 9.13%.

The terms of the Term Loans and the Revolver require us to maintain certain covenants. Capitalized terms are defined in the First Lien Credit Agreement and the Second Lien Credit Agreement. The covenants include:

As of December 31, 2006, we were in compliance with all of the financial covenants of our Term Loans. Significant adverse changes in our expected production levels, commodity prices and reserves or material delays or cost overruns could have a material adverse affect on our financial condition and results of operations and result in our non-compliance with these covenants. An event of non-compliance with any of the required covenants could result in a material mandatory repayment under the Term Loans.

The foregoing description of the First Lien Credit Agreement and the Second Lien Credit Agreement is qualified in its entirety by reference to the First Lien Credit Agreement and the Second Lien Credit Agreement filed as exhibits to this report and incorporated by reference herein. In addition, capitalized terms used but not defined in the foregoing description have the respective meanings assigned to such terms in the First Lien Credit Agreement and the Second Lien Credit Agreement.

Index to Financial Statements

December 31, 2006. The warrants have a term of six years and expire in March 2010. The fair value of the warrants, as determined by use of the Black-Scholes valuation model on March 29, 2004, was approximately $4.2 million and was accounted for as additional paid-in-capital and debt discount. The fair value was calculated with the following weighted-average assumptions: zero dividend yield; risk-free interest rate of 3.0%; volatility of 51.6% and an expected life of 6 years. The value was adjusted for liquidity issues associated with a potential sale of such a large volume of shares in relation to our public float. This amount and the unamortized portion of the original issue discount of $5.6 million were written off in connection with the Amendment.

During October 2005, we acquired the ATP Innovator (formerly the Rowan Midland) for the net adjusted purchase price of $46.7 million, and paid $1.7 million toward this lease in 2005, $21.0 million in 2006 and the remaining balance of $24.0 million on January 31, 2007.

On October 1, 2005, the Board of Directors of ATP authorized the issuance of one preferred share purchase right (a “Right”) with respect to each outstanding share of common stock, par value $.001 per share (the “Common Shares”), of the Company (the “Shareholder Rights Plan”). The rights were issued on October 17, 2005 to the holders of record of Common Shares on that date. Each Right entitles the registered holder to purchase from the Company one one-hundredth (1/100) of a share of Junior Participating Preferred Stock, par value $.001 per share (the “Preferred Shares”), of the Company at a price of $150.00 per one one-hundredth of a Preferred Share, subject to adjustment. The description and terms of the Rights are set forth in a Rights Agreement dated as of October 11, 2005 between the Company and American Stock Transfer & Trust Company, as Rights Agent.

The Company’s preferred stock, par value $0.001 per share, consisted of the following (in thousands):

See Note 3, “Recently Issued Accounting Pronouncements,” to the Consolidated Financial Statements.

We have various commitments primarily related to leases for office space, other property and equipment and other agreements. The following table summarizes certain contractual obligations at December 31, 2006 (in thousands):

Index to Financial Statements

Our liabilities also include asset retirement obligations ($21.3 million current and $87.1 million long-term) that represent the estimated fair value at December 31, 2006 of our obligations with respect to the retirement/plugging and abandonment of our oil and gas properties. Each reporting period the liability is accreted to its then present value. The ultimate settlement amounts and the timing of the settlements of such obligations is unknown because they are subject to, among other things, federal, state and local regulation and economic factors. See Note 2 to the Consolidated Financial Statements.

Our consolidated financial statements are prepared in conformity with generally accepted accounting principles (“GAAP”) in the U.S., which require management to make estimates and assumptions that affect the reported amounts of the assets and liabilities and disclosures of contingent assets and liabilities as of the date of the balance sheet as well as the reported amounts of revenues and expenses during the reporting period. We routinely make estimates and judgments about the carrying value of our assets and liabilities that are not readily apparent from other sources. Such estimates and judgments are evaluated and modified as necessary on an ongoing basis. Significant estimates include DD&A of proved oil and gas properties. Oil and gas reserve estimates, which are the basis for unit-of-production DD&A and the impairment analysis, are inherently imprecise and are expected to change as future information becomes available. In addition, alternatives may exist among various accounting methods. In such cases, the choice of accounting method may also have a significant impact on reported amounts.

Based on a critical assessment of our accounting policies discussed below and the underlying judgments and uncertainties affecting the application of those policies, management believes that our consolidated financial statements provide a meaningful and fair perspective of our company.

We account for our oil and gas property costs using the successful efforts accounting method. Under the successful efforts method, lease acquisition costs and intangible drilling and development costs on successful wells and development dry holes are capitalized. Costs of drilling exploratory wells are initially capitalized, but charged to expense if and when a well is determined to be unsuccessful.

Capitalized proved property acquisition costs are depleted on the unit-of-production method on the basis of total estimated units of proved reserves. Capitalized costs relating to producing properties are depleted on the unit-of-production method on the basis of total estimated units of proved developed reserves. When significant development costs (such as the cost of an off-shore production platform) are incurred in connection with a planned group of development wells before all of the planned wells have been drilled, it is occasionally necessary to exclude a portion of those development costs in determining the unit-of-production amortization rate until the additional development wells are drilled. However, in no case are future development costs anticipated in computing our amortization rate. Estimated dismantlement, restoration and abandonment costs and estimated residual salvage values are taken into account in determining amortization and depletion provisions. Expenditures for geological and geophysical testing costs are generally charged to expense unless the costs can be specifically attributed to mapping a proved reservoir and determining the optimal placement for future developmental well locations. Expenditures for repairs and maintenance are charged to expense as incurred; renewals and betterments are capitalized. The costs and related accumulated depreciation, depletion, and amortization of properties sold or otherwise retired are eliminated from the accounts, and gains or losses on disposition are reflected in the statements of operations.

Index to Financial Statements

development activities. For a property determined to be impaired, an impairment loss equal to the difference between the carrying value and the estimated fair value of the impaired property will be recognized. Restoration of a previously recognized impairment loss is prohibited. Fair value, on a depletable unit basis, 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’ reserves, future cash flows and fair value.

Costs directly associated with the acquisition and evaluation of unproved properties are excluded from the amortization base until the related properties are developed. Unproved properties are assessed quarterly and any impairment in value is charged to impairment expense. The costs of unproved properties which are determined to be productive are transferred to proved oil and gas properties and amortized on a unit-of-production basis.

The process of estimating quantities of natural gas and crude oil reserves is very complex, requiring significant decisions in the evaluation of all available geological, geophysical, engineering and economic data. The data for a given field may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. As a result, material revisions to existing reserve estimates may occur from time to time. Although every reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible, the subjective decisions and variances in available data for various fields make these estimates generally less precise than other estimates included in the financial statement disclosures. We use the unit-of-production method to amortize our oil and gas properties. This method requires us to amortize the capitalized costs incurred in developing a property in proportion to the amount of oil and gas produced as a percentage of the amount of proved reserves contained in the property. Accordingly, changes in reserve estimates as described above will cause corresponding changes in depletion expense recognized in periods subsequent to the reserve estimate revision. In all years presented, 100% of our reserves were prepared by independent petroleum engineers. Currently, we use Ryder Scott Company, L.P., DeGolyer and MacNaughton, Collarini Associates and RPS Energy. See the Supplemental Information (unaudited) in our consolidated financial statements for reserve data related to our properties.

