10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-K

x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2007

or

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission file number: 000-32261

ATP Oil & Gas Corporation

(Exact name of registrant as specified in its charter)

Texas	76-0362774
(State of incorporation)	(I.R.S. Employer Identification No.)

4600 Post Oak Place, Suite 200

Houston, Texas 77027

(Address of principal executive offices) (Zip Code)

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

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

Title of each class	Name of exchange on which registered
Common Stock, par value $.001 per share	NASDAQ Global Select Market

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

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, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer  x    Accelerated filer  ¨    Non-accelerated filer  ¨    Smaller reporting company  ¨

(do not check if a smaller reporting company)

Indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes  ¨    No  x

The aggregate market value of the voting and non-voting common stock held by non-affiliates of the Registrant as of June 30, 2007 (the last business day of the Registrant’s most recently completed second fiscal quarter) was approximately $1.054 billion. The number of shares of the Registrant’s common stock outstanding as of February 22, 2008 was 35,798,009.

DOCUMENTS INCORPORATED BY REFERENCE

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, 2007, are incorporated by reference in Part III of this Form 10-K.

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

2007 FORM 10-K ANNUAL REPORT

TABLE OF CONTENTS

			Page
Part I
	Item 1.	Business	5
	Item 1A.	Risk Factors	14
	Item 1B.	Unresolved Staff Comments	22
	Item 2.	Properties	22
	Item 3.	Legal Proceedings	27
	Item 4.	Submission of Matters to a Vote of Security Holders	27
Part II
	Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	28
	Item 6.	Selected Financial Data	30
	Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	31
	Item 7A.	Quantitative and Qualitative Disclosures about Market Risk	46
	Item 8.	Financial Statements and Supplementary Data	47
	Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	47
	Item 9A.	Controls and Procedures	47
	Item 9A(T).	Controls and Procedures	48
	Item 9B.	Other Information	48
Part III
	Item 10.	Directors, Executive Officers and Corporate Governance	49
	Item 11.	Executive Compensation	50
	Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	50
	Item 13.	Certain Relationships and Related Transactions, and Director Independence	51
	Item 14.	Principal Accounting Fees and Services	51
Part IV
	Item 15.	Exhibits, Financial Statement Schedules	52

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Cautionary Statement About Forward-Looking Statements

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

This annual report includes assumptions, expectations, projections, intentions or beliefs about future events. These statements are intended as “forward-looking statements” under the Private Securities Litigation Reform Act of 1995, 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:

• projected operating or financial results;

• timing and expectations of financing activities;

• budgeted or projected capital expenditures;

• expectations regarding our planned expansions and the availability of acquisition opportunities;

• statements about the expected drilling of wells and other planned development activities;

• expectations regarding oil and natural gas markets in the United States, United Kingdom and the Netherlands; and

• estimates of quantities of our proved reserves and the present value thereof, and timing and amount of future production of oil and natural gas.

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:

• the volatility in oil and natural gas prices;

• the timing of planned capital expenditures;

• the timing of and our ability to obtain financing on acceptable terms;

• our ability to identify and acquire additional properties necessary to implement our business strategy and our ability to finance such acquisitions;

• the inherent uncertainties in estimating proved reserves and forecasting production results;

• operational factors affecting the commencement or maintenance of producing wells, including catastrophic weather related damage, unscheduled outages or repairs, or unanticipated changes in drilling equipment costs or rig availability;

• the condition of the capital markets generally, which will be affected by interest rates, foreign currency fluctuations and general economic conditions;

• cost and other effects of legal and administrative proceedings, settlements, investigations and claims, including environmental liabilities, which may not be covered by indemnity or insurance;

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• the political and economic climate in the foreign or domestic jurisdictions in which we conduct oil and gas operations, including risk of war or potential adverse results of military or terrorist actions in those areas; and

• other United States, United Kingdom or Netherlands regulatory or legislative developments, which may affect the demand for natural gas or oil, or generally increase the environmental compliance cost for our production wells or impose liabilities on the owners of such wells.

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CERTAIN DEFINITIONS

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

Bbls	Barrels of crude oil or other liquid hydrocarbons
Bcf	Billion cubic feet of natural gas
Bcfe	Billion cubic feet of natural gas equivalent
MBbls	Thousand barrels of crude oil or other liquid hydrocarbons
Mcf	Thousand cubic feet of natural gas
Mcfe	Thousand cubic feet of natural gas equivalent
MMBbls	Million barrels of crude oil or other liquid hydrocarbons
MMBtu	Million British thermal units
MMcf	Million cubic feet of natural gas
MMcfe	Million cubic feet of natural gas equivalent
MMBoe	Million barrels of crude oil or other liquid hydrocarbons equivalent
SEC	United States Securities and Exchange Commission
U.S.	United States of America
U.K.	United Kingdom of Great Britain and Northern Ireland

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, a non-GAAP measure, 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), after 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).

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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.

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

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

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

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

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PART I

Item 1. Business.

General

ATP Oil & Gas Corporation was incorporated in Texas in 1991. We are engaged in the acquisition, development and production of oil and natural gas properties in the Gulf of Mexico and the 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 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, 2007, we had estimated net proved reserves of 715.6 Bcfe, of which approximately 441.7 Bcfe (62%) were in the Gulf of Mexico and 273.9 Bcfe (38%) were in the North Sea. Year-end reserves were comprised of 356.2 Bcf of natural gas (50%) and 59.9 MMBbls of oil (50%). The majority of our oil reserves (71%) are located in the Gulf of Mexico. Our natural gas reserves are almost evenly split between the Gulf of Mexico (53%) and the North Sea (47%). Of our total proved reserves, 211.5 Bcfe (30%) were producing, 36 Bcfe (5%) were developed and not producing and 467.7 Bcfe (65%) were undeveloped. The estimated pre-tax PV-10 of our proved reserves at December 31, 2007 was $3.5 billion. See “Item 2. Properties – Oil and Natural Gas Reserves” for a reconciliation to after-tax PV-10.

At December 31, 2007, we had leasehold and other interests in 76 offshore blocks, 40 platforms and 127 wells, including 19 subsea wells, in the Gulf of Mexico. We operate 109 (86%) of these wells, including all of the subsea wells, and 78% of our offshore platforms. We also had interests in 10 blocks and two company-operated subsea wells in the North Sea. Our average working interest in our properties at December 31, 2007 was approximately 82%.

Our Business Strategy

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

• significant undeveloped reserves or reservoirs;

• close proximity to developed markets for oil and natural gas;

• existing infrastructure of oil and natural gas pipelines and production / processing platforms; and

• a relatively stable regulatory environment for offshore oil and natural gas development and production.

We believe our strategy has significantly lower risk than 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.

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We focus on acquiring properties that have become noncore or nonstrategic 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 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. 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. For the three year period ending December 31, 2007, we have added 280.8 Bcfe of proved oil and natural gas reserves through acquisitions at a total cost of $141.0 million, exclusive of asset retirement costs. Development costs exclusive of asset retirement costs for this same period were approximately $1.688 billion or 76% of oil and gas capital expenditures.

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 complete the development project efficiently and commence production in the shortest time possible after initial significant investment in order to maximize our rate of return.

Our Strengths

• Low Acquisition Cost Structure. We believe that our focus on acquiring properties with minimal cash investment for the proved undeveloped component allows us to pursue the acquisition of properties with minimal capital at risk.

• Technical Expertise and Significant Experience. We have assembled a technical staff with an average of over 26 years of industry experience. Our technical staff has specific expertise in the Gulf of Mexico and North Sea offshore property development, including the implementation of subsea completion technology.

• Operating Control. As the operator of a property, we are afforded greater control of the selection of completion and production equipment, the timing and amount of capital expenditures and the operating parameters and costs of the project. As of December 31, 2007, we operated all of our properties under development, all of our subsea wells and 78% of our offshore platforms.

• Employee Ownership. Through employee ownership of company stock, we have assembled a staff whose business decisions are aligned with the interests of our shareholders. As of February 22, 2008, our executive officers and directors own approximately 20% of our common stock.

• Inventory of Projects. We have a substantial inventory of properties to develop in both the Gulf of Mexico and the North Sea.

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Marketing and Delivery Commitments

We sell 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 such 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 unaffiliated gas marketing companies. Historically, we have sold our oil and natural gas production to a relatively small 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. For the year ended December 31, 2007, revenues from four purchasers accounted for 36%, 18%, 16% and 11%, respectively, of oil and gas production revenues.

Competition

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

Regulation

Gulf of Mexico

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

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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, nondiscriminatory 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 nonjurisdictional 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 nondiscriminatory 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.

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

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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 nondiscriminatory 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.

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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.

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.

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.

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

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

The Safe Drinking Water Act (“SDWA”) regulates the underground injection of fluid (such as the reinjection of brine produced and separated from oil and natural gas production) through a well. The SDWA of 1974, as amended establishes a regulatory framework for underground injection, with the main goal being the protection of usable aquifers. The primary objective of injection well operating requirements is to ensure the mechanical integrity of the injection apparatus and to prevent migration of fluids from the injection zone into underground sources of drinking water. Hazardous-waste injection well operations are strictly controlled and certain wastes, absent an exemption, cannot be injected into underground injection control wells. Failure to abide by our permits could subject us to civil and/or criminal enforcement.

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 wastes 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

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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 any more burdensome to us than to other companies our size involved in similar natural gas and oil development and production activities.

North Sea

Our properties in the U.K. sector represent virtually all of our total proved reserves in the North Sea. Related government regulations in the U.K. are discussed below.

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 Business Enterprise and Regulatory Reform (the “Secretary of State”) a consent to commence field development. We would be required to obtain the consent of the Secretary of State prior to transferring an interest in a license.

The terms of U.K. petroleum production licenses are based on model license clauses applicable at the time of 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 has approved. Breach of these requirements may result in the revocation of the license. In addition, licenses may require payment of fees and royalties on production and also impose certain other duties.

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

Environmental Regulations. Our operations are 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 before 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 Business Enterprise and Regulatory Reform, 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,

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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.

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.

Pipelines and Transportation. 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, National Grid Gas plc (“National Grid”). The terms on which National Grid must transport gas are governed by the Gas Acts of 1986 and 1995, the gas transporter’s license issued to National Grid 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 National Grid 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 to ship the gas through the NTS on our behalf.

Compliance

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

Employees

At December 31, 2007 we had 55 full-time employees in our Houston office, 7 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.

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Available Information

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 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.

Item 1A. Risk Factors.

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

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

Estimates of our oil and natural gas reserves and the costs and timing associated with developing these reserves may not be accurate. Additionally, approximately 65% 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 of 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 or infrastructure installation may result in a material adverse effect on our financial condition and results of operations. For instance, during 2006 and 2007, 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.

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In addition, relatively few wells contribute a substantial portion of our production. If we were to experience operational problems or adverse commodity prices 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 and abandonment operations 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. Increased drilling activity in the Gulf of Mexico and the North Sea decreases the availability of offshore rigs and associated equipment. 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. These costs may increase further and necessary equipment and services may not be available to us at economical prices. For the year ended December 31, 2007, we recorded a loss on abandonment of $18.6 million primarily as a result of increased service costs in the Gulf of Mexico.

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 $849.5 million, $577.0 million and $420.5 million for the years ended December 31, 2007, 2006 and 2005, 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.

During 2008, we plan to finance anticipated expenses, debt service and acquisition and development requirements with available cash, funds generated by operating activities and net cash proceeds from potential sales 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.

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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. Among the factors that can cause this volatility are:

• worldwide or regional demand for energy, which is affected by economic conditions;

• the domestic and foreign supply of oil and natural gas;

• the devaluation of the U.S. dollar against other currencies

• weather conditions;

• domestic and foreign governmental regulations;

• political conditions in natural gas or oil producing regions;

• the ability of members of the Organization of Petroleum Exporting Countries to agree upon and maintain oil prices and production levels; and

• price and availability of alternative fuels.

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.

As required by our lenders, we periodically utilize 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:

• production is less than expected for forward sales contracts;

• the counterparty to the derivative instrument defaults on its contract obligations; or

• there is an adverse change in the expected differential between the underlying price in the derivative instrument and the fixed price forward sales contract and actual prices received.

Our results of operations may be negatively impacted in the future by our 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.

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

During March, 2007 ATP, Credit Suisse (as Administrative Agent and Collateral Agent for the lenders) and the lenders named therein entered into Amendment No. 1 and Agreement (the “Amendment”) amending the Third Amended and Restated Credit Agreement (the “Existing Credit Agreement” or “Term Loans”).