We perform an impairment analysis whenever events or changes in circumstances indicate that an asset’s carrying amount may not be recoverable. 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 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 and actual or planned drilling or other development activities. For a property determined to be impaired, an impairment loss equal to the difference between the carrying value and the estimated fair value of the impaired property will be recognized. Fair value, on a depletable unit basis, is estimated to be the present value of the aforementioned expected future net cash flows. An impairment allowance is provided on an unproved property when we determine that the property will not be developed. 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 have significant obligations related to the plugging and abandonment of our oil and gas wells, dismantling our offshore production platforms, and the removal of equipment and facilities from leased

Index to Financial Statements

acreage and returning such land to its original condition. We estimate the future cost of this obligation, discounted to its present value, and record a corresponding asset and liability in our consolidated balance sheets. The values ultimately derived are based on many significant estimates, including the ultimate expected cost of the obligation, the expected future date of the required cash payment, and interest and inflation rates. Revisions to these estimates may be required based on changes to cost estimates, the timing of settlement, and changes in legal requirements. Any such changes that result in upward or downward revisions in the estimated obligation will result in an adjustment to the related capitalized asset and corresponding liability on a prospective basis. See Note 2 to the Consolidated Financial Statements.

In preparing financial statements at any point in time, management is periodically faced with uncertainties, the outcomes of which are not within its control and will not be known for prolonged periods of time. As discussed in Part I, Item 3. – “Legal Proceedings” and the Notes to Consolidated Financial Statements, we are involved in actions from time to time, which if determined adversely, could have a material negative impact on our financial position, results of operations and cash flows. Management, with the assistance of counsel makes estimates, if determinable, of ATP’s probable liabilities and records such amounts in the consolidated financial statements. Such estimates may be the minimum amount of a range of probable loss when no single best estimate is determinable. Disclosure is made, when determinable, of any additional possible amount of loss on these claims, or if such estimate cannot be made, that fact is disclosed. Along with our counsel, we monitor developments related to these legal matters and, when appropriate, we make adjustments to recorded liabilities to reflect current facts and circumstances. Although it is difficult to predict the ultimate outcome of these matters, management is not aware of any amounts that need to be recorded and believes that the recorded amounts, if any, are reasonable.

We periodically enter into commodity derivative contracts and fixed-price physical contracts to manage our exposure to oil and natural gas price volatility. We primarily utilize fixed price physical contracts, price swaps and put options, which are generally placed with major financial institutions or with counterparties of high credit quality that we believe are minimal credit risks. The oil and natural gas reference prices of these commodity derivatives contracts are based upon oil and natural gas, which have a high degree of historical correlation with actual prices we receive. All derivative instruments, unless designated as normal purchases and sales, are recorded on the balance sheet at fair value. Changes in the derivative’s fair value are recognized currently in earnings unless specific hedge accounting criteria are met. For qualifying cash flow hedges, the gain or loss on the derivative is deferred in accumulated other comprehensive income (loss) to the extent the hedge is effective. For qualifying fair value hedges, the gain or loss on the derivative is offset by related results of the hedged item in the income statement. Gains and losses on hedging instruments included in accumulated other comprehensive income (loss) are reclassified to oil and natural gas sales revenue in the period that the related production is delivered. Derivative contracts that do not qualify for hedge accounting treatment are recorded as derivative assets and liabilities at market value in the consolidated balance sheet, and the associated unrealized gains and losses are recorded in oil and natural gas revenues. As of December 31, 2006, we had five derivative contracts in place that qualified as cash flow hedges and thirty-four gas and oil fixed price futures contracts designated as normal sales contracts.

In determining whether a valuation allowance is appropriate, we weigh positive and negative evidence that suggests whether a deferred tax asset is likely to be recoverable. We have incurred net operating losses in a number of 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 onto production and development cost overruns in 2003 were

Index to Financial Statements

also significant factors considered in evaluating our deferred tax asset valuation allowance. Accordingly, we established a valuation allowance of $33.6 million as of December 31, 2003. We achieved profitable operations in 2004; however the income generated in 2004 was not sufficient to overcome the negative evidence noted in the prior years. During 2005, we incurred a net loss before income taxes of $2.6 million, and in 2006 we recorded income before income taxes of $25.7 million. See Note 10 “Income Taxes” to the Consolidated Financial Statements.

Effective January 1, 2006, we adopted Statement of Financial Accounting Standards (“SFAS”) No. 123(R), “Accounting for Share-Based Payment,” as amended, using the modified prospective transition method which requires, among other things, current recognition of compensation expense for share-based compensation granted after January 1, 2006, and for that portion of prior period share-based compensation for which the requisite service has not been rendered that was outstanding as of January 1, 2006. For periods prior to January 1, 2006, we applied to our stock-based compensation awards the intrinsic method of accounting as set forth in Accounting Principles Board (“APB”) Opinion No. 25, “Accounting for Stock Issued to Employees,” and related interpretations.

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

Our revenues, profitability and future growth depend substantially on prevailing prices for oil and natural gas. Prices also affect the amount of cash flow available for capital expenditures and our ability to borrow and raise additional capital. The amount we can borrow under our term loan is subject to periodic re-determination based in part on changing expectations of future prices. Lower prices may also reduce the amount of oil and natural gas that we can economically produce. We currently sell a portion of our oil and natural gas production under price sensitive or market price contracts. We periodically use derivative instruments to hedge our commodity price risk. We hedge a portion of our projected oil and natural gas production through a variety of financial and physical arrangements intended to support oil and natural gas prices at targeted levels and to manage our exposure to price fluctuations. We may use futures contracts, swaps, put options and fixed price physical contracts to hedge our commodity prices. Realized gains and losses from our price risk management activities are recognized in oil and gas sales when the associated production occurs. For derivatives designated as cash flow hedges, the unrecognized gains and losses are included as a component of other comprehensive income (loss) to the extent the hedge is effective. See Note 12 to the Consolidated Financial Statements for additional information. We do not hold or issue derivative instruments for trading purposes.

Index to Financial Statements

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

The information required here is included in the report as set forth in the “Index to the Consolidated Financial Statements” beginning on page F-1.

Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure.

In order to ensure that the information we must disclose in our filings with the Securities and Exchange Commission is recorded, processed, summarized, and reported on a timely basis, we have formalized our disclosure controls and procedures. Our principal executive officer and principal financial officer have reviewed and evaluated the effectiveness of our disclosure controls and procedures, as defined in Exchange Act Rules 13a-15(e) and 15d-15(e), as of December 31, 2006. Based on such evaluation, such officers have concluded that, as of December 31, 2006, our disclosure controls and procedures were effective in timely alerting them to material information relating to us (and our consolidated subsidiaries) required to be included in our periodic SEC filings. There has been no change in our internal control over financial reporting during the quarter ended December 31, 2006 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

Management of ATP Oil & Gas Corporation (the “Company”) is responsible for establishing and maintaining adequate internal control over financial reporting for the Company, as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934. Under the supervision and with the participation of the Company’s management, including our principal executive and principal financial officers, the Company conducted an evaluation of the effectiveness of its internal control over financial reporting based on the framework in “Internal Control—Integrated Framework” issued by the Committee of Sponsoring Organizations of the Treadway Commission (the “COSO Framework”). Based on this evaluation under the COSO Framework which was completed on February 28, 2006, management concluded that its internal control over financial reporting was effective as of December 31, 2006.

Management’s assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2006 has been audited by the independent registered public accounting firm who audited the Company’s consolidated financial statements as of and for the year ended December 31, 2006, as stated in their report which is included herein.

Index to Financial Statements

Set forth below are the names, ages (as of February 28, 2007) and titles of the persons currently serving as executive officers of the Company. All executive officers hold office until their successors are elected and qualified.

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

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

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

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

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.

Index to Financial Statements

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

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

Except for the information relating to Executive Officers of the Registrant set forth above, the information required by Item 10 of Form 10-K is incorporated herein by reference to the definitive proxy statement for the Company’s Annual Meeting of Shareholders to be held on June 8, 2007 (the “Proxy Statement.”)

We have adopted a Code of Business Conduct and Ethics that applies to all of our employees, officers and directors, including our principal executive officer, principal financial officer, principal accounting officer and controller, and it is available on our internet website at www.atpog.com. In the event that an amendment to, or a waiver from, a provision of our Code of Business Conduct and Ethics that applies to any of the executive officers (including the principal executive officer, principal financial officer, principal accounting officer and controller) or directors is necessary, we intend to post such information on our website.

The information required by Item 11 of Form 10-K is incorporated by reference to the Company’s Proxy Statement.

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.

The information required by Item 12 of Form 10-K is incorporated herein by reference to the Company’s Proxy Statement.

Item 13. Certain Relationships and Related Transactions, and Director Independence.

The information required by Item 13 of Form 10-K is incorporated herein by reference to the Company’s Proxy Statement.

The information required by Item 14 of Form 10-K is incorporated by reference to the Company’s Proxy Statement.

Index to Financial Statements

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.


ATP OIL & GAS CORPORATION

By:		/S/ ALBERT L. REESE, JR.
		Albert L. Reese, Jr. Chief Financial Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the registrant in the capacities indicated on March 1, 2007.

Index to Financial Statements

All other financial statement schedules have been omitted because they are not applicable or the required information is presented in the financial statements or the notes to consolidated financial statements.

Index to Financial Statements

We have audited the accompanying consolidated balance sheets of ATP Oil & Gas Corporation and subsidiaries (the “Company”) as of December 31, 2006 and 2005, and the related consolidated statements of operations, shareholders’ equity, comprehensive income (loss), and cash flows for each of the three years in the period ended December 31, 2006. Our audits also included the financial statement schedule listed in the index at Item 15. We also have audited management’s assessment, included in Management’s Report on Internal Control Over Financial Reporting, that the Company maintained effective internal control over financial reporting as of December 31, 2006, based on criteria established in “Internal Control-Integrated Framework” issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for these financial statements and financial statement schedule, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on these financial statements and financial statement schedule, an opinion on management’s assessment, and an opinion on the effectiveness of the Company’s internal control over financial reporting based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audit of financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Index to Financial Statements

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of ATP Oil & Gas Corporation and subsidiaries as of December 31, 2006 and 2005, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2006, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein. Also, in our opinion, management’s assessment that the Company maintained effective internal control over financial reporting as of December 31, 2006, is fairly stated, in all material respects, based on the criteria established in “Internal Control-Integrated Framework” issued by the Committee of Sponsoring Organizations of the Treadway Commission. Furthermore, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2006, based on the criteria established in “Internal Control-Integrated Framework” issued by the Committee of Sponsoring Organizations of the Treadway Commission.

As discussed in Note 2 to the consolidated financial statements, on January 1, 2006, the Company adopted Statement of Financial Accounting Standards No. 123(R), “Share-Based Payment.”

Index to Financial Statements

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

The consolidated financial statements include our accounts and our wholly-owned subsidiaries, ATP Energy, Inc. (“ATP Energy”), ATP Oil & Gas (UK) Limited, or “ATP (UK),” and ATP Oil & Gas Netherlands (B.V.). All intercompany transactions are eliminated upon consolidation. Certain prior year amounts have been reclassified to conform to the current year presentation.

The preparation of financial statements in accordance with generally accepted accounting principles and pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”) requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and disclosure of contingent assets and liabilities in the financial statements, including the use of estimates for oil and gas reserve information and the valuation allowance for deferred income taxes. Actual results could differ from those estimates.

Cash and cash equivalents primarily consist of cash on deposit and investments in money market funds with original maturities of three months or less, stated at market value.

Index to Financial Statements

incurred; renewals and betterments are capitalized. The costs and related accumulated depreciation, depletion, and amortization of properties sold or otherwise retired are eliminated from the accounts, and gains or losses on disposition are reflected in the statements of operations.

We perform a review for impairment of proved oil and gas properties 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 engineer’s estimate of proved reserves. In addition, other factors such as probable and possible reserves are taken into consideration when justified by economic conditions and actual or planned drilling or other development activities. For a property determined to be impaired, an impairment loss equal to the difference between the carrying value and the estimated fair value of the impaired property will be recognized. Restoration of a previously recognized impairment loss is prohibited. Fair value, on a depletable unit basis, 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’ reserves, future cash flows and fair value. We recorded impairments during the year ended December 31, 2006 totaling $18.5 million on certain proved properties, primarily due to lower than projected oil and natural gas prices, unfavorable operating performance or downward revisions of recoverable reserves or a combination of all of these factors, and no impairments during 2005 and 2004.

We recognize liabilities associated with the eventual retirement of tangible long-lived assets, upon the acquisition, construction and development of the assets, whenever law or regulation will eventually require that we abandon those assets. We record the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of the related long-lived asset.

Until all such assets are ultimately sold or abandoned, we will recognize (i) depletion expense on the additional capitalized costs; (ii) accretion expense as the present value of the future asset retirement obligation increases with the passage of time, and; (iii) the impact, if any, of changes in estimates of the liability. The following table sets forth a reconciliation of the beginning and ending asset retirement obligation for the periods ended December 31, 2006, 2005 and 2004 (in thousands):

Index to Financial Statements

Interest costs during the development phase of certain long-term assets are capitalized and amortized over the related assets’ estimated useful lives. No interest was capitalized during 2006, 2005 or 2004.

Furniture and fixtures consists of office furniture, computer hardware and software and leasehold improvements. Depreciation of furniture and fixtures is computed using the straight-line method over their estimated useful lives, which vary from three to five years.

Costs incurred in connection with the issuance of long-term debt are capitalized and amortized to interest expense over the term of the related agreement, using the effective interest method.

Environmental liabilities are recognized when the expenditures are considered probable and can be reasonably estimated. Measurement of liabilities is based on currently enacted laws and regulations, existing technology and undiscounted site-specific costs. Generally, such recognition would coincide with a commitment to a formal plan of action.

We use the sales method of accounting for oil and natural gas revenues. Under this method, revenues are recognized based on actual volumes of gas and oil sold to purchasers. The volumes sold may differ from the volumes to which we are entitled based on our interests in the properties. Differences between volumes sold and entitled volumes create oil and gas imbalances which are generally reflected as adjustments to reported proved oil and gas reserves and future cash flows in our supplemental oil and gas disclosures. If our excess takes of natural gas or oil exceed our estimated remaining proved reserves for a property, a natural gas or oil imbalance liability is recorded in the consolidated balance sheet.

We extend credit, primarily in the form of uncollateralized oil and gas sales and joint interest owners’ receivables, to various companies in the oil and gas industry, which results in a concentration of credit risk. The concentration of credit risk may be affected by changes in economic or other conditions within our industry and may accordingly impact our overall credit risk. However, we believe that the risk of these unsecured receivables is mitigated by the size, reputation, and nature of the companies to which we extend credit.

We sell a portion of our oil and gas to end users through various gas marketing companies. For the year ended December 31, 2006, revenues from two purchasers accounted for 43% and 32%, respectively, of oil and gas production revenues. For the year ended December 31, 2005, revenues from three purchasers accounted for 48%, 14% and 12%, respectively, of oil and gas production revenues. For the year ended December 31, 2004, revenues from four purchasers accounted for 35%, 21%, 17% and 15%, respectively, of oil and gas production revenues. Percentages are calculated on oil and gas revenues before any effects of price risk management activities.