The terms of the Existing Credit Agreement require us to comply with certain covenants. Capitalized terms are defined in the Existing Credit Agreement. The covenants include:

• Minimum Current Ratio of 1.0 to 1.0;

• Ratio of Total Net Debt to Consolidated EBITDAX of not greater than 3.0 to 1.0 at the end of each quarter;

• Ratio of Consolidated EBITDAX to Consolidated Interest Expense of not less than 2.5 to 1.0 for any four consecutive fiscal quarters;

• Ratio of pre-tax PV-10 of our total Proved Developed Producing oil and gas reserves adjusted for current oil and gas price estimates, to Net Debt of at least 0.5 to 1.0 at June 30 and December 31 of any fiscal year;

• Ratio of pre-tax PV-10 of our Total Proved oil and gas reserves plus 50% of our pre-tax probable oil and gas reserves, both adjusted for current oil and gas price estimates, to Net Debt of at least 2.5 to 1.0 at June 30 or December 31 of any fiscal year;

• Commodity Hedging Agreements, based on forecasted production attributable to our proved producing reserves and calculated on a rolling twelve month basis, of (i) not less than 60% during the year subsequent to measurement, and (ii) not less than 40% during the second year subsequent to measurement;

• Permitted Business Investments during any fiscal year of no more than $150.0 million or 7.5% of PV-10 value of our total proved reserves.

During September 2007, the Company, Credit Suisse (as Administrative Agent for the lenders) and the lenders named therein entered into an Unsecured Subordinated Credit Agreement (the “Subordinated Notes”) for aggregate borrowings of $210.0 million. The Subordinated Notes contain no financial performance covenants, but contain affirmative and negative covenants, including limitations on incurring certain indebtedness, that are usual and customary for transactions of this type.

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. We were in compliance with the financial performance covenants applicable to our Term Loans at December 31, 2007, 2006, 2005. If we are unable to meet the requirements of our Term Loans, Subordinated Notes 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:

• make it more difficult or render us unable to satisfy these or our other financial obligations;

• require us to dedicate a substantial portion of any cash flow from operations to the payment of interest and principal due under our debt, which will reduce funds available for other business purposes;

• increase our vulnerability to general adverse economic and industry conditions;

• limit our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate;

• place us at a competitive disadvantage compared to some of our competitors that have less financial leverage;

• limit our ability to obtain additional financing required to fund working capital and capital expenditures and for other general corporate purposes; and

• make it difficult or impossible for us to meet our scheduled debt maturities, which increase significantly in June 2009.

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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.

We may incur substantial impairment write-downs.

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 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 year-end 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 impairment of $34.3 million, $19.5 million for the years ended December 31, 2007 and 2006, respectively and no impairments in 2005.

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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:

• fires;

• explosions;

• blow-outs and surface cratering;

• uncontrollable flows of natural gas, oil and formation water;

• pipe, cement, subsea well or pipeline failures;

• casing collapses;

• embedded oil field drilling and service tools;

• abnormally pressured formations;

• environmental accidents or hazards, such as natural gas leaks, oil spills, pipeline ruptures and discharges of toxic gases; and

• hurricanes and other natural disasters.

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:

• injury or loss of life;

• severe damage to and destruction of property, natural resources and equipment;

• pollution and other environmental damage;

• clean-up responsibilities;

• regulatory investigation and penalties;

• suspension of our operations; and

• repairs to resume operations.

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.

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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 worker’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

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affect our competitive position. These competitors may be able to pay more for oil and natural gas properties and may be able to define, evaluate, bid for and acquire a greater number of properties than we can. Our ability to acquire additional properties and develop new and existing properties in the future will depend on our ability to conduct operations, to evaluate and select suitable properties and to consummate transactions in this highly competitive environment. In addition, some of our competitors have been operating in the Gulf of Mexico and in the North Sea for a much longer time than we have and have demonstrated the ability to operate through industry cycles.

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

The net assets, net earnings and cash flows from our wholly owned subsidiaries in the U.K. and the Netherlands are based on the U.S. dollar equivalent of such amounts measured in the applicable local currency. These foreign operations have the potential to impact our financial position due to fluctuations in exchange rates. 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. In July 2007, we entered into a foreign currency swap agreement which locks in a $2.049 USD/GBP exchange rate. At December 31, 2007, the remaining notional amount of the swap was £18.0 million through March 2008. Otherwise, we have not utilized derivatives or other financial instruments to hedge the risk associated with the movement in foreign currency exchange rates.

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, 2007, we had 27 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 20% of our outstanding shares of common stock as of February 22, 2008. As a result, these shareholders are in a position to significantly influence or control the outcome of matters requiring a shareholder vote, including the election of directors, the adoption of an amendment to our articles of incorporation or bylaws and the approval of mergers and other significant corporate transactions. Their control of ATP may delay or prevent a change of control of ATP and may adversely affect the voting and other rights of other shareholders.

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Rapid growth may place significant demands on our resources.

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

• the need to manage relationships with various strategic partners and other third parties;

• difficulties in hiring and retaining skilled personnel necessary to support our business;

• the need to train and manage a growing employee base; and

• pressures for the continued development of our financial and information management systems.

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:

• discharge permits for drilling operations;

• bonds for ownership, development and production of oil and gas properties;

• reports concerning operations; and

• taxation.

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.

Item 1B. Unresolved Staff Comments.

None

Item 2. Properties.

General

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, 2007, we owned leasehold and other interests in 76 offshore blocks, 40 platforms and 127 wells, including 19 subsea wells, in the Gulf of Mexico. We operate 109 (86%) of these wells, including all of the subsea wells, and 78% of our offshore platforms. We also had interests in 10 blocks and two company-operated subsea wells in the North Sea. Our average working interest in our properties at December 31, 2007 was approximately 82%. As of December 31, 2007, we had leasehold interests located in the Gulf of Mexico and North Sea covering approximately 447,910 gross and 372,386 net acres, of which 276,374 gross acres were developed and 206,322 net acres were developed.

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Gulf of Mexico

Acquisitions – During 2007, we acquired 37.3 Bcfe of undeveloped and developed minerals in place for an aggregate net purchase price of $40.6 million. Significant acquisitions are discussed below.

During January 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 interest in the Canyon Express Pipeline Common System (“Canyon Express”). Both Aconcagua and Camden Hills, along with MC Block 217 (“King’s Peak”) produce through Canyon Express. During December 2007, we increased our ownership in Camden Hills by 50.03% in exchange for the assumption of future abandonment liability for which the seller is obligated to pay ATP a total of $12.5 million upon abandonment of the property. Consequently, we recognized a $10.8 million long-term receivable, an asset retirement obligation of $8.3 million and $2.6 million of deferred revenue. As a result of the acquisitions, we now hold a 66.7% working interest in Camden Hills and a 55.09% working interest in the Canyon Express for which we are the operator.

During January 2007, we completed the acquisition of a 100% working interest in the northwest quarter of MC Block 755 (“Anduin”), a 50% working interest in MC Block 754 (“Anduin West”), and a 25% working interest in MC Block 800 (“Gladden”). These properties are located in the vicinity of the MC Block 711 (“Gomez”) development and, if successful, are expected to produce through the ATP Innovator floating production facility. A portion of the acquisition price of one property was financed by granting an interest in the future net profits of that property.

Other acquisitions in 2007 included Ship Shoal Block 350 and additional interests at South Timbalier Block 77 and High Island Block 74. During August 2007, we were the apparent high bidder and we subsequently acquired a 100% working interest in High Island Block A-580 and East Breaks Block 563 at the MMS offshore lease sale. At the October 2007 MMS lease sale we were the apparent high bidder on two blocks, De Soto Canyon Block 355, immediately east of the Canyon Express area, and Viosca Knoll Block 863. Both of these blocks were subsequently awarded to ATP.

Development – On the Gulf of Mexico Shelf during 2007, we drilled and completed two development and three exploratory wells in which we own 100% of the working interest. Four of the wells are at Ship Shoal 351 and the fifth well is at South Timbalier 77. All five wells were placed on production in 2007. At year-end 2007, three wells were being drilled.

Gulf of Mexico Deepwater – MC 711 and the Gomez Hub. The Gomez Hub continues to be the largest contributor to production. To provide for additional acquisition of surrounding blocks and to accommodate new drilling plans, the production capacity of the ATP Innovator, the floating production facility that serves the Gomez Hub, was expanded in 2007. As noted above, we acquired interests in three blocks south and west of MC 711. During 2007, two development wells were drilled and placed on production. In conjunction with one of the wells, an exploratory sand was targeted that found noncommercial quantities of hydrocarbons and was charged to exploration expense. We operate MC 711 with a 100% working interest.

Telemark Hub – Construction began on the new floating drilling and production facility that will serve the Telemark Hub. Installation of the facility at MC 941/942 is expected in late 2008.

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North Sea

Development – Two wells were drilled at Tors in 2007, one exploratory and one development. Both were successful and placed on production in 2007, bringing to four the number of producing wells at Tors. We operate Tors with an 85% working interest.

At Wenlock, we drilled and placed on production a development well during 2007. We operate Wenlock with a 100% working interest.

Significant Properties

The following table sets forth additional information on our most significant properties as of December 31, 2007:

Field	Development Location	Net Total Proved Reserves MMcfe	2007 Net Production MMcfe	Average WI%	Expected First Production
Canyon Express Hub (1)	GOM	53,437	5,043	54	Producing
Cheviot	N. Sea	180,560	—	100	2010
Gomez Hub	GOM	128,735	31,861	100	Producing
Telemark Hub	GOM	183,070	—	100	2009
Tors	N. Sea	60,906	9,983	85	Producing

(1) Contains both shut-in reserves and undeveloped reserves, both of which are scheduled to be on production in 2008/2009.

Oil and Natural Gas Reserves

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

Our business strategy is to acquire proved reserves, typically 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, 2007 based on reserve reports prepared by independent petroleum engineers 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.

	Proved Reserves
	Developed	Undeveloped	Total
Gulf of Mexico
Natural gas (MMcf)	69,845	117,789	187,634
Oil and condensate (MBbls)	14,111	28,231	42,342
Total proved reserves (MMcfe)	154,511	287,175	441,686
North Sea
Natural gas (MMcf)	93,317	75,260	168,577
Oil and condensate (MBbls)	1	17,550	17,551
Total proved reserves (MMcfe)	93,323	180,560	273,883
Total
Natural gas (MMcf)	163,162	193,049	356,211
Oil and condensate (MBbls)	14,112	45,781	59,893
Total proved reserves (MMcfe)	247,834	467,735	715,569

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

At December 31, 2007 our standardized measure of discounted future net cash flows was $2.6 billion. The present value of future net pre-tax 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, 2007. 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.

Net present value of future net cash flows, before income taxes	$	3,497,262
Future income taxes, discounted at 10%		(857,295	)
Standardized measure of discounted future net cash flows	$	2,639,967

Drilling Activity

The following table shows our drilling and well 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.

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	Gulf of Mexico			North Sea
	2007	2006	2005	2007	2006	2005
Gross Development Wells:
Productive	4.0	3.0	4.0	2.0	2.0	2.0
Nonproductive	—	—	—	—	—	—
Total	4.0	3.0	4.0	2.0	2.0	2.0
Net Development Wells:
Productive	4.0	2.8	3.4	1.9	1.7	1.3
Nonproductive	—	—	—	—	—	—
Total	4.0	2.8	3.4	1.9	1.7	1.3
Gross Exploratory Wells:
Productive	3.0	4.0	3.0	1.0	—	—
Nonproductive	1.0	—	1.0	—	—	—
Total	4.0	4.0	4.0	1.0	—	—
Net Exploratory Wells:
Productive	3.0	2.2	3.0	0.9	—	—
Nonproductive	1.0	—	0.8	—	—	—
Total	4.0	2.2	3.8	0.9	—	—
Total Gross Wells:
Productive	7.0	7.0	7.0	3.0	2.0	2.0
Nonproductive	1.0	—	1.0	—	—	—
Total	8.0	7.0	8.0	3.0	2.0	2.0
Total Net Wells:
Productive	7.0	5.0	6.4	2.7	1.7	1.3
Nonproductive	1.0	—	0.8	—	—	—
Total	8.0	5.0	7.2	2.7	1.7	1.3

At December 31, 2007 we had three gross development wells (2.5 net wells) in the Gulf of Mexico in the process of being drilled.

Productive Wells

The following table presents the number of productive oil and natural gas wells in which we owned an interest as of December 31, 2007:

	Gulf of Mexico	North Sea	Total
Gross
Natural gas	31.0	7.0	38.0
Oil	13.0	—	13.0
Total	44.0	7.0	51.0
Net
Natural gas	20.1	5.4	25.5
Oil	9.0	—	9.0
Total	29.1	5.4	34.5

At December 31, 2007, we had two gross natural gas wells with multiple completions.