The local currency is the functional currency for our foreign subsidiaries, and as such, assets and liabilities are translated into U.S. dollars at year-end exchange rates. Income and expense items are translated at average exchange rates during the year. The gains or losses resulting from such translations are deferred and included in accumulated other comprehensive income as a separate component of shareholders’ equity. Also included in income are gains and losses arising from transactions denominated in a currency other than the functional

Index to Financial Statements

currency of a particular entity. At December 31, 2006, accumulated other comprehensive income included $27.4 million of gain related to cumulative foreign currency translation adjustments.

Income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences or benefits attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases and operating loss and tax credit carry forwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes that enactment date.

Comprehensive income (loss) is net income or loss, plus certain other items that are recorded directly to shareholders’ equity. In 2006, comprehensive income was $37.6 million. In 2005, comprehensive loss was $13.6 million. In 2004, comprehensive income was $4.5 million.

Effective January 1, 2006, we adopted Statement of Financial Accounting Standards (“SFAS”) No. 123(R), “Accounting for Share-Based Payment,” as amended, using the modified prospective transition method which requires, among other things, current recognition of compensation expense for share-based compensation granted after January 1, 2006, and for that portion of prior period share-based compensation for which the requisite service has not been rendered that was outstanding as of January 1, 2006. During the years ended December 31, 2006, 2005 and 2004, we recognized aggregate compensation expense of $1.8 million, $0 and $0, respectively, related to outstanding common stock options. During the years ended December 31, 2006, 2005 and 2004, we recognized aggregate compensation expense of $9.6 million, $0 million and $0, respectively, related to outstanding restricted stock grants.

For periods prior to January 1, 2006, we applied to our stock-based compensation awards the intrinsic method of accounting as set forth in Accounting Principles Board (“APB”) Opinion No. 25, “Accounting for Stock Issued to Employees,” and related interpretations. The following table illustrates the effect on net income (loss) and earnings per share if we had applied the fair value recognition provisions of SFAS 123(R), as amended, to stock-based employee compensation during 2005 and 2004 (in thousands, except for per-share data):

For cash and cash equivalents, receivables and payables, the carrying amounts approximate fair value because of the short maturity of these instruments. Bank debt is variable rate debt and as such, approximates fair values, as interest rates are variable based on prevailing market rates.

From time to time, we utilize fixed price forward gas and oil sales contracts, options, swaps and collars to manage our commodity price risk. Our fixed price forward gas and oil sales contracts are designated normal sales under Statement of Financial Accounting Standards (“SFAS”) No. 133, “Accounting for Derivative

Index to Financial Statements

Instruments and Hedging Activities” (“SFAS No. 133”), as amended. SFAS No. 133 requires that all derivative instruments subject to the requirements of the statement be measured at fair value and recognized as assets or liabilities in the balance sheet. The accounting for changes in the fair value of a derivative depends on the intended use of the derivative and the resulting designation is generally established at the inception of a derivative. For derivatives designated as cash flow hedges and meeting the effectiveness guidelines of SFAS 133, changes in fair value, to the extent effective, are recognized in other comprehensive income (loss) until the hedged item is recognized in earnings. Hedge effectiveness is measured at least quarterly based on the relative changes in fair value between the derivative contract and the hedged item over time, or in the case of options based on the change in intrinsic value. Any change in fair value of a derivative resulting from ineffectiveness or an excluded component of the gain or loss, such as time value for option contracts, is recognized immediately in earnings. For a derivative that does not qualify as a hedge, changes in fair value will be recognized in earnings.

During February 2007, the Financial Accounting Standards Board (“FASB”) issued FASB Statement of Accounting Standards (“SFAS”) No 159, “The Fair Value Option for Financial Assets and Financial Liabilities” (“SFAS No. 159”) which permits all entities to choose, at specified election dates, to measure eligible items at fair value. SFAS No. 159 permits entities to choose to measure many financial instruments and certain other items at fair value that are not currently required to be measured at fair value, and thereby mitigate volatility in reported earnings caused by measuring related assets and liabilities differently without having to apply complex hedge accounting provisions. This Statement also establishes presentation and disclosure requirements designed to facilitate comparisons between entities that choose different measurement attributes for similar types of assets and liabilities. SFAS No. 159 is effective as of the beginning of an entity’s first fiscal year that begins after November 15, 2007. We are evaluating the impact that this Statement will have on our financial statements.

During September 2006, the Securities and Exchange Commission (“SEC”) issued Staff Accounting Bulletin (“SAB”) No. 108. This Bulletin provides the Staff’s views on the consideration of the effects of prior year misstatements in quantifying current year misstatements for the purpose of a materiality assessment. The guidance in SAB No. 108 is effective for financial statements of fiscal years ending after November 15, 2006. Adoption of this guidance did not materially impact our financial statements.

During September 2006, the Financial Accounting Standards Board (“FASB”) issued FASB Statement of Accounting Standards (“SFAS”) No. 157. This Statement defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles, and expands disclosures about fair value measurements. This Statement applies under other accounting pronouncements that require or permit fair value measurements, where fair value has been determined to be the relevant measurement attribute. This statement is effective for financial statements of fiscal years beginning after November 15, 2007. Adoption of this guidance did not materially impact our financial statements.

In June 2006, the FASB issued Interpretation No. 48, “Accounting for Uncertainty in Income Taxes-an Interpretation of FASB Statement No. 109,” (“FIN 48”) which provides guidance for the recognition and measurement of a tax position taken or expected to be taken in a tax return. FIN 48 requires the evaluation of a tax position as a two-step process. First, we will be required to determine whether it is more likely than not that a tax position will be sustained upon examination, including resolution of any related appeals or litigation processes, based on the technical merits of the position. If the tax position meets the “more likely than not” recognition threshold, it is then measured and recorded at the largest amount of benefit that is greater than 50 percent likely of being realized upon ultimate settlement. We will be required to adopt FIN 48 in the first quarter of 2007. We are evaluating our tax positions and the impact that this guidance will have on our financial statements.

During November 2005, the FASB issued Staff Position (“FSP”) No. FAS 123(R)-3, “Transition Election Related to Accounting for the Tax Effects of Share-Based Payment Awards,” which provided a practical

Index to Financial Statements

transition election related to accounting for the tax effects of share-based payment awards to employees as an alternative to the method set forth in paragraph 81 of Statement of Financial Accounting Standards (“SFAS”) No. 123(R). An entity that adopts SFAS No. 123(R) using either the modified retrospective or the modified prospective application may make a one-time election to adopt the transition methodology described in this FSP up to one year after the later of its adoption of SFAS 123(R) or the effective date of this FSP. The Company adopted SFAS 123(R) and related guidance on January 1, 2006 for its outstanding unvested awards as well as for awards granted, modified, repurchased or canceled on or after that date. We have determined that we will not make the one-time election allowed by this FSP.

During October 2005, the FASB issued FSP No. FAS 123(R)-2, “Practical Accommodation to the Application of Grant Date as Defined in FASB Statement No. 123(R),” which clarifies the notion of “mutual understanding” required under SFAS No. 123 to establish the grant date of a common stock award. We adopted this guidance upon implementation of SFAS No. 123(R) on January 1, 2006 and it did not have a material impact on our consolidated financial position, results of operations or cash flows.

During August 2005, the FASB issued FSP No. FAS 123(R)-1, “Classification and Measurement of Freestanding Financial Instruments Originally Issued in Exchange for Employee Services under FASB Statement No. 123R.” This guidance defers at this time the requirement of SFAS No. 123(R) that a freestanding financial instrument originally subject to SFAS 123(R) becomes subject to the recognition and measurement requirements of other applicable generally acceptable accounting principles (“GAAP”) when the rights conveyed by the instrument to the holder are no longer dependent on the holder being an employee of the entity. We adopted this guidance upon implementation of SFAS No. 123(R) on January 1, 2006 and it did not have a material impact on our consolidated financial position, results of operations or cash flows.