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Acreage

The following table summarizes our developed and undeveloped acreage holdings at December 31, 2007. Acreage in which ownership interest is limited to royalty, overriding royalty and other similar interests is excluded (in acres):

	Developed (1)		Undeveloped (2)		Total
	Gross	Net	Gross	Net	Gross	Net
Gulf of Mexico	216,728	158,793	151,781	146,309	368,509	305,102
North Sea	59,646	47,529	19,755	19,755	79,401	67,284
Total	276,374	206,322	171,536	166,064	447,910	372,386

(1) Developed acres are acres spaced or assigned to productive wells.

(2) Undeveloped acres are acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas, regardless of whether such acreage contains proved reserves.

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.

	Gulf of Mexico		North Sea		Total
Year Ending December 31:	Gross	Net	Gross	Net	Gross	Net
2008	25,934	25,934	11,703	11,703	37,637	37,637
2009	20,207	17,615	8,052	8,052	28,259	25,667
2010	36,520	36,520	—	—	36,520	36,520
2011 & beyond	69,120	66,240	—	—	69,120	66,240
Total	151,781	146,309	19,755	19,755	171,536	166,064

Production and Pricing Data

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

Item 3. Legal Proceedings.

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.

Item 4. Submission of Matters to a Vote of Security Holders.

No matters were submitted to a vote of security holders during the fourth quarter of 2007.

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PART II

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 or preferred stock, par value $0.001 per share. There were 35,798,009 shares of common stock and no shares of preferred stock outstanding as of February 22, 2008. 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.

	High		Low
2007:
4th Quarter	$	57.58	$	43.19
3rd Quarter		49.39		38.44
2nd Quarter		49.00		37.46
1st Quarter		43.65		35.15
2006:
4th Quarter	$	47.29	$	34.16
3rd Quarter		43.30		35.35
2nd Quarter		49.70		35.04
1st Quarter		44.05		36.05

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.

Shareholder Return Performance Presentation

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 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 (through June 2007), Newfield Exploration Company, Noble Energy Inc., Pogo Producing Company (through November 2007), Remington Oil and Gas Corporation (through December 2005), Stone Energy Corporation, Callon Petroleum Company, Forest Oil Corporation (beginning June 2007), Helix Energy Solution GP (beginning January 2006), Plains Exploration & Production (beginning November 2007).

Each of the total cumulative returns presented assumes a $100 investment beginning December 31, 2002 and ending December 31, 2007. 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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Total Return Analysis	12/31/02		12/31/03		12/31/04		12/31/05		12/31/06		12/31/07
ATP Oil & Gas Corporation	$	100.00	$	154.30	$	456.76	$	909.34	$	972.24	$	1,241.57
Peer Group Index		100.00		124.59		160.46		202.35		205.74		255.71
NASDAQ Market Index		100.00		150.36		163.00		166.58		183.68		201.91

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Item 6. Selected Financial Data.

(In thousands, except per share data)

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

	Year Ended December 31,
	2007			2006			2005			2004			2003
Statement of Operations Data:
Revenues:
Oil and gas production	$	599,324		$	414,182		$	146,674		$	116,123		$	70,151
Other revenues (1)		8,611			5,639			—			—			—
		607,935			419,821			146,674			116,123			70,151
Cost, operating expenses and other:
Lease operating		91,693			72,446			23,629			19,531			17,173
Exploration		13,756			2,231			6,208			997			1,358
General and administrative (2)		32,018			32,976			24,331			15,806			12,170
Depreciation, depletion and amortization		247,378			169,704			64,069			55,637			29,378
Impairment of oil and gas properties		34,342			19,520			—			—			11,670
Accretion of asset retirement obligation		12,117			8,076			3,238			2,069			2,752
(Gain) loss on abandonment		18,649			9,603			(732	)		(251	)		4,973
Loss on unsuccessful property acquisition (3)		—			—			—			—			8,192
Gain on disposition of properties		—			—			(2,743	)		(6,011	)		—
Other, net		(3,706	)		(7	)		(419	)		120			(2,244	)
		446,247			314,549			117,581			87,898			85,422
Income (loss) from operations		161,688			105,272			29,093			28,225			(15,271	)
Other income (expense):
Interest income		7,603			4,532			4,064			627			52
Interest expense		(121,302	)		(58,018	)		(35,720	)		(24,112	)		(11,668	)
Loss on extinguishment of debt		—			(28,115	)		—			(3,326	)		(3,352	)
Income (loss) before income taxes and cumulative effect of change in accounting principle		47,989			23,671			(2,563	)		1,414			(30,239	)
Income tax (expense) benefit		631			(16,794	)		(153	)		(58	)		(21,224	)
Income (loss) before cumulative effect of change in accounting principle		48,620			6,877			(2,716	)		1,356			(51,463	)
Cumulative effect of change in accounting principle, net of tax (4)		—			—			—			—			662
Net income (loss)		48,620			6,877			(2,716	)		1,356			(50,801	)
Preferred stock dividends		—			(46,225	)		(9,858	)		—			—
Net income (loss) available to common shareholders	$	48,620		$	(39,348	)	$	(12,574	)	$	1,356		$	(50,801	)
Weighted average number of common shares outstanding:
Basic		30,793			29,693			29,080			24,944			22,975
Diluted		31,301			29,693			29,080			25,271			22,975
Net income (loss) before cumulative effect of change in accounting principle per basic common share	$	1.58		$	(1.33	)	$	(0.43	)	$	0.05		$	(2.24	)
Cumulative effect of change in accounting principle, net of tax per basic common share		—			—			—			—			0.03
Net income (loss) available to common shareholders per basic common share		1.58			(1.33	)		(0.43	)		0.05			(2.21	)
Net income (loss) before cumulative effect of change in accounting principle per diluted common share		1.55			(1.33	)		(0.43	)		0.05			(2.24	)
Cumulative effect of change in accounting principle, net of tax per diluted common share		—			—			—			—			0.03
Net income (loss) available to common shareholders per diluted common share		1.55			(1.33	)		(0.43	)		0.05			(2.21	)

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	December 31,
	2007		2006		2005		2004		2003
Balance Sheet Data:
Cash and cash equivalents	$	199,449	$	182,592	$	65,566	$	102,774	$	4,564
Working capital (deficit)		96,888		77,504		567		68,330		(46,423	)
Oil and gas properties, net		1,830,580		1,095,645		627,421		213,206		189,125
Total assets		2,307,133		1,447,058		823,763		372,147		217,685
Long-term debt, including current maturities		1,404,011		1,071,441		340,989		210,309		115,409
Capital lease, including current maturities		—		23,699		43,116		—		—
Total liabilities		1,997,267		1,411,140		606,252		314,983		213,353
Shareholders’ equity		309,866		35,918		217,511		57,164		4,332

(1) Other revenues are comprised of amounts realized under our Loss of Production Income insurance policy as a result of disruptions caused by the 2005 hurricanes.

(2) Effective January 1, 2006 we adopted SFAS No. 123(R) using the modified prospective transition approach.

(3) During 2003, ATP was in a dispute over a contract for the purchase of an oil and gas property. The dispute was subsequently resolved for $8.2 million.

(4) Effective January 1, 2003 we adopted SFAS No. 143 and recorded a cumulative effect of the change in accounting principle as an increase to earnings of $0.7 million (net of income taxes).

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

Executive Overview

General

ATP Oil & Gas Corporation is engaged in the acquisition, development and production of oil and 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 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:

• significant undeveloped reserves and reservoirs;

• close proximity to developed markets for oil and natural gas;

• existing infrastructure of oil and natural gas pipelines and production / processing platforms; and

• a relatively stable regulatory environment for offshore oil and natural gas development and production.

Our focus is on acquiring properties that are noncore or nonstrategic 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 may 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.

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

To enhance the economics and return on investment of a project, we sometimes develop the project to a value creation point and either sell an interest or bring in partners on a promoted basis during the high capital development phase. For example, 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.

Review of 2007

2007 was another year of major growth in proved reserves and another increase in production for ATP. The growth in reserves was accomplished primarily through extensions and revisions (105.4 Bcfe) and through acquisitions (37.3 Bcfe). Also of significance in 2007 was a marked increase in proved developed reserves, growing from 213.8 Bcfe at the end of 2006 to 247.8 Bcfe at December 31, 2007. Our growth in production from an average of 139 MMcfe per day during 2006 to an average of 175 MMcfe per day during 2007, an increase of 26%, was primarily a result of new production from our Mississippi Canyon 711 (Gomez) project in the Gulf of Mexico.

Reserves

At December 31, 2007, we had proved reserves of 715.6 Bcfe, of which 62% are located in the Gulf of Mexico and the remaining 38% are in the North Sea. The pre-tax PV-10 of our proved reserves at December 31, 2007 was $3.5 billion. See “Item 2. Properties – Oil and Natural Gas Reserves” for reconciliation to our after-tax PV-10 of $2.6 billion. In addition, we have scheduled for drilling or completion, properties where previous drilling into the targeted reservoirs indicates 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.

Acquisitions

During 2007, we acquired 37.3 Bcfe of undeveloped and developed minerals in place for an aggregate net purchase price of $40.6 million. Significant acquisitions are discussed below.

During January 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 interest in the Canyon Express Pipeline Common System

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(“Canyon Express”). Both Aconcagua and Camden Hills, along with MC Block 217 (“King’s Peak”) produce through Canyon Express. During December 2007, we increased our ownership in Camden Hills by 50.03% in exchange for the assumption of future abandonment liability for which the seller is obligated to pay ATP a total of $12.5 million upon abandonment of the property. Consequently, we recognized a $10.8 million long-term receivable, an asset retirement obligation of $8.3 million and $2.6 million of deferred revenue. As a result of the acquisitions, we now hold a 66.7% working interest in Camden Hills and a 55.09% working interest in the Canyon Express for which we are the operator.

During January 2007, we completed the acquisition of a 100% working interest in the northwest quarter of MC Block 755 (“Anduin”), a 50% working interest in MC Block 754 (“Anduin West”), and a 25% working interest in MC Block 800 (“Gladden”). These properties are located in the vicinity of the MC Block 711 (“Gomez”) development and, if successful, are expected to produce through the ATP Innovator floating production facility. A portion of the acquisition price of one property was financed by granting an interest in the future net profits of that property.

Other acquisitions in 2007 included Ship Shoal Block 350 and additional interests at South Timbalier Block 77 and High Island Block 74. During August 2007, we were the apparent high bidder and we subsequently acquired a 100% working interest in High Island Block A-580 and East Breaks Block 563 at the MMS offshore lease sale. At the October 2007 MMS lease sale we were the apparent high bidder on two blocks, De Soto Canyon Block 355, immediately east of the Canyon Express area, and Viosca Knoll Block 863. Both of these blocks were subsequently awarded to ATP.

Development

On the Gulf of Mexico Shelf during 2007, we drilled and completed two development and three exploratory wells in which we own 100% of the working interest. Four of the wells are at Ship Shoal 351 and the fifth well is at South Timbalier 77. All five wells were placed on production in 2007. At year-end 2007, three wells were being drilled.

Gulf of Mexico Deepwater – MC 711 and the Gomez Hub. The Gomez Hub continues to be the largest contributor to production. To provide for additional acquisition of surrounding blocks and to accommodate new drilling plans, the production capacity of the ATP Innovator, the floating production facility that serves the Gomez Hub, was expanded in 2007. As noted above, we acquired interests in three blocks south and west of MC 711. During 2007, two development wells were drilled and placed on production. In conjunction with one of the wells, an exploratory sand was targeted that found noncommercial quantities of hydrocarbons and was charged to exploration expense. We operate MC 711 with a 100% working interest.

Telemark Hub – Construction began on the new floating drilling and production facility that will serve the Telemark Hub. Installation of the facility at MC 941/942 is expected in late 2008.

In the North Sea, two wells were drilled at Tors in 2007, one exploratory and one development. Both were successful and placed on production in 2007 bringing to four the number of producing wells at Tors. We operate Tors with an 85% working interest.

At Wenlock, we drilled and placed on production a development well during 2007. We operate Wenlock with a 100% working interest.

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Financings

During 2007, we completed three new financings. During March 2007, ATP, Credit Suisse (as Administrative Agent and Collateral Agent for the lenders) and the lenders named therein entered into Amendment No. 1 and Agreement (the “Amendment”) amending the Third Amended and Restated Credit Agreement (the “Existing Credit Agreement” or “Term Loans”). The Amendment changed the total amount borrowed and the interest rate to LIBOR plus 3.5%. New borrowings under the Existing Credit Agreement were $375.0 million which were used to repay the $175.0 million outstanding borrowings under our former second lien term loan facility, which bore interest at LIBOR plus 4.75%, and to pay financing costs of $8.4 million. The net proceeds of the new Term Loans were used primarily for oil and gas development activities.

During September 2007, the Company, Credit Suisse (as Administrative Agent for the lenders) and the lenders named therein entered into an Unsecured Subordinated Credit Agreement (the “Subordinated Notes”) for aggregate borrowings of $210.0 million. The borrowings bear annual interest at 11.25%, payable quarterly, and mature in September 2011. Such borrowings are subordinated to the borrowings under the Existing Credit Agreement and may be prepaid at any time at the option of the Company, subject to limitations set forth in the Existing Credit Agreement. The Company has assumed that debt will be paid off at maturity and accordingly recognizes over the term of the facility additional noncash interest expense related to deferred financing costs, an original issue discount and a sliding-scale redemption premium. If held to maturity, the aggregate average effective interest rate on the Subordinated Notes is approximately 15.3% per annum. The Company received net proceeds from the issuance of the Subordinated Notes of $193.8 million after deducting $16.2 million for the original issue discount, fees and expenses.

During November 2007, we issued 5,000,000 shares of common stock and received net proceeds of approximately $226.7 million ($47.00 per share before underwriters discounts and commissions and offering expenses). Proceeds of the offering were used primarily for oil and gas development activities. We were required under the terms of our Existing Credit Agreement to apply $56.7 million of the net proceeds to reduce the outstanding balance of our Term Loans.

Cash flow from operating activities was $329.4 million for the year ended December 31, 2007, compared to $258.5 million in 2006. We had working capital at December 31, 2007 of $96.9 million, an increase of approximately $19.4 million from December 31, 2006. This decrease is primarily attributable to increased spending on development of oil and gas properties.

2008 Operational and Financial Objectives

We will continue to pursue acquisitions that meet our criteria as well as devote considerable resources to our developments in 2008. With approximately 52% of our proved reserves in the Gulf of Mexico deepwater, much of our capital and efforts will be spent at this location. At the Gomez Hub, additional drilling is planned at MC 800 and MC 754. At the Canyon Express Hub, additional opportunities will continue to be evaluated. At the Telemark Hub, construction will continue on the floating drilling and production facility with on-site installation projected in late 2008. A second floating facility to serve the southern area of the Telemark Hub is also under consideration.

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During 2008, efforts will be spent completing and bringing to production at least three more wells on the Gulf of Mexico Shelf. Depending on the success of these wells, additional activities may be targeted at these locations in 2008 or later.

In the North Sea, we will continue to evaluate our producing properties and the areas surrounding these properties for additional development or exploratory opportunities. Cheviot, one of our largest properties in terms of proved reserves, is a multi-year development that is scheduled to begin active development during 2008.

Our revenues, profitability and cash flows are highly dependent upon many factors, particularly our production results and the price of oil and natural gas. We believe that 2008 production will exceed that of 2007 as a result of our recent development programs and projects scheduled for development in 2008. To mitigate future price volatility, we may hedge the sales price of additional production.

Results of Operations

For the years ended December 31, 2007, 2006 and 2005 we reported net income (loss) available to common shareholders of $48.6 million, $(39.3) million and $(12.6) million , or $1.55, $(1.33) and $(0.43) per diluted share, respectively.

Oil and Gas Production Revenues

Revenues presented in the table and the discussion below represent revenues from sales of 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 Statement of Financial Accounting Standards (“SFAS”) No. 133 are also included in these amounts. Approximately 51%, 67% and 61% of our oil production was sold under these contracts for the years ended December 31, 2007, 2006 and 2005, respectively. Approximately 20%, 19% and 54% 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.

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	Year Ended December 31,								% Change from 2006 to 2007		% Change from 2005 to 2006
	2007			2006			2005
Production:
Natural gas (MMcf)		37,013			31,224			15,614	19	%	100	%
Oil and condensate (MBbls)		4,498			3,273			717	37	%	356	%
Total (MMcfe)		64,002			50,860			19,914	26	%	155	%
Revenues from production (in thousands):
Natural gas	$	309,572		$	234,035		$	116,404	32	%	101	%
Effects of cash flow hedges		897			2,479			40	(64	)%	6,098	%
Total	$	310,469		$	236,514		$	116,444	31	%	103	%
Oil and condensate	$	290,329		$	180,713		$	30,041	61	%	502	%
Effects of cash flow hedges		(1,549	)		(3,155	)		—	51	%	(100	)%
Total	$	288,780		$	177,558		$	30,041	63	%	491	%
Natural gas, oil and condensate	$	599,901		$	414,748		$	146,445	45	%	183	%
Effects of cash flow hedges		(652	)		(676	)		40	4	%	(1,790	)%
Total	$	599,249		$	414,072		$	146,485	45	%	183	%
Average realized sales price:
Natural gas (per Mcf)	$	8.36		$	7.50		$	7.46	11	%	—
Effects of cash flow hedges (per Mcf)		0.02			0.07			—	(71	)%	100	%
Average realized price (per Mcf)	$	8.39		$	7.57		$	7.46	11	%	1	%
Oil and condensate (per Bbl)	$	64.54		$	55.21		$	41.90	17	%	32	%
Effects of cash flow hedges (per Bbl)		(0.34	)		(0.96	)		—	(65	)%	(100	)%
Average realized price (per Bbl)	$	64.20		$	54.25		$	41.90	18	%	29	%
Natural gas, oil and condensate (per Mcfe)	$	9.37		$	8.15		$	7.35	15	%	11	%
Effects of cash flow hedges (per Mcfe)		(0.01	)		(0.01	)		—	—		(100	)%
Average realized price (per Mcfe)	$	9.36		$	8.14		$	7.35	15	%	11	%

Revenues from production increased 45% in 2007 compared to 2006. During 2007, our production increased 26% compared to 2006 primarily due to greater production in the Gulf of Mexico from MC 711, and new production at the Canyon Express Hub and Garden Banks 409. In the North Sea, increased production at Tors was offset by decreased production from L-06 in 2007. The comparable revenues were impacted favorably by an overall 15% increase in average sales price.

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 volumes increased more than three-fold. Realized average sales price in 2006 was 11% higher as compared to 2005.

Other Revenues

Other revenues for 2007 and 2006 are comprised of amounts realized as a result of disruptions caused by the 2005 hurricanes under our loss of production income insurance policy.

Lease Operating

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, 2007, 2006 and 2005 was as follows ($ in thousands):

	Year Ended December 31,						% Change from 2006 to 2007		% Change from 2005 to 2006
	2007		2006		2005
Lease operating	$	91,693	$	72,446	$	23,629	27	%	207	%
Per Mcfe	$	1.43	$	1.42	$	1.19	1	%	19	%

Lease operating expenses for 2007 increased to $91.7 million ($1.43 per Mcfe) from $72.4 million ($1.42 per Mcfe) in 2006. The increase was primarily attributable to the production increases noted above. Typically, as production increases, our lease operating expense per unit decreases as a result of fixed costs. However, due to significantly higher insurance costs, our per unit costs have remained flat.

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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 of production basis reflects the price spikes we experienced for materials and labor in the Gulf of Mexico after the 2005 hurricanes.

Exploration

During 2007, exploration expense included costs related to an exploratory well at MC 667. This well found noncommercial quantities of hydrocarbons, resulting in exploration expense of approximately $10.3 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 noncommercial quantities of hydrocarbons, resulting in exploration and dry hole expense of approximately $5.3 million in 2005. Exploration expense in 2007, 2006 and 2005 also includes the costs of geological and geophysical studies.

General and Administrative

General and administrative expenses are overhead-related expenses, including employee compensation, legal and accounting fees, insurance, and investor relations expenses. General and administrative expense for the years ended December 31, 2007, 2006 and 2005 was as follows ($ in thousands):

	Year Ended December 31,						% Change from 2006 to 2007		% Change from 2005 to 2006
	2007		2006		2005
General and administrative	$	32,018	$	32,976	$	24,331	(3	)%	36	%
Per Mcfe	$	0.50	$	0.65	$	1.22	(23	)%	(47	)%

General and administrative expense of $32.0 million was approximately the same as 2006. Noncash stock-based compensation expense decreased to $7.1 million in 2007 compared to $11.5 million for 2006 primarily due to a change in the vesting schedule of restricted stock. However, this decrease was offset by an increase in other compensation costs.

The increase in 2006 compared to 2005 was primarily due to $11.5 million of stock-based compensation resulting from adoption of SFAS No. 123(R) in 2006 partially offset by inclusion in 2005 of costs associated with a nonrecurring employee incentive program.

Depreciation, Depletion and Amortization

Depreciation, depletion and amortization (“DD&A”) expense for the years ended December 31, 2007, 2006 and 2005 was as follows ($ in thousands):

	Year Ended December 31,						% Change from 2006 to 2007		% Change from 2005 to 2006
	2007		2006		2005
DD&A	$	247,378	$	169,704	$	64,069	46	%	165	%
Per Mcfe	$	3.87	$	3.34	$	3.22	16	%	4	%

DD&A expense increased $77.7 million (46%) during 2007 to $247.4 million from $169.7 million for 2006. The DD&A expense increase was due primarily to increased production. The DDA rates for the Gulf of Mexico and North Sea were $3.57 per Mcfe and $5.12 per Mcfe, respectively. The average DD&A rate increased 16% to $3.87 per Mcfe in 2007 compared to $3.34 per Mcfe in 2006. This per unit increase is primarily a result of higher costs incurred on our new developments relative to some of our older properties.

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

Impairment of Oil and Gas Properties

During 2007, we recorded impairment expense of $25.3 million and $9.0 million related to Gulf of Mexico and North Sea properties, respectively. These impairments are primarily due to unfavorable operating performance on four properties resulting in downward revisions of recoverable reserves.

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.

Accretion of Asset Retirement Obligation

Accretion expense of $12.1 million in 2007, $8.1 million in 2006 and $3.2 million in 2005 show increases primarily due to increased asset retirement obligations associated with increased oil and gas property development and general vendor price increases.

(Gain) Loss on Abandonment

During 2007, we recognized an aggregate loss on abandonment of $18.6 million due to unanticipated vendor price increases in the Gulf of Mexico. 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. In 2005, we had a gain on abandonment of $0.7 million.

Gain on Disposition of Properties

During 2005 we recognized a net gain of $2.7 million on the sales of 15% of our interest in Tors fields in the North Sea and one property in the Gulf of Mexico.

Other, Net

Other income, net primarily included a foreign currency transaction gain related to our restricted cash deposits.

Interest Income

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 funding activities.

Interest Expense

Interest expense increased to $121.3 million for 2007 compared to $58.0 million for 2006 primarily due to the net $200 million increase in borrowings under our Term Loans and the issuance of $210.0 million face value subordinated notes. Partially offsetting this increase are $8.0 million of capitalized 2007 interest costs related to the construction of a floating production system at the Telemark Hub.

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Interest expense increased to $58.0 million for 2006 compared to $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.

Loss on Extinguishment of Debt

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.

Income Taxes

We recorded a net tax benefit of $0.6 million for the year ended December 31, 2007, determined based on the results of operations for the year for each jurisdiction, the valuation allowance released and permanent differences affecting the overall tax rate in each foreign jurisdiction. As of December 31, 2007, for U.S. tax provision purposes all of our valuation allowance has been released except the portion related to our excess tax benefits from stock options and restricted stock prior to implementation of SFAS No. 123(R).

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.

Preferred Stock Dividends

We recognized $46.2 million of dividends during 2006 related to our 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 we redeemed all of the shares 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.

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Liquidity and Capital Resources

Under the Existing Credit Agreement (as defined below), we have a $50.0 million revolving credit facility (“Revolver”), all of which was available as of December 31, 2007. At that date, we had working capital of approximately $96.9 million, an increase of approximately $19.4 million from December 31, 2006. Our credit agreement covenants specify a minimum liquidity ratio under which we include the availability under the Revolver, and exclude current maturities of long-term debt, the current portion of assets and liabilities from derivatives and the current portion of asset retirement obligations. We were in compliance with our credit agreement covenants at December 31, 2007.

Historically, we have financed our acquisition and development activities through a combination of bank borrowings, proceeds from equity offerings, cash from operations and, occasionally, the sale on a promoted basis of interests in selected properties. We intend to continue to finance our near-term development projects utilizing these potential sources of capital. As operator of most of our projects under development, we have the ability to significantly control the timing of most of our capital expenditures. Coupled with that control, we believe our cash flows from operating activities and potential for available third-party capital will enable us to meet our future capital requirements.