During April 2005, the FASB issued FSP No. FAS 19-1, “Accounting for Suspended Well Costs.” FSP No. 19-1 amends SFAS No. 19, “Financial Accounting and Reporting by Oil and Gas Producing Companies,” to allow continued capitalization of exploratory well costs beyond one year from the date drilling was completed under circumstances where the well has found a sufficient quantity of reserves to justify its completion as a producing well and the enterprise is making sufficient progress assessing the reserves and the economic and operating viability of the project. FSP No. 19-1 also amends SFAS No. 19 to require enhanced disclosures of suspended exploratory well costs in the notes to the financial statements for annual and interim periods when there has been a significant change from the previous disclosure. Adoption of this guidance did not have a material impact on our consolidated financial position, results of operations or cash flows.

During March 2005, FASB issued Interpretation (“FIN”) No. 47, “Accounting for Conditional Asset Retirement Obligations,” which clarifies that an entity is required to recognize a liability for the fair value of a conditional asset retirement obligation when the obligation is incurred—generally upon acquisition, construction, or development and/or through the normal operation of the asset, if the fair value of the liability can be reasonably estimated. A conditional asset retirement obligation is a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. Uncertainty about the timing and/or method of settlement is required to be factored into the measurement of the liability when sufficient information exists. We adopted FIN No. 47 on December 31, 2005 and it did not have a material impact on our consolidated financial position, results of operations or cash flows.

During March 2005, the SEC issued Staff Accounting Bulletin (“SAB”) No. 107 to express the views of the staff regarding the interaction between SFAS 123(R) and certain SEC rules and regulations and to provide the staff’s views regarding the valuation of share-based payment arrangements for public companies, including assumptions such as expected volatility and expected term. We adopted this guidance upon implementation of SFAS No. 123(R) on January 1, 2006 and it did not have a material impact on our consolidated financial position, results of operations or cash flows.

Index to Financial Statements

We closed three separate purchase transactions for minerals in-place during 2006. These purchases totaled $30.0 million in acquisition costs. Additionally, we acquired three blocks for $4.3 million at the Gulf of Mexico Offshore Lease Sales held in 2006. We hold a 100% working interest and serve as operator of each of the blocks.

During the second and third quarter of 2006, we acquired in two separate transactions a 100% working interest in Mississippi Canyon Blocks 941, 942 and Atwater Valley Block 63, collectively called the Telemark Hub. As of December 31, 2006, we had begun engineering and construction of a floating drilling and production facility for the Telemark Hub which is expected to be installed in mid-2008. Costs incurred, excluding acquisition costs, during 2006 at the Telemark Hub were approximately $11.0 million. We serve as operator of each of the blocks.

At Ship Shoal 351, we increased our ownership from 50% to 100% in exchange for the assumption of future abandonment liability. At December 31, 2006, we were installing a platform at Ship Shoal 351 and in February 2007 we began drilling the first of at least two planned wells. We hold a 100% working interest and serve as operator at Ship Shoal 351.

During March 2005, ATP was the apparent high bidder and was subsequently awarded seven blocks relating to its winning bids totaling $2.4 million at the Central Gulf of Mexico Offshore Lease Sale. ATP owns a 100% working interest in and is the operator of all seven blocks. Two of the blocks are adjacent to the Company’s wholly-owned Mississippi Canyon 711 development. Two additional blocks are contiguous to an existing ATP operated development in the West Cameron area and the remaining three blocks provide for new development area opportunities. Also, in the second quarter of 2005, ATP acquired 100% of the working interest in South Marsh Island 166.

During September 2005, ATP acquired a 55% working interest in four Federal oil and gas leases covering Mississippi Canyon Blocks 173/217 and Desoto Canyon Blocks 133/177, offshore Gulf of Mexico, in an oil and gas discovery area named “King’s Peak.” The acquisition also included a 19.25% working interest in the Canyon Express Pipeline System. The final adjusted purchase price for this acquisition was $16.9 million.

During October 2005, ATP was awarded two blocks relating to its winning bids at the Western Gulf of Mexico Offshore Lease Sale held in New Orleans during August 2005. During December 2005 the Minerals Management Service awarded a third block to the Company on which it was the apparent high bidder. We are the operator and have a 100% working interest in the blocks, Garden Banks 228, High Island A-391 and High Island A-589, which were awarded at a total cost of approximately $2.9 million dollars.

Also during October 2005, we acquired substantially all of the oil and gas assets of a privately held company, consisting of 19 blocks located on the Gulf of Mexico Outer Continental Shelf in less than 600 feet of water. The reserves are approximately 80% gas and 20% oil. The adjusted purchase price was $37.2 million

Index to Financial Statements

in cash, plus net liabilities assumed totaling an estimated $31.4 million for future property abandonment operations. The purchase price was allocated $68.1 million to proved oil and gas property, and $0.5 million to unproved property.

During the fourth quarter of 2006, ATP (UK) acquired a 100% working interest in Block 49/12b in the Southern Gas Basin of the U.K. North Sea. Block 49/12b is an exploratory opportunity offsetting our Wenlock development. Wenlock is located in 75 feet of water and has two vertical wells that have tested at rates of 35 MMcf per day and 74 MMcf per day.

During June 2005, we increased our ownership in the Tors fields (Garrow and Kilmar) in the Southern Gas Basin of the U.K. North Sea to 100% by acquiring the remaining 25% interest pursuant to an agreement with our partner. The Secretary of State for Trade and Industry gave approval for ATP (UK) to own a 100% interest in the Tors fields and to act as the sole development and production operator. Subsequently, in December 2005, ATP (UK) sold 15% of its working interest in the Tors fields.

During December 2005, we announced that we had increased our ownership to 100% in the Wenlock (formerly Venture) field (Block 49/12a North) in the Southern Gas Basin of the U.K. North Sea. ATP (UK) acquired the 50% working interest owned by our partner pursuant to a Sale and Purchase Agreement. Control of this property will allow ATP to proceed with the field development plan approval process.

ATP (UK) recorded net acquisition costs of $7.0 million related to its 2005 acquisitions.

Index to Financial Statements

$27.9 million related to the capitalized costs of the Previous First Lien Credit Agreement and approximately $9.3 million of costs related to calling and retiring all of the preferred shares.

The terms of the Term Loans and the Revolver require us to maintain certain covenants. As of December 31, 2006, we were in compliance with all of the financial covenants of our Term Loans.

At December 31, 2005, we had $347.4 million outstanding on our Senior Secured First Lien Term Loan Facility (“Term Loan”). The Term Loan was to mature in April 2010 and was secured by substantially all of our oil and gas assets in the Gulf of Mexico and the U.K. Sector North Sea and was guaranteed by our wholly owned subsidiaries ATP Energy, Inc. and ATP (UK). The Term Loan bore interest at the base rate plus a margin of 4.50% or LIBOR plus a margin of 5.50% at the election of ATP. At December 31, 2005, the weighted average rate on outstanding borrowings was approximately 10.06%.

In connection with the original issuance of the term loans during 2004, we granted warrants to purchase 2,452,336 shares of common stock of ATP for $7.25 per share, 525,499 of which remain outstanding at December 31, 2006. The warrants have a term of six years and expire in March 2010. The fair value of the warrants, as determined by use of the Black-Scholes valuation model on March 29, 2004, was approximately $4.2 million and was accounted for as additional paid-in-capital and debt discount. The fair value was calculated with the following weighted-average assumptions: zero dividend yield; risk-free interest rate of 3.0%; volatility of 51.6% and an expected life of 6 years. The value was adjusted for liquidity issues associated with a potential sale of such a large volume of shares in relation to our public float. This amount and the unamortized portion of the original issue discount of $5.6 million were written off in connection with the Amendment.