Cash Flows	Year Ended December 31,
	2007			2006			2005
Cash provided by (used in) (in thousands):
Operating activities	$	329,388		$	258,514		$	43,588
Investing activities		(835,093	)		(590,683	)		(414,072	)
Financing activities		521,795			447,991			335,514

Cash provided by operating activities during 2007 and 2006 was $329.4 million and $258.5 million, respectively. Cash flow from operations increased due to higher oil and gas production revenues during 2007 compared to 2006, partially offset by higher costs. The increase in sales revenue was attributable to higher oil and gas production and higher oil and gas prices during 2007. The increase in cash flows from revenues were partially offset by higher interest costs, higher lease operating expense and by the timing of payments and receipts in our payables and receivables. 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 production volumes and an 11% increase in average realized prices. Gas sales increased by $120.0 million, or 103%, due mainly to 100% higher production. Oil sales increased by $147.5 million, or 491%, due to a 356% increase in production and a 29% increase in the average price.

Cash used in investing activities was $835.1 million and $590.7 million during 2007 and 2006, respectively. Cash expended in the Gulf of Mexico and North Sea for additions to oil and gas properties was approximately $648.7 million and $200.8 million, respectively, in 2007. Cash expended in the Gulf of Mexico and North Sea for additions to oil and gas properties was approximately $356.0 million and $221.0 million, respectively, in 2006.

Cash provided by financing activities was $521.8 million and $448.0 million during 2007 and 2006, respectively. The amount for 2007 was primarily from increases in our Term Loans

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and issuance of Subordinated Notes (as defined below) of $560.3 million (net of issuance costs) and issuance of 5,000,000 shares of common stock for $226.7 million (net of issuance costs), partially offset by the aggregate $268.2 million repayments of our first and second lien term loans and other debt repayments. Cash provided by financing activities in 2006 consisted primarily of net proceeds of $703.9 million related to our term loans, after deducting 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 one series of preferred stock, reduced by $381.1 million paid to redeem our preferred stock.

Long-term Loans

Long-term debt consisted of the following (in thousands):

	December 31,
	2007			2006
First Lien Term Loans	$	1,202,154		$	896,441
Second Lien Term Loans		—			175,000
Subordinated Notes (includes accreted premium of $1,523; net of unamortized discount of $9,666)		201,857			—
Total		1,404,011			1,071,441
Less current maturities		(12,165	)		(8,987	)
Total long-term debt	$	1,391,846		$	1,062,454

During March 2007, ATP, Credit Suisse (as Administrative Agent and Collateral Agent for the lenders) and the lenders named therein entered into Amendment No. 1 and Agreement (the “Amendment”) amending the Third Amended and Restated Credit Agreement (the “Existing Credit Agreement” or “Term Loans”). The Amendment changed the total amount borrowed and the interest rate to LIBOR plus 3.5%. New borrowings under the Existing Credit Agreement were $375.0 million which were used to repay the $175.0 million outstanding borrowings under the Second Lien Term Loan Facility, which bore interest at LIBOR plus 4.75%, and to pay financing costs of $8.4 million. The net proceeds of the Term Loans were used primarily for oil and gas development activities. The interest rate on outstanding borrowings at December 31, 2007 was approximately 8.5%.

The terms of the Existing Credit Agreement require us to comply with certain covenants. Capitalized terms are defined in the Existing Credit Agreement. The covenants include:

• Minimum Current Ratio of 1.0 to 1.0;

• Ratio of Total Net Debt to Consolidated EBITDAX of not greater than 3.0 to 1.0 at the end of each quarter;

• Ratio of Consolidated EBITDAX to Consolidated Interest Expense of not less than 2.5 to 1.0 for any four consecutive fiscal quarters;

• Ratio of pre-tax PV-10 of our total Proved Developed Producing oil and gas reserves adjusted for current oil and gas price estimates, to Net Debt of at least 0.5 to 1.0 at June 30 and December 31 of any fiscal year;

• Ratio of pre-tax PV-10 of our Total Proved oil and gas reserves plus 50% of our pre-tax probable oil and gas reserves, both adjusted for current oil and gas price estimates, to Net Debt of at least 2.5 to 1.0 at June 30 or December 31 of any fiscal year;

• Commodity Hedging Agreements, based on forecasted production attributable to our proved producing reserves and calculated on a rolling twelve month basis, of (i) not less than 60% during the year subsequent to measurement, and (ii) not less than 40% during the second year subsequent to measurement;

• Permitted Business Investments during any fiscal year of no more than $150.0 million or 7.5% of PV-10 value of our total proved reserves.

The foregoing description of the Existing Credit Agreement does not purport to be complete and is qualified in its entirety by reference to Amendment No. 1 which is an exhibit to this report.

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As of December 31, 2007, we were in compliance with the covenants of the Existing Credit Agreement. 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 noncompliance with these covenants. An event of noncompliance with any of the required covenants could result in a material mandatory repayment under the Existing Credit Agreement.

Our Term Loans are 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. and were guaranteed by our wholly owned subsidiary ATP Energy, Inc.

During September 2007, the Company, Credit Suisse (as Administrative Agent for the lenders) and the lenders named therein entered into an Unsecured Subordinated Credit Agreement (the “Subordinated Notes”) for aggregate borrowings of $210.0 million. The borrowings bear annual interest at 11.25%, payable quarterly, and mature in September 2011. Such borrowings are subordinated to the borrowings under the Existing Credit Agreement and may be prepaid at any time at the option of the Company, subject to limitations set forth in the Existing Credit Agreement. The Company has assumed that debt will be paid off at maturity and accordingly recognizes over the term of the facility additional noncash interest expense related to deferred financing costs, an original issue discount and a sliding-scale redemption premium. If held to maturity, the aggregate average effective interest rate on the Subordinated Notes is approximately 15.3% per annum. The Company received net proceeds from the issuance of the Subordinated Notes of $193.8 million after deducting $16.2 million for the original issue discount, fees and expenses. The foregoing description of the Subordinated Notes does not purport to be complete and is qualified in its entirety by reference to the Unsecured Subordinated Credit Agreement dated as of September 7, 2007 (as amended on September 14, 2007) which is an exhibit to this report.

The Subordinated Notes contain no financial performance covenants, but contain affirmative and negative covenants, including limitations on incurring certain indebtedness, that are usual and customary for transactions of this type. As of December 31, 2007, we were in compliance with the covenants of the Subordinated Notes.

Common Stock Issuance

During 2007, we issued 5,000,000 shares of common stock and received net proceeds of approximately $226.7 million ($47.00 per share before underwriters discounts and commissions and offering expenses). We were required by the Existing Credit Agreement to apply $56.7 million of the $226.7 million net proceeds from our issuance of 5,000,000 shares of common stock to reduce the outstanding balance of our Term Loans.

Recently Issued Accounting Pronouncements

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

Contractual Obligations

The following table summarizes certain contractual obligations at December 31, 2007 (in thousands):

Contractual Obligations	Total		2008		2009 and 2010		2011 and 2012		After 5 Years
Long-term debt (1)	$	1,431,055	$	12,165	$	1,189,990	$	228,900	$	—
Interest on long-term debt (2)		279,948		125,681		138,150		16,117		—
Other trade commitments		94,000		—		94,000		—		—
Noncancelable operating leases		2,923		1,063		1,195		665		—
Total contractual obligations	$	1,807,926	$	138,909	$	1,423,335	$	245,682	$	—

(1) Long-term debt in future periods includes projected accretion of premium and amortization of discount.

(2) Interest is based on rates and principal repayments in effect at December 31, 2007.

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Our liabilities also include asset retirement obligations (“ARO”) ($28.2 million current and $158.6 million long-term) that represent the amount at December 31, 2007 of our obligations with respect to the retirement/plugging and abandonment of our oil and gas properties. 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, economic and operational factors. Consequently, ARO is not reflected in the table above.

Critical Accounting Policies and Estimates

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 and impairment of 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.

Oil and Gas Property Accounting

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. Development 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 offshore 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.

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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.

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 reservoir engineers’ 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. 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’ 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.

Oil and Gas Reserves

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.

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Asset Retirement Obligations

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 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 liability and asset 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 liability with the offset to the related capitalized asset on a prospective basis.

Contingent Liabilities

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, 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.

Price Risk-Management Activities

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 market exchanges, 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 to the extent the hedge is effective. For qualifying fair value hedges, the changes in the fair value of the derivative and of the hedged item attributable to the hedged risk offset each other in earnings. Gains and losses on hedging instruments included in accumulated other comprehensive income 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.

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Valuation of Deferred Tax Asset

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 also record a valuation allowance if it is more likely than not that some or all of a deferred tax asset will not be realized. 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.

Stock-Based Compensation

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.

Off-Balance Sheet Arrangements

The Company has no off-balance sheet arrangements at December 31, 2007.

Item 7A. Quantitative and Qualitative Disclosures about Market Risk.

Commodity Price Risk

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. 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 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.

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. We do not hold or issue derivative instruments for speculative purposes.

Interest Rate Risk

We are exposed to changes in interest rates. Changes in interest rates affect the amount of interest earned on our cash and cash equivalents and the interest paid on borrowings. In January 2008, we entered into an interest rate swap agreement on, initially, $500.0 million of long-term debt which locks the LIBOR portion of our interest rate at 3.1% until 2010.

46

Foreign Currency Risk

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.

In July 2007, we entered into a foreign currency swap agreement which locks in a $2.049 USD/GBP exchange rate. At December 31, 2007, the remaining notional amount of the swap was £18.0 million through March 2008.

Item 8. Financial Statements and Supplementary Data.

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

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

None.

Item 9A. Controls and Procedures.

Disclosure Controls and Procedures

Our management, with the participation of our principal executive officer and principal financial officer, evaluated the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) promulgated under the Securities Exchange Act of 1934, as amended (Exchange Act)) as of December 31, 2007. Based on this evaluation, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were not effective as a result of a material weakness in internal controls as of December 31, 2007 in ensuring that information that is required to be disclosed by us in the reports it files or submits under the Exchange Act is (i) recorded, processed, summarized and reported, within the time periods specified in the Securities and Exchange Commission’s rules and forms and (ii) accumulated and communicated to our management as appropriate to allow timely decisions regarding required disclosure.

Management’s Annual Report on Internal Control over Financial Reporting

Our management is responsible for establishing and maintaining effective internal control over financial reporting (as defined in Rule 13a-15(f) and 15d-15(f) promulgated under the Exchange Act). Even an effective system of internal control over financial reporting, no matter how well designed, has inherent limitations, including the possibility of human error, circumvention or overriding of controls and, therefore, can provide only reasonable assurance with respect to reliable financial reporting. Furthermore, the effectiveness of a system of internal control over financial reporting in future periods can change as conditions change.

Our management assessed the effectiveness of our internal control over financial reporting as of December 31, 2007. In making this assessment, it used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control - Integrated Framework. We have determined that a material weakness in our internal control over depreciation, depletion, amortization and impairment of oil and gas properties existed during the fourth quarter of 2007. The control deficiency resulted from the lack of effective detective and monitoring controls within internal control over financial reporting over these accounts. Solely as a result of this material weakness, we concluded that our disclosure controls and procedures were not effective as of December 31, 2007. We have taken and will take the following actions to enhance our internal controls: formalize the reconciliation, review and monitoring process related to depreciation, depletion, amortization and impairment, implement additional controls to ensure all significant reviews in this area are performed timely and accurately and add additional review processes as deemed necessary. Other than with respect to the identification of this weakness in internal control procedures, there was no change in our internal control over financial reporting during the quarter and year ended December 31, 2007 that materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

The report of our independent registered public accounting firm relating to the effectiveness of internal control over financial reporting is set forth in the accompanying financial statements.

47

Item 9A(T). Controls and Procedures.

Not applicable.

Item 9B. Other Information.

None.

48

PART III

Item 10. Directors, Executive Officers and Corporate Governance.

Executive Officers of the Company and Other Key Employees

Set forth below are the names, ages (as of February 29, 2008) and titles of the persons currently serving as executive officers of the Company. There are no term limits for the executive officers.

Name	Age	Position
T. Paul Bulmahn	64	Chairman and President
Albert L. Reese, Jr.	58	Chief Financial Officer
Leland E. Tate	60	Chief Operations Officer
John E. Tschirhart	57	Senior Vice President, International, General Counsel
Isabel M. Plume	47	Chief Communications Officer
Keith R. Godwin	40	Chief Accounting Officer

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.

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.

49

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

Isabel M. Plume has served as our Chief Communications Officer since 2004 and Corporate Secretary since 2003. Ms. Plume currently serves on the board of directors of ATP Oil & Gas (UK) Limited and ATP Oil and Gas (Netherlands) B.V. 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 9, 2008 (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.

Item 11. Executive Compensation.

Incorporated by reference to the Company’s Proxy Statement.

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

Incorporated by reference to the Company’s Proxy Statement.

50

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

Incorporated by reference to the Company’s Proxy Statement.

Item 14. Principal Accounting Fees and Services.

Incorporated by reference to the Company’s Proxy Statement.

51

PART IV

Item 15. Exhibits, Financial Statement Schedules.

(a) (1) and (2) Financial Statements and Financial Statement Schedules

See “Index to Consolidated Financial Statements” on page F-1.

(a) (3) Exhibits

3.1	Amended and Restated Articles of Incorporation, incorporated by reference to Exhibit 3.1 of Registration Statement No. 333-46034 on Form S-1 of ATP Oil & Gas Corporation (“ATP”).
3.2	Amended and Restated Bylaws of ATP, incorporated by reference to Exhibit 3.1 of ATP’s Report on Form 10-Q for the quarter ended September 30, 2006.
4.1	Warrant Shares Registration Rights Agreement dated as of March 29, 2004 between ATP and each of the Holders set forth on the execution pages thereof, incorporated by reference to Exhibit 4.5 of ATP’s Form 10-K for the year ended December 31, 2003.
4.2	Warrant Agreement dated as of March 29, 2004 by and among ATP and the Holders from time to time of the warrants issued hereunder, incorporated by reference to Exhibit 4.6 of ATP’s Form 10-K for the year ended December 31, 2003.
4.3	Rights Agreement dated October 11, 2005 between ATP and American Stock Transfer & Trust Company, as Rights Agent, specifying the terms of the Rights, which includes the form of Statement of Designations of Junior Participating Preferred Stock as Exhibit A, the form of Right Certificate as Exhibit B and the form of the Summary of Rights to Purchase Preferred Shares as Exhibit C, incorporated by reference to Exhibit 1 to the Company’s Registration Statement on Form 8-A filed with the Securities and Exchange Commission on October 14, 2005.
†10.1	ATP Oil & Gas Corporation 2000 Stock Plan, incorporated by reference to Exhibit 10.11 of ATP’s Form 10-K for the year ended December 31, 2000.
10.2	Third Amended and Restated Credit Agreement dated December 28, 2006 among ATP, the Lenders named therein and Credit Suisse (“CS”), as administrative and collateral agent incorporated by reference to Exhibit 10.2 of ATP’s Report on Form 10-K for the year ended December 31, 2006.
10.3	Amendment No. 1 and Agreement dated as of March 23, 2007 to the Third Amended and Restated Credit Agreement dated as of December 28, 2006, among ATP Oil & Gas Corporation, the lenders from time to time party thereto and CS, as administrative agent and as collateral agent for the Lenders, incorporated by reference to Exhibit 10.1 of ATP’s Form 8-K filed on March 23, 2007.
10.4	Unsecured Subordinated Credit Agreement dated as of September 7, 2007 (as amended on September 14, 2007), among ATP Oil & Gas Corporation, the lenders from time to time party thereto and CS, as administrative agent for such lenders, incorporated by reference to Exhibit 10.1 of ATP’s Form 8-K filed on September 7, 2007 and Exhibit 10.1 of ATP’s Form 8-K filed on September 14, 2007.
†10.5	Employment Agreement between ATP and Pauline H. van der Sman-Archer, dated December 29, 2005, incorporated by reference to Exhibit 10.1 to ATP’s Form 8-K dated December 30, 2005.
†10.6	Employment Agreement between ATP and John E. Tschirhart, dated December 29, 2005, incorporated by reference to Exhibit 10.2 to ATP’s Form 8-K dated December 30, 2005.
†10.7	Employment Agreement between ATP and Leland E. Tate, dated December 29, 2005, incorporated by reference to Exhibit 10.3 to ATP’s Form 8-K dated December 30, 2005.
†10.8	Employment Agreement between ATP and Robert M. Shivers, III, dated December 29, 2005, incorporated by reference to Exhibit 10.4 to ATP’s Form 8-K dated December 30, 2005.
†10.9	Employment Agreement between ATP and Mickey W. Shaw, dated December 29, 2005, incorporated by reference to Exhibit 10.5 to ATP’s Form 8-K dated December 30, 2005.
†10.10	Employment Agreement between ATP and Albert L. Reese, Jr., dated December 29, 2005, incorporated by reference to Exhibit 10.7 to ATP’s Form 8-K dated December 30, 2005.

52

†10.11	Employment Agreement between ATP and Isabel M. Plume, dated December 29, 2005, incorporated by reference to Exhibit 10.8 to ATP’s Form 8-K dated December 30, 2005.
†10.12	Employment Agreement between ATP and Scott D. Heflin, dated December 29, 2005, incorporated by reference to Exhibit 10.9 to ATP’s Form 8-K dated December 30, 2005.
†10.13	Employment Agreement between ATP and Keith R. Godwin, dated December 29, 2005, incorporated by reference to Exhibit 10.10 to ATP’s Form 8-K dated December 30, 2005.
†10.14	Employment Agreement between ATP and George Ross Frazer, dated December 29, 2005, incorporated by reference to Exhibit 10.11 to ATP’s Form 8-K dated December 30, 2005.
†10.15	Employment Agreement between ATP and T. Paul Bulmahn, dated December 29, 2005, incorporated by reference to Exhibit 10.12 to ATP’s Form 8-K dated December 30, 2005.
21.1	Subsidiaries of ATP, incorporated by reference to Exhibit 21.1 of ATP’s Annual Report on Form 10-K for the year ended December 31, 2002.
*23.1	Consent of Deloitte & Touche LLP.
*23.2	Consent of Ryder Scott Company, L.P.
*23.3	Consent of RPS Energy Limited.
*23.4	Consent of Collarini Associates.
*23.5	Consent of DeGolyer and MacNaughton.
*31.1	Certification of Principal Executive Officer pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934, the “Act.”
*31.2	Certification of Principal Financial Officer pursuant to Rule 13a-14(a) of the Act
*32.1	Certification of Principal Executive Officer pursuant to 18 U.S.C. Section 1350
*32.2	Certification of Principal Financial Officer pursuant to 18 U.S.C. Section 1350

* Filed herewith

† Management contract or compensatory plan or arrangement

53

SIGNATURES

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 7, 2008.

Signature	Title
/s/ T. Paul Bulmahn	Chairman, President and Director
T. Paul Bulmahn	(Principal Executive Officer)
/s/ Albert L. Reese, Jr.	Chief Financial Officer
Albert L. Reese, Jr.	(Principal Financial Officer)
/s/ Keith R. Godwin	Chief Accounting Officer
Keith R. Godwin	(Principal Accounting Officer)
/s/ Chris A. Brisack	Director
Chris A. Brisack
/s/ Arthur H. Dilly	Director
Arthur H. Dilly
/s/ Gerard J. Swonke	Director
Gerard J. Swonke
/s/ Robert C. Thomas	Director
Robert C. Thomas
/s/ Walter Wendlandt	Director
Walter Wendlandt
/s/ Burt A. Adams	Director
Burt A. Adams
/s/ Robert J. Karow	Director
Robert J. Karow
/s/ George R. Edwards	Director
George R. Edwards

54

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

	Page
Reports of Independent Registered Public Accounting Firm	F-2
Consolidated Balance Sheets as of December 31, 2007 and 2006	F-5
Consolidated Statements of Operations for the years ended December 31, 2007, 2006 and 2005	F-6
Consolidated Statements of Cash Flows for the years ended December 31, 2007, 2006 and 2005	F-7
Consolidated Statements of Shareholders’ Equity for the years ended December 31, 2007, 2006 and 2005	F-8
Consolidated Statements of Comprehensive Income (Loss) for the years ended December 31, 2007, 2006 and 2005	F-9
Notes to Consolidated Financial Statements	F-10
Supplemental Disclosures About Oil and Gas Producing Activities (Unaudited)	F-27
Schedule II – Valuation and Qualifying Accounts	S-1

F-1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of

ATP Oil & Gas Corporation

Houston, Texas

We have audited the accompanying consolidated balance sheets of ATP Oil & Gas Corporation and subsidiaries (the "Company") as of December 31, 2007 and 2006, 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, 2007. Our audits also included the financial statement schedule listed in the Index at Item 15. These financial statements and financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on the financial statements and financial statement schedule 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. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of ATP Oil & Gas Corporation and subsidiaries as of December 31, 2007 and 2006, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2007, 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.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company's internal control over financial reporting as of December 31, 2007, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 7, 2008 expressed an adverse opinion on the Company's internal control over financial reporting because of a material weakness.

/s/ DELOITTE & TOUCHE LLP

Houston, Texas

March 7, 2008

F-2

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of

ATP Oil & Gas Corporation

Houston, Texas

We have audited ATP Oil & Gas Corporation and subsidiaries’ (the “Company’s”) internal control over financial reporting as of December 31, 2007, 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 maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.

We conducted our audit 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 effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on that risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

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.

F-3

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.

A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the company’s annual or interim financial statements will not be prevented or detected on a timely basis. The following material weakness has been identified and included in management’s assessment: a material weakness in internal control related to depreciation, depletion, amortization and impairment of oil and gas properties existed during the fourth quarter of 2007. The control deficiency resulted from the lack of effective detective and monitoring controls within internal control over financial reporting over these accounts. This material weakness was considered in determining the nature, timing, and extent of audit tests applied in our audit of the consolidated financial statements and financial statement schedule as of and for the year ended December 31, 2007, of the Company and this report does not affect our report on such financial statements and financial statement schedule.

In our opinion, because of the effect of the material weakness identified above on the achievement of the objectives of the control criteria, the Company has not maintained effective internal control over financial reporting as of December 31, 2007, based on the criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements and financial statement schedule as of and for the year ended December 31, 2007, of the Company and our report dated March 7, 2008, expressed an unqualified opinion on those financial statements and financial statement schedules.

/s/ DELOITTE & TOUCHE LLP

Houston, Texas

March 7, 2008

F-4

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(In Thousands, Except Share Amounts)

	December 31,
	2007			2006
Assets
Current assets:
Cash and cash equivalents	$	199,449		$	182,592
Restricted cash		13,981			27,497
Accounts receivable (net of allowance of $382 and $409, respectively)		127,891			105,030
Deferred tax asset		84,110			1,113
Derivative asset		1,286			1,170
Other current assets		15,934			9,931
Total current assets		442,651			327,333
Oil and gas properties (using the successful efforts method of accounting):
Proved properties		2,468,523			1,483,163
Unproved properties		88,415			56,189
		2,556,938			1,539,352
Less accumulated depletion, impairment and amortization		(726,358	)		(443,707	)
Oil and gas properties, net		1,830,580			1,095,645
Furniture and fixtures (net of accumulated depreciation)		860			1,079
Derivative asset		673			—
Deferred financing costs, net		19,873			13,272
Other assets, net		12,496			9,729
Total assets	$	2,307,133		$	1,447,058
Liabilities and Shareholders’ Equity
Current liabilities:
Accounts payable and accruals	$	270,557		$	195,846
Current maturities of long-term debt		12,165			8,987
Capital lease		—			23,699
Asset retirement obligation		28,194			21,297
Derivative liability		11,335			—
Other current liabilities		23,512			—
Total current liabilities		345,763			249,829
Long-term debt		1,391,846			1,062,454
Asset retirement obligation		158,577			87,092
Deferred tax liability		85,256			11,765
Derivative liability		13,242			—
Other liabilities		2,583			—
Total liabilities		1,997,267			1,411,140
Commitments and contingencies (Note 11)
Shareholders’ equity:
Preferred stock: $0.001 par value, 10,000,000 shares authorized; none issued		—			—
Common stock: $0.001 par value, 100,000,000 shares authorized; 35,808,188 issued and 35,732,348 outstanding at December 31, 2007; 30,272,210 issued and 30,196,370 outstanding at December 31, 2006		36			30
Additional paid-in capital		388,250			151,467
Accumulated deficit		(92,061	)		(140,681	)
Accumulated other comprehensive income		14,552			26,013
Treasury stock		(911	)		(911	)
Total shareholders’ equity		309,866			35,918
Total liabilities and shareholders’ equity	$	2,307,133		$	1,447,058

See accompanying notes to the consolidated financial statements.