During October 2005, we agreed to acquire the Rowan Midland mobile offshore drilling unit (“Vessel”) from Rowandrill, Inc. for modification for use as a floating offshore production unit at our Mississippi Canyon 711 development. The Vessel was subsequently renamed the ATP Innovator. The net purchase price of $46.7 million, including certain prepayment credits, was payable over the succeeding 15-month period. We paid $1.7 million toward this lease in 2005, $21.0 million in 2006 and the remaining balance of $24.0 on January 31, 2007. At its inception, the company recorded this transaction as a capital lease and recorded an oil and gas asset and corresponding capital lease obligation in the amount of $44.8 million.

We have commitments under an operating lease agreement for office space and various leases for office equipment. Total rent expense for the years ended December 31, 2006, 2005 and 2004 was approximately $0.7 million, $0.6 million and $0.7 million, respectively. At December 31, 2006, the future minimum rental payments due under operating leases are as follows (in thousands):

Index to Financial Statements

On August 2, 2005, ATP entered into a Subscription Agreement for the private placement of 175,000 shares of its 13.5% Series A cumulative perpetual preferred stock, par value, $0.001 per share (the “Series A Preferred Stock”), at a price of $1,000.00 per share. The Series A Preferred Stock was redeemed in its entirety with the proceeds of additional Term Loans, as discussed in Note 6. The Series A Preferred Stock was not convertible into the Company’s common stock. Aggregate gross proceeds to the Company were $175.0 million and the Company paid $5.25 million in placement agent commissions. The issuance of the Series A Preferred Stock was exempt from the registration requirements of the Securities Act of 1933, as amended, and was offered and issued only to institutional accredited investors.

The Statement of Resolutions establishing the Series A Preferred Stock provided for: (1) an initial liquidation preference of $1,000.00 per share; (2) cumulative quarterly dividends at an initial rate of 13.5%, subject to escalation in the applicable dividend rate under certain conditions; (3) no voting rights (except as required by law or after the occurrence of various extraordinary events); (4) special provisions in the event of a Fundamental Change (as defined in the Statement of Resolutions) in the Company or the satisfaction of the Company’s currently outstanding debt; (5) limitations on incurrence of additional debt; and (6) restrictions on transfer or sale of the Series A Preferred Stock.

The Company had the right to redeem the Series A Preferred Stock at its option at any time after a Fundamental Change or the later of February 3, 2006 or the specified debt satisfaction date at a premium that declined until February 3, 2009, at which time the Series A Preferred Stock could be redeemed at 100% of the liquidation preference plus accrued and unpaid dividends.

In the event of a Fundamental Change in the Company or the repayment of the then outstanding debt, the Company was required to notify the preferred stockholders whether it intended to offer to redeem the Series A Preferred Stock. If the Company chose not to offer to redeem the Series A Preferred Stock, then it was to be deemed a Fundamental Change offer default or a debt satisfaction offer default, as the case may be, and the applicable dividend rate was to escalate by 5% per quarter, to a maximum of 25%. Such escalation was to continue until either of such defaults was cured, unless the Company had previously exercised its optional redemption right with respect to all of the shares of Series A Preferred Stock then outstanding. The Company was under no obligation to offer to redeem the Series A Preferred Stock under any circumstances, but chose to redeem the Series A Preferred Stock and accrued dividends with the proceeds of additional Term Loans as described in Note 6.

On March 20, 2006, ATP entered into a Subscription Agreement for the private placement of 150,000 shares of its 12.5% Series B cumulative perpetual preferred stock, par value, $0.001 per share (the “Series B Preferred Stock”), at a price of $1,000.00 per share. The Series B Preferred Stock was redeemed in its entirety with the proceeds of additional Term Loans, as discussed in Note 6. The Series B Preferred Stock was not convertible into the Company’s common stock. Aggregate gross proceeds to the Company were $150.0 million and the Company paid $4.5 million in placement agent commissions. The issuance of the Series B Preferred Stock was exempt from the registration requirements of the Securities Act of 1933, as amended, and was offered and issued only to institutional accredited investors.

Index to Financial Statements

The Statement of Resolutions establishing the Series B Preferred Stock provided for: (1) an initial liquidation preference of $1,000.00 per share; (2) cumulative quarterly dividends at an initial annual rate of 12.5%, subject to escalation in the applicable annual dividend rate under certain conditions; (3) no voting rights (except as required by law or after the occurrence of various extraordinary events); (4) special provisions in the event of a Fundamental Change in the Company or the satisfaction of the Company’s currently outstanding debt; (5) limitations on incurrence of additional debt; and (6) restrictions on transfer or sale of the Preferred Stock.

The Company had the right to redeem the Series B Preferred Stock at its option at any time at a premium that declined until February 3, 2009, at which time the preferred stock could be redeemed at 100% of the liquidation preference plus accrued and unpaid dividends.

In the event of a Fundamental Change in the Company or the repayment of the then outstanding debt, the Company was required to notify the preferred stockholders whether it intended to offer to redeem the Series B Preferred Stock. If the Company chose not to offer to redeem the Series B Preferred Stock, then it was to be deemed a Fundamental Change offer default or a debt satisfaction offer default, as the case may be, and the applicable dividend rate was to escalate by 5% per quarter, to a maximum of 25%. Such escalation was to continue until either of such defaults was cured, unless the Company had previously exercised its optional redemption right with respect to all of the shares of Series B Preferred Stock then outstanding. The Company was under no obligation to offer to redeem the Series B Preferred Stock under any circumstances, but chose to redeem the Series B Preferred Stock and accrued dividends with the proceeds of additional Term Loans as described in Note 6.

The Company’s preferred stock, par value $0.001 per share, consisted of the following (in thousands):

At December 31, 2006, we had 100,000,000 shares authorized, 30,272,210 shares issued, 30,196,370 shares outstanding and 75,840 shares in treasury. At December 31, 2005, we had 100,000,000 shares authorized, 29,688,517 shares issued, 29,592,677 shares outstanding and 75,840 shares in treasury.

At December 31, 2006 and 2005, there were 525,499 warrants outstanding to purchase common stock at $7.25, which expire in March 2010.

Index to Financial Statements

In December 1998, the Board of Directors approved the 1998 Stock Option Plan (the “1998 Plan”) to provide increased incentive for its employees and directors. The 1998 Plan authorized the granting of incentive and nonqualified options for up to 2,678,571 shares of common stock to eligible participants, and expired five years after the closing date of our IPO. One third of the options were exercisable on April 10, 2001 with each remaining third exercisable on the first and second anniversaries of the IPO. As of December 31, 2006, there are no remaining options outstanding under this plan.

In January 2001, the Board of Directors approved the 2000 Stock Option Plan (the “2000 Plan”) to provide increased incentive for its employees and directors. The 2000 Plan authorizes the granting of options and restricted stock awards for up to 4,000,000 shares of common stock. Generally, options are granted at prices equal to at least 100% of the fair value of the stock at the date of grant, expire not later than five years from the date of grant and vest ratably over a four-year period following the date of grant. From time to time, as approved by the Board of Directors, options with differing terms have also been granted. We recognized stock option compensation expense of approximately $1.8 million for the year ended December 31, 2006.