F-5

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(In Thousands, Except Per Share Amounts)

	Year Ended December 31,
	2007			2006			2005
Revenues:
Oil and gas production	$	599,324		$	414,182		$	146,674
Other revenues		8,611			5,639			—
		607,935			419,821			146,674
Costs, operating expenses and other:
Lease operating		91,693			72,446			23,629
Exploration		13,756			2,231			6,208
General and administrative		32,018			32,976			24,331
Depreciation, depletion and amortization		247,378			169,704			64,069
Impairment of oil and gas properties		34,342			19,520			—
Accretion of asset retirement obligation		12,117			8,076			3,238
(Gain) loss on abandonment		18,649			9,603			(732	)
Gain on disposition of properties		—			—			(2,743	)
Other, net		(3,706	)		(7	)		(419	)
		446,247			314,549			117,581
Income from operations		161,688			105,272			29,093
Other income (expense):
Interest income		7,603			4,532			4,064
Interest expense		(121,302	)		(58,018	)		(35,720	)
Loss on extinguishment of debt		—			(28,115	)		—
		(113,699	)		(81,601	)		(31,656	)
Income (loss) before income taxes		47,989			23,671			(2,563	)
Income tax (expense) benefit:
Current		1,179			(2,528	)		(4,102	)
Deferred		(548	)		(14,266	)		3,949
		631			(16,794	)		(153	)
Net income (loss)		48,620			6,877			(2,716	)
Preferred stock dividends		—			(46,225	)		(9,858	)
Net income (loss) available to common shareholders	$	48,620		$	(39,348	)	$	(12,574	)
Net income (loss) per common share – basic	$	1.58		$	(1.33	)	$	(0.43	)
Net income (loss) per common share –diluted	$	1.55		$	(1.33	)	$	(0.43	)
Weighted average number of common shares:
Basic		30,793			29,693			29,080
Diluted		31,301			29,693			29,080

See accompanying notes to the consolidated financial statements.

F-6

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In Thousands)

	Year Ended December 31,
	2007			2006			2005
Cash flows from operating activities
Net income (loss)	$	48,620		$	6,877		$	(2,716	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities –
Depreciation, depletion and amortization		247,378			169,704			64,069
Impairment of oil and gas properties		34,342			19,520			—
Gain on disposition of properties		—			—			(2,743	)
Accretion of asset retirement obligation		12,117			8,076			3,238
Deferred income taxes		548			14,266			(3,949	)
Dry hole costs		10,251			—			5,341
Amortization of deferred financing costs		7,547			5,985			4,173
Loss on extinguishment of debt		—			28,115			—
Stock-based compensation		7,108			11,477			57
Ineffectiveness of cash flow hedges		(74	)		(110	)		(189	)
Noncash interest expense		2,327			3,054			1,742
Other noncash items		13,693			(643	)		(1,075	)
Changes in assets and liabilities –
Accounts receivable and other current assets		(42,766	)		(24,904	)		(43,095	)
Accounts payable and accruals		(2,195	)		20,419			23,212
Other assets		(9,508	)		(3,322	)		(3,781	)
Other long-term liabilities and deferred obligations		—			—			(696	)
Net cash provided by operating activities		329,388			258,514			43,588
Cash flows from investing activities
Additions to oil and gas properties		(849,491	)		(577,012	)		(420,516	)
Proceeds from disposition of oil and gas properties		650			—			19,820
Decrease (increase) in restricted cash		14,096			(13,290	)		(12,476	)
Additions to furniture and fixtures		(348	)		(381	)		(900	)
Net cash used in investing activities		(835,093	)		(590,683	)		(414,072	)
Cash flows from financing activities
Proceeds from long-term debt		574,500			728,500			132,113
Payments of long-term debt		(244,287	)		(4,435	)		(3,175	)
Deferred financing costs		(14,148	)		(24,551	)		(10,416	)
Issuance of common stock, net of issuance costs		226,706			—			—
Issuance of preferred stock, net of issuance costs		—			145,463			169,437
Redemption of preferred stock		—			(381,083	)		—
Proceeds from capital lease		—			—			44,774
Payments of capital lease		(23,950	)		(20,869	)		(1,658	)
Exercise of stock options		2,974			4,966			4,507
Other		—			—			(68	)
Net cash provided by financing activities		521,795			447,991			335,514
Effect of exchange rate changes on cash and cash equivalents		767			1,204			(2,238	)
Increase (decrease) in cash and cash equivalents		16,857			117,026			(37,208	)
Cash and cash equivalents, beginning of period		182,592			65,566			102,774
Cash and cash equivalents, end of period	$	199,449		$	182,592		$	65,566

See accompanying notes to the consolidated financial statements.

F-7

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY

(In Thousands)

	2007				2006					2005
	Shares	Amount			Shares		Amount			Shares	Amount
Preferred Stock
Balance, beginning of year	—	$	—		175		$	184,858		—	$	—
Issuance of preferred stock	—		—		150			150,000		175		175,000
Preferred dividends	—		—		—			46,225		—		9,858
Redemption of preferred stock	—		—		(325	)		(381,083	)	—		—
Balance, end of year	—	$	—		—		$	—		175	$	184,858
Common Stock
Balance, beginning of year	30,196	$	30		29,592		$	29		28,884	$	29
Issuances of common stock
Secondary offering	5,000		5		—			—		—		—
Exercise of stock options/warrants	302		1		503			1		443		—
Restricted stock	234		—		101			—		265		—
Balance, end of year	35,732	$	36		30,196		$	30		29,592	$	29
Paid-in Capital
Balance, beginning of year		$	151,467				$	139,561			$	140,628
Issuance of capital stock
Secondary offering			226,702					—				—
Exercise of stock options/warrants			2,973					4,966				4,504
Preferred stock offering costs			—					(4,537	)			(5,628	)
Stock-based compensation			7,108					11,477				57
Balance, end of year		$	388,250				$	151,467			$	139,561
Accumulated Deficit
Balance, beginning of year		$	(140,681	)			$	(101,333	)		$	(88,759	)
Net income (loss)			48,620					6,877				(2,716	)
Preferred dividends			—					(46,225	)			(9,858	)
Balance, end of year		$	(92,061	)			$	(140,681	)		$	(101,333	)
Accumulated Other Comprehensive Income (Loss)
Balance, beginning of year		$	26,013				$	(4,693	)		$	6,177
Other comprehensive income (loss)			(11,461	)				30,706				(10,870	)
Balance, end of year		$	14,552				$	26,013			$	(4,693	)
Treasury Stock
Balance, beginning of year	76	$	(911	)	76		$	(911	)	76	$	(911	)
Balance, end of year	76	$	(911	)	76		$	(911	)	76	$	(911	)
Total Shareholders’ Equity		$	309,866				$	35,918			$	217,511

See accompanying notes to the consolidated financial statements.

F-8

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(In Thousands)

	Year Ended December 31,
	2007			2006			2005
Net income (loss)	$	48,620		$	6,877		$	(2,716	)
Other comprehensive income (loss):
Reclassification adjustment for settled hedge contracts (net of taxes of $(271), $0 and $0, respectively)		888			4,391			5
Change in fair value of outstanding hedge positions (net of taxes of $15,281, $0 and $0, respectively)		(17,266	)		(4,080	)		(1,759	)
Foreign currency translation adjustment		4,917			30,395			(9,116	)
Other comprehensive income (loss)		(11,461	)		30,706			(10,870	)
Comprehensive income (loss)	$	37,159		$	37,583		$	(13,586	)

F-9

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1 — Organization and Basis of Presentation

Organization

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 may not be strategic to major or exploration-oriented independent oil and gas companies.

Basis of Presentation

The consolidated financial statements include our accounts and our wholly-owned subsidiaries, ATP Energy, Inc., 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.

Note 2 — Summary of Significant Accounting Policies

Use of Estimates

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

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.

Restricted Cash

The Company’s restricted cash represents a time deposit denominated in Pounds Sterling which secures an irrevocable stand-by letter of credit for our future abandonment obligation with respect to the Wenlock property in the North Sea.

Oil and Gas Properties

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

F-10

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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.

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 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 net cash flows and fair value. We recorded impairments during the years ended December 31, 2007, 2006 and 2005, totaling $34.1 million, $18.5 million and $0, respectively, on certain proved properties, primarily due to unfavorable operating performance resulting in downward revisions of recoverable reserves. Impairments of unproved properties were $0.2, $1.0 million and $0 during 2007, 2006, 2005, respectively, related to surrendered leases.

Asset Retirement Obligation

We recognize liabilities associated with the eventual retirement of tangible long-lived assets, upon the acquisition, construction and development of the 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.

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. During the second half of 2007, vendor prices for services and equipment related to asset retirement operations in the Gulf of Mexico increased significantly relative to expectations. Consequently, we revised our estimates of retirement costs for our oil and gas properties. The following table sets forth a reconciliation of the beginning and ending asset retirement obligation (in thousands):

	December 31,
	2007			2006			2005
Asset retirement obligation, beginning of year	$	108,389		$	67,364		$	24,923
Liabilities incurred		31,471			34,984			43,685
Liabilities settled		(19,941	)		(2,998	)		(3,730	)
Accretion expense		12,117			8,076			3,238
Foreign currency translation		874			2,570			(525	)
Changes in estimates		53,861			(1,607	)		217
Liabilities settled – assets sold		—			—			(444	)
Asset retirement obligation, end of year	$	186,771		$	108,389		$	67,364

F-11

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Capitalized Interest

Interest costs during the development phase of certain long-term assets are capitalized and amortized over the related assets’ estimated useful lives. During 2007, we capitalized $8.0 million of 2007 interest costs to oil and gas properties related to the construction of a floating drilling and production system at our Telemark development in the Gulf of Mexico. No interest was capitalized during 2006 and 2005.

Furniture and Fixtures

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.

Deferred Financing Costs

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

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.

Revenue Recognition

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.

Concentration of Credit Risk

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.

F-12

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Major Customers

For the year ended December 31, 2007, revenues from four purchasers accounted for 36%, 18%, 16% and 11%, respectively, of oil and gas production revenues. 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. A substantial portion of our oil and gas production revenues in the North Sea are from one customer.

Translation of Foreign Currencies

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 currency of a particular entity. At December 31, 2007, accumulated other comprehensive income included $31.9 million of gain related to cumulative foreign currency translation adjustments.

Income Taxes

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.

Stock-based Compensation

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 2005, 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 year ended 2005 (in thousands, except for per-share data):

Net loss available to common shareholders, as reported	$	(12,574	)
Total stock-based employee compensation benefit determined under fair value for all awards, net of related tax effects		(350	)
Pro forma net loss	$	(12,924	)
Loss per share:
Basic and diluted – as reported	$	(0.43	)
Basic and diluted – pro forma		(0.44	)

F-13

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Fair Value of Financial Instruments

For cash and cash equivalents, receivables and payables, the carrying amounts approximate fair value because of the short maturity of these instruments. Most of our long-term debt is market-variable rate debt and as such, book value approximates fair value.

Derivative Instruments

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 market exchanges, 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 changes in the fair value of the derivative and of the hedged item attributable to the hedged risk offset each other in earnings. Gains and losses on hedging instruments included in accumulated other comprehensive income 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 earnings. At December 31, 2007 and 2006, accumulated other comprehensive income (loss) included $17.3 million and $1.0 million of unrealized losses on our cash flow hedges, respectively.

From time to time, we utilize foreign currency and interest rate derivative instruments to mitigate risks associated with our foreign operations and borrowings, respectively.

Note 3 — Recently Issued Accounting Pronouncements

During December 2007, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements-an amendment of ARB No. 51,” (“SFAS No. 160”), which causes noncontrolling interests in subsidiaries to be included in the equity section of the balance sheet. SFAS No. 160 is effective for periods beginning on or after December 15, 2008. This standard does not presently affect our financial statements.

During December 2007, the FASB issued SFAS No. 141(R), “Business Combinations,” (“SFAS No. 141(R)”), which establishes new accounting and disclosure requirements for recognition and measurement of identifiable assets, liabilities and goodwill acquired and requires that the fair value estimates of contingencies acquired or assumed be considered as part of the original purchase price allocation. SFAS No. 141(R) is effective for periods beginning on or after December 15, 2008. This standard does not presently affect our financial statements.

During February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities including an amendment of FASB Statement No. 115.” The new standard permits an entity to make an irrevocable election to measure most financial assets and financial liabilities at fair value. The fair value option may be elected on an instrument-by-instrument basis, with a few exceptions. Changes in fair value would be recorded in income. SFAS No. 159 establishes presentation and disclosure requirements intended to help financial statement users understand the effect of the entity’s election on earnings. SFAS No. 159 is effective as of the beginning of the first fiscal year beginning after November 15, 2007. We will not elect the fair value accounting permitted by this standard.