The fair values of options granted during the years ended December 31, 2006, 2005 and 2004 were estimated at the date of grant using a Black-Scholes option-pricing model assuming no dividends and with the following weighted average assumptions for grants during the periods indicated:

Volatilities are based on the historical volatility of our closing common stock price. Expected term of options granted is derived from output of the option valuation model and represents the period of time that options granted are expected to be outstanding. The risk-free rate for periods within the contractual life of the options is based on the comparable U.S. Treasury rates in effect at the time of each grant. The weighted average grant-date fair values of options granted during the years ended December 31, 2006, 2005 and 2004 were $16.21, $6.68 and $4.69, respectively. The aggregate intrinsic values of options exercised during the years ended December 31, 2006, 2005 and 2004 were $14.9 million, $11.9 million and $10.8 million, respectively. The following table sets forth a summary of option transactions for the year ended December 31, 2006:

Index to Financial Statements

A summary of the status of ATP’s nonvested stock options as of December 31, 2006 and changes during the year ended December 31, 2006 is presented below:

At December 31, 2006, unrecognized compensation expense related to nonvested stock option grants totaled $2.5 million. Such unrecognized expense will be recognized as vesting occurs over a weighted average period of 2.7 years.

On September 25, 2006, we granted 3,000 shares of restricted stock with a weighted average grant date fair value of $36.61 per share to an employee. On June 14, 2006, we granted 21,816 shares of restricted stock with a weighted average grant date fair value of $36.68 per share to our non-employee directors. Such restricted stock grants vest over a three-year period. On April 4, 2006, we granted 31,500 shares of restricted stock with a weighted average grant date fair value of $44.63 per share to our non-employee directors. Such restricted stock grants vest on January 15, 2007. On February 9, 2006, we granted 44,500 shares of restricted stock with a weighted average grant date fair value of $37.82 per share to employees. Such restricted stock grants vest over a three-year period. Each of the above restricted stock grants is subject to forfeiture, and cannot be sold, transferred or disposed of during the restriction period. The holders of the shares have voting and dividend rights with respect to such shares. We will recognize compensation expense over the vesting period of these shares. During the years ended December 31, 2006, 2005 and 2004, we recognized aggregate compensation expense of $9.6 million, $0 million and $0, respectively, related to outstanding restricted stock grants.

Index to Financial Statements

The following table sets forth the changes in nonvested restricted stock for the year ended December 31, 2006:

At December 31, 2006, unrecognized compensation expense related to restricted stock totaled $4.1 million. Such unrecognized expense will be recognized as vesting occurs over a weighted average period of 1.8 years.

We have a 401(k) Savings Plan which covers all domestic employees. At our discretion, we may match a certain percentage of the employees’ contributions to the plan. The matching percentage is currently 100% of the first 3% and 50% of the next 2% of each participant’s compensation. Our matching contributions to the plan were approximately $218,000, $190,000 and $157,000 for the years ended December 31, 2006, 2005 and 2004, respectively.

We also have a defined contribution plan for our U.K. employees. We currently contribute 4% to the plan and such contributions are subject to the Pensions Act 1999 (U.K.) and to U.K. rules on taxation. For the years ended December 31, 2006, 2005 and 2004, we contributed approximately $22,100, $20,300 and $20,200, respectively.

Basic earnings per share is computed by dividing net income or loss by the weighted average number of shares of common stock (other than unvested restricted stock) outstanding during the period. Diluted earnings per share are determined on the assumption that outstanding stock options and warrants have been converted using the average price for the period. For purposes of computing earnings per share in a loss year, potential common shares are excluded from the computation of weighted average common shares outstanding if their effect is antidilutive. In the table below, potential common stock equivalents of 709,000 and 1,086,000 have been excluded from the calculations for 2006 and 2005, respectively, because their effect would be antidilutive.

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

Index to Financial Statements

The reconciliation of income tax computed at the U.S. federal statutory tax rates to the provision for income taxes is as follows:

Significant components of our deferred tax assets (liabilities) as of December 31, 2006 and 2005 are as follows (in thousands):

Index to Financial Statements

We compute income taxes using an asset and liability approach which results in the recognition of deferred tax liabilities and assets for the expected future tax consequences of temporary differences between the carrying amounts and the tax basis of those assets and liabilities. We have recorded and continue to carry a valuation allowance to give effect to our judgment that it is more likely than not that some portion or all of our net U.S. deferred tax assets will not be realized at some point in the future. Relevant accounting guidance suggests that cumulative losses in recent years constitute significant negative evidence that such deferred tax assets are not recoverable, and that future expectations about income are overshadowed by such history of losses. As of December 31, 2006, we have a valuation allowance equal to the entire balance of our net U.S. deferred tax asset, and we have no valuation allowance recorded related to our foreign operations as a result of the taxable income generated by those entities.

Effective January 1, 2006, we adopted Statement of Financial Accounting Standards (“SFAS”) No. 123(R), “Accounting for Share-Based Payment,” as amended. The implementation guidance does not allow recognition of the excess tax benefit related to option exercises and vesting of restricted stock until realized by reducing current taxes payable. Accordingly, the deferred tax asset related to the U.S. net operating loss carry forwards as disclosed does not include an additional $15.9 million of net operating loss as we anticipate we will include this amount in our 2006 U. S. net operating loss carry forwards in relation to excess tax benefits on stock option exercises and restricted stock vested during the fiscal year ended December 31, 2006.

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 €7.4 million from the partner 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, 2005 and 2004, the U.S. recorded balance is reflected as a long-term liability of $8.8 million and $10.2 million, respectively, in the financial statements. The property was developed during 2005 and commenced production in February 2006. We reclassified this liability as a reduction to our basis in oil and gas properties in the first quarter of 2006 since our obligation under the agreement was fulfilled.

At the time of receipt, we determined the payment was not taxable at that time due to the obligation for substantial future performance. During a recent tax audit of our Dutch subsidiary, the tax authorities have concluded that receipt of the payment was a taxable event at the time of receipt and taxes and interest are currently due on this payment in the amount of approximately €3.4 million ($4.5 million). Accordingly, we have provided for this contingency and recorded a current liability in the amount of the taxes and interest. We recorded a deferred tax asset for this contingency, however we have not recorded a valuation allowance against this deferred tax asset as it resulted from a timing difference on the revenue recognition of the receipt of the payment. We do not agree with the position that has been asserted and, if necessary, we will defend our position vigorously.

At December 31, 2006 and 2005, we had net operating loss carry forwards (“NOLs”) for financial statement purposes of approximately $116.0 million and $132.2 million, respectively, which are available to offset future taxable income through 2026. ATP (UK) had NOL’s of $120.6 and $329.0 million available for corporate tax carry-back at December 31, 2006 and 2005 respectively which are presented in Foreign Operations above.

Hurricanes Rita and Katrina caused minimal direct damage to most of the Company’s platforms with some platforms, primarily in the Western Gulf, sustaining no damage. In addition, the company lost potential revenues due to shut-in production resulting from the storms. The company maintains property casualty

Index to Financial Statements

insurance for such physical damages and loss of production insurance to replace lost cash flows resulting from downtime in excess of ninety days after the event. The company has submitted claims for the insured damages and any recoveries available under the loss of production income (“LOPI”) insurance policy. At December 31, 2006, we had a receivable for expected recovery of repair costs incurred related to the 2005 storms in the amount of $12.1 million, net of $4.4 million already received through that date. Additionally, we recorded other revenues in the amount of $5.6 million realized under the LOPI insurance policy. We expect to receive additional amounts related to LOPI insurance; however no such amounts will be recorded to the financial statements until they are realized.

In 2001 we purchased three properties in the U.K. Sector—North Sea. In accordance with the purchase agreement, we also committed to pay future consideration contingent upon the successful development and operation of the properties. The contingent consideration for each property includes amounts to be paid upon achieving first commercial production and upon achieving designated cumulative production levels. The first threshold of initial commercial production was achieved in 2004 on one property and such related contingent consideration was paid and capitalized as acquisition costs. Upon achievement of the second threshold for the one property, the remaining contingent consideration will be accrued and capitalized at that time. Future development is planned on the other two properties and when they reach their respective thresholds, the appropriate consideration will be recorded.

During 2005, we purchased additional interest in the Tors property in the U.K. sector of the North Sea, and agreed to pay the seller contingent consideration of £2.0 million 180 days after first production, interest on such amount if the payment date meets certain criteria, a second contingent payment of £1.0 million after a cumulative 40 Bcf of production is achieved from the property, and a third contingent payment of £1.0 million after a cumulative 80 Bcf of production. As of December 31, 2006, we have paid the U.S dollar equivalent of the £2.0 million contingent liability due to the commencement of production at Tors.

During the fourth quarter of 2006, ATP (UK) acquired a 100% working interest in Block 49/12b in the Southern Gas Basin of the U.K. North Sea, which is an exploratory opportunity offsetting our Wenlock development. We agreed to pay the seller contingent consideration of £3.5 million after a cumulative 20 Bcf of production is achieved from the property.

We are, from time to time, a party to various legal proceedings in the ordinary course of business. Management does not believe that the outcome of these legal proceedings, individually, or in the aggregate will have a material adverse effect on our financial condition, results of operations or cash flows.

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

We occasionally use derivative instruments with respect to a portion of our oil and gas production to manage our exposure to price volatility. These instruments may take the form of futures contracts, swaps or options. A put option requires us to pay the counterparty the fair value of the option at the purchase date and receive from the counterparty the excess, if any, of the fixed floor price over the floating market price. The costs to purchase put options are amortized over the option period.

At December 31, 2006 and 2005, Accumulated Other Comprehensive Income (Loss) included $1.0 million and $1.3 million of unrealized losses on our cash flow hedges, respectively. Gains and losses are reclassified from Accumulated Other Comprehensive Income to the consolidated statement of operations as a component of oil and gas revenues in the period the hedged production occurs. If any ineffectiveness occurs, amounts are recorded directly to the consolidated statement of operations as a component of oil and gas revenues. All of this deferred loss will be reversed during the period in which the forecasted transactions actually occur.

Index to Financial Statements

At December 31, 2006, we had oil derivatives that qualified as cash flow hedges with respect to our future production as follows:

We also manage our exposure to oil and gas price risks by periodically entering into fixed-price delivery contracts. These physical contracts qualified and have been designated for the normal purchase and sale exemption under SFAS 133, as amended.

At December 31, 2006, we had fixed-price contracts in place for the following oil and gas volumes:

ATP Energy entered an agreement in December 1998 with American Citigas Company (“American Citigas”) to purchase gas over a ten-year period commencing January 1999. During December 2005, ATP and American Citigas entered into an agreement to terminate this transaction and the related gas purchase and sale obligations, as described below.

The original contract required an amount of 9,000 MMBtu per day of gas to be purchased for the first year and 5,000 MMBtu per day for years two through ten. The contract required ATP Energy to purchase on a monthly basis the gas at a premium of approximately $2.50 per MMBtu to the Gas Daily Henry Hub Index. American Citigas was required to reimburse ATP Energy on a monthly basis for a portion of the premium during the term of the contract. This portion of the reimbursement was accomplished by a note receivable in favor of ATP. The note receivable bore interest at 6% and had monthly payments of approximately $0.4 million until January 2009. The balance of the note receivable at December 31, 2004 was $16.4 million. At December 31, 2004, the present value of the remaining premium payments to be made by ATP Energy, using a discount rate of 6%, was $16.0 million. The note receivable and the premium payable to American Citigas have been offset in the consolidated financial statements in accordance with the prescribed accounting in FASB Interpretation No. 39, “Offsetting of Amounts Related to Certain Contracts.” The aggregate amount of premium payments expected to be paid by ATP Energy over the term of the contract was approximately $49.0 million and the aggregate amount of payments to be received by ATP Energy over the term of the note was approximately $45.0 million. ATP Energy sold to a third party an identical quantity of natural gas at the Gas Daily Henry Hub index price less $0.015.

ATP Energy received $6.0 million in connection with these transactions, of which $2.0 million was recorded as deferred revenue and $4.0 million was recorded as deferred obligations. The deferred revenue

Index to Financial Statements

amount of $2.0 million was a non-refundable fee received by ATP Energy and was recognized into income as earned over the life of the contract. At December 31, 2004, the deferred revenue amount was $0.7 million. The deferred obligation amount of $4.0 million represented the difference between the premium we agreed to pay for natural gas under the American Citigas contract and the obligation of American Citigas to partially reimburse us for such premium. The transaction was structured with American Citigas such that there was no financial impact to ATP Energy associated with the premium paid and reimbursement received other than the $2.0 million realized by ATP Energy. ATP Energy entered into the transactions to earn the fee for agreeing to market the volumes of natural gas specified in the American Citigas contract.

On December 30, 2005, ATP Energy and American Citigas entered into an agreement to terminate the original agreement. On January 25, 2006, ATP Energy paid to American Citigas $132,784 which was the approximate value of the premium to be paid to American Citigas in excess of the reimbursement obligation for the remainder of the contract. For 2005, ATP Energy recorded a net gain of $0.4 million upon the termination of the original agreement.

The Company’s operations are focused in the Gulf of Mexico and in the North Sea. Management reviews and evaluates the operations separately of its Gulf of Mexico segment and its North Sea segment. Each segment is an aggregation of operations subject to similar economic and regulatory conditions such that they are likely to have similar long-term prospects for financial performance. The operations of both segments include natural gas and liquid hydrocarbon production and sales. The accounting policies of the reportable segments are the same as those described in Note 2 to the Consolidated Financial Statements. The Company evaluates the segments based on income (loss) from operations. Segment activity for the years ended December 31, 2006, 2005 and 2004 is as follows (in thousands):

Index to Financial Statements

On January 8, 2007, we completed the acquisition of a 50% working interest in Mississippi Canyon (“MC”) Block 305 (“Aconcagua”), a 16.67% working interest in MC Block 348 (“Camden Hills”), and an additional 25.834% interest in the Canyon Express Pipeline Common System (“Canyon Express”). Aconcagua is currently producing approximately 10 MMcfe per day net to our interest and Camden Hills produced previously, but is currently shut-in. Both Aconcagua (located in 6,820’ of water) and Camden Hills (located in 7,112’ of water), along with MC 217 (“King’s Peak”) produce through Canyon Express, in which we now owns a 45.084% interest as a result of this acquisition.

We received net cash of $4.7 million at closing, which consisted of the net proceeds from production since July 1, 2006 of $5.7 million, partially offset by the $1.0 million acquisition price at July 1, 2006. We assumed certain abandonment costs in conjunction with this acquisition and accordingly recorded a $9.8 million abandonment liability. At closing, the Seller agreed to provide continuing operations for the properties on our behalf until March 31, 2007, at which time we will assume the operations.

Index to Financial Statements

The following table sets forth certain information with respect to costs incurred in connection with our oil and gas producing activities during the year ended December 31, 2006, 2005 and 2004 (in thousands):

Proved reserves are estimated quantities of oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are proved reserves that can reasonably be expected to be recovered through existing wells with existing equipment and operating methods.

In all years presented, 100% of our reserves were prepared by independent petroleum engineers. Currently we use Ryder Scott Company, L.P., DeGolyer and MacNaughton, Collarini Associates and RPS Energy.

Index to Financial Statements