F-14

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

During September 2006, the FASB issued SFAS No. 157, ‘Fair Value Measurements.” SFAS No. 157 provides a definition of fair value and provides a framework for measuring fair value. The standard also requires additional disclosures on the use of fair value in measuring assets and liabilities. SFAS No. 157 establishes a fair value hierarchy and requires disclosure of fair value measurements within that hierarchy. In February 2008, the FASB issued a Staff Position on SFAS No. 157, FASB Staff Position No. FAS 157-2, “Effective Date of FASB Statement No. 157,’ (FSP 157-2). FSP 157-2 delays the effective date of SFAS No. 157 for all nonrecurring fair value measurements of nonfinancial assets and nonfinancial liabilities until fiscal years beginning after November 15, 2008, except as provided by FSP 157-2. SFAS No. 157 is effective for fiscal years beginning after November 15, 2007 and interim periods within those years. FSP 157-2 requires an entity that does not adopt SFAS No. 157 in its entirety to disclose, at each reporting date until fully adopted, that it has only partially adopted SFAS No. 157 and the categories of assets and liabilities recorded or disclosed at fair value to which SFAS No. 157 has not been applied. The adoption of SFAS No. 157 is not expected to have a material impact on our financial statements, but will result in additional disclosures related to the use of fair values in the financial statements.

Note 4 — Supplemental Disclosures of Cash Flow Information

Supplemental disclosures of cash flow information (in thousands):

	Year Ended December 31,
	2007		2006		2005
Cash paid during the year for interest	$	106,410	$	42,748	$	28,085
Cash paid during the year for income taxes	$	8,325	$	5	$	—

During 2007, we acquired two oil and gas properties, a significant portion of the consideration for which was noncash.

Note 5 — Acquisitions

Gulf of Mexico

During 2007, we acquired undeveloped and developed minerals in place for an aggregate net purchase price of $40.6 million. Significant acquisitions are discussed below.

During January 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 interest in the Canyon Express Pipeline Common System (“Canyon Express”). Both Aconcagua and Camden Hills, along with MC Block 217 (“King’s Peak”) produce through Canyon Express. During December 2007, we increased our ownership in Camden Hills by 50.03% in exchange for the assumption of future abandonment liability for which the seller is obligated to pay ATP a total of $12.5 million upon abandonment of the property. Consequently, we recognized a $10.8 million long-term receivable, an asset retirement obligation of $8.3 million and $2.6 million of deferred revenue. As a result of the acquisitions, we now hold a 66.7% working interest in Camden Hills and a 55.09% working interest in the Canyon Express where we are the operator.

During January 2007, we completed the acquisition of a 100% working interest in the northwest quarter of MC Block 755 (“Anduin”), a 50% working interest in MC Block 754 (“Anduin West”), and a 25% working interest in MC Block 800 (“Gladden”). These properties are located in the vicinity of the MC Block 711 (“Gomez”) development and, if successful, are expected to produce through the ATP Innovator floating production facility. A portion of the acquisition price of one property was financed by granting an interest in the future net profits of that property.

Other acquisitions in 2007 included Ship Shoal Block 350 and additional interests at South Timbalier Block 77 and High Island Block 74. During August 2007, we were the apparent high bidder and we subsequently acquired a 100% working interest in High Island Block A-580 and East Breaks Block 563 at the MMS offshore lease sale. At the October 2007 MMS lease sale we were the apparent high bidder on two blocks, De Soto Canyon Block 355, immediately east of the Canyon Express area, and Viosca Knoll Block 863. Both of these blocks were subsequently awarded to ATP.

F-15

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

During 2006, we purchased minerals in place for $30.0 million. 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 quarters of 2006, we acquired a 100% working interest in MC Block 941, MC Block 942 and Atwater Valley Block 63.

At Ship Shoal Block 351, we increased our ownership from 50% to 100% in exchange for the assumption of future abandonment liability. We hold a 100% working interest and serve as operator at Ship Shoal Block 351.

North Sea

During the fourth quarter of 2006, we 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.

Note 6 — Long-term Debt and Leases

Long-term debt

Long-term debt consisted of the following (in thousands):

	December 31,
	2007			2006
First Lien Term Loans	$	1,202,154		$	896,441
Second Lien Term Loans		—			175,000
Subordinated Notes (includes accreted premium of $1,523; net of unamortized discount of $9,666)		201,857			—
Total		1,404,011			1,071,441
Less current maturities		(12,165	)		(8,987	)
Total long-term debt	$	1,391,846		$	1,062,454

During March 2007, ATP, Credit Suisse (as Administrative Agent and Collateral Agent for the lenders) and the lenders named therein entered into Amendment No. 1 and Agreement (the “Amendment”) amending the Third Amended and Restated Credit Agreement (the “Existing Credit Agreement” or “Term Loans”). The Amendment changed the total amount borrowed and the interest rate to LIBOR plus 3.5%. New borrowings under the Existing Credit Agreement were $375.0 million which were used to repay the $175.0 million outstanding borrowings under our former second lien term loan facility, which bore interest at LIBOR plus 4.75%, and to pay financing costs of $8.4 million. The net proceeds of the new Term Loans were used primarily for oil and gas development activities. The interest rate on outstanding borrowings at December 31, 2007 was approximately 8.5% per annum. In January 2008, we entered into an interest rate swap on initially $500.0 million of long-term debt which locks the LIBOR portion of our interest rate at 3.1% per annum until 2010.

Under the Existing Credit Agreement, we have a $50.0 million revolving credit facility (“Revolver”), all of which was available as of December 31, 2007.

During September 2007, the Company, Credit Suisse (as Administrative Agent for the lenders) and the lenders named therein entered into an Unsecured Subordinated Credit

F-16

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Agreement (the “Subordinated Notes”) for aggregate borrowings of $210.0 million. The borrowings bear annual interest at 11.25%, payable quarterly, and mature in September 2011. Such borrowings are subordinated to the borrowings under the Existing Credit Agreement and may be prepaid at any time at the option of the Company, subject to limitations set forth in the Existing Credit Agreement. The Company has assumed the debt will be paid off at maturity and accordingly recognizes over the term of the facility additional noncash interest expense related to deferred financing costs, an original issue discount and a sliding-scale redemption premium. If held to maturity, the aggregate average effective interest rate on the Subordinated Notes is approximately 15.3% per annum. The Company received net proceeds from the issuance of the Subordinated Notes of $193.8 million after deducting $16.2 million for the original issue discount, fees and expenses. The Subordinated Notes contain no financial performance covenants, but contain affirmative and negative covenants, including limitations on incurring certain indebtedness, that are usual and customary for transactions of this type.

Our Term Loans are 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. and were guaranteed by our wholly owned subsidiary ATP Energy, Inc. The combined effective interest rate on all outstanding borrowings under the Existing Credit Agreement and the Subordinated Notes at December 31, 2007 was approximately 9.2% per annum.

As of December 31, 2007, we were in compliance with the covenants of our credit agreements. 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 noncompliance with these covenants. An event of noncompliance with any of the required covenants could result in a material mandatory repayment under the Existing Credit Agreement and the Subordinated Notes.

Operating Leases

We have commitments under various administrative and other operating lease agreements. Total rent expense for the years ended December 31, 2007, 2006 and 2005 was approximately $0.9 million, $0.7 million and $0.6 million, respectively. At December 31, 2007, the future minimum rental payments due under operating leases are as follow (in thousands):

Year Ending December 31:
2008	$	1,063
2009		709
2010		486
2011		499
2012		166
Thereafter		—
Total	$	2,923

Note 7 — Equity

Preferred Stock

During 2005 and 2006, we issued preferred stock totaling $325.0 million (before issuance costs). During November 2006, we redeemed the preferred stock.

F-17

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Rights Plan

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 $0.001 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 $0.001 per share (the “Preferred Shares”), of the Company at a price of $150 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.

Common Stock

During 2007, we issued 5,000,000 shares of common stock and received net proceeds of approximately $226.7 million ($47.00 per share before underwriters discounts and commissions and offering expenses). We were required by the Existing Credit Agreement to apply $56.7 million of the $226.7 million net proceeds from our issuance of 5,000,000 shares of common stock to reduce the outstanding balance of our Term Loans.

Warrants

At December 31, 2007 and 2006, there were 350,333 and 525,499, respectively, warrants outstanding to purchase common stock at $7.25, which will expire in March 2010.

Note 8 — Stock and Other Compensation Plans

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 $1.7 million, $1.8 million and $0 for the years ended December 31, 2007, 2006 and 2005, respectively.

The fair values of options granted during the years ended December 31, 2007, 2006 and 2005 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:

	Year Ended December 31,
	2007			2006			2005
Weighted average volatility		36	%		51	%		49	%
Expected term (in years)		3.8			3.8			2.5
Risk-free rate		4.0	%		4.6	%		3.7	%
Weighted average fair value of options – grant date	$	15.22		$	16.21		$	6.68

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 expected term of the options granted in 2007 and 2006 is estimated using the simplified method because they are homogeneous and the Company has insufficient option exercise history to refine its expectations. The expected term of the options granted in 2005 was based on the weighted average remaining period to vest of the outstanding options. The risk-free rate for periods within the

F-18

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

contractual life of the options is based on the comparable U.S. Treasury rates in effect at the time of each grant. The aggregate intrinsic values of options exercised during the years ended December 31, 2007, 2006 and 2005 were $4.2 million, $14.9 million and $11.9 million, respectively. The following table sets forth a summary of option transactions for the year ended December 31, 2007:

	Number of Options		Weighted Average Grant Price		Aggregate Intrinsic Value (1) ($000)		Weighted Average Remaining Contractual Life
							(in years)
Outstanding at beginning of year	693,851		$	24.76
Granted	313,750			46.31
Exercised	(152,781	)		19.47
Forfeited	(54,751	)		30.52
Outstanding at end of year	800,069			33.83	$	13,555	3.43
Vested and expected to vest	732,739			33.71	$	12,494	3.20
Options exercisable at end of year	137,102			24.25	$	3,605	2.51

(1) Based upon the difference between the market price of the common stock on the last trading day of the year and the option exercise price of in-the-money options.

A summary of the status of ATP’s nonvested stock options as of December 31, 2007 and changes during the year is presented below:

	Number of Options		Weighted Average Grant-date Fair Value
Nonvested at beginning of year	586,051		$	8.37
Granted	313,750
Vested	(182,083	)
Forfeited	(54,751	)
Nonvested at end of year	662,967			11.63

At December 31, 2007, unrecognized compensation expense related to nonvested stock option grants totaled $4.5 million. Such unrecognized expense will be recognized as vesting occurs over a weighted average period of 2.7 years.

Restricted stock grants vest over a three-year period, are 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. During the years ended December 31, 2007, 2006 and 2005, we recognized aggregate compensation expense of $5.4 million, $9.6 million and $0, respectively, related to outstanding restricted stock grants.

The following table sets forth the changes in nonvested restricted stock for the year ended December 31, 2007:

	Number of Shares		Weighted Average Grant-date Fair Value		Aggregate Intrinsic Value (1) ($000)
Nonvested at beginning of year	233,502		$	38.03
Granted	249,887			46.19
Forfeited	(16,000	)		43.27
Vested	(161,600	)		39.23
Nonvested at end of year	305,789			43.79	$	15,455

(1) Based upon the closing market price of the common stock on the last trading day of the year.

F-19

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

At December 31, 2007, unrecognized compensation expense related to restricted stock totaled $9.3 million. Such unrecognized expense will be recognized as vesting occurs over a weighted average period of 2.2 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 $269,000, $218,000 and $190,000 for the years ended December 31, 2007, 2006 and 2005, 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, 2007, 2006 and 2005, we contributed approximately $28,000, $22,000 and $20,000, respectively.

Note 9 — Earnings Per Share

Basic earnings per share (“EPS”) is computed by dividing net income or loss available to common shareholders by the weighted average number of shares of common stock (other than unvested restricted stock) outstanding during the period. Weighted average shares outstanding for diluted EPS also includes a hypothetical number of shares assuming all in-the-money options and warrants would have been exercised and vesting of restricted stock. 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 as their effect is antidilutive. In the table below, stock-based awards for 103,000, 709,000 and 1,086,000 average shares of common stock for the years ended December 31, 2007, 2006 and 2005, respectively, were excluded from the diluted EPS calculation because their inclusion would have been antidilutive.

F-20

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

	Year Ended December 31,
	2007		2006			2005
Income
Net income (loss)	$	48,620	$	6,877		$	(2,716	)
Less preferred dividends		—		(46,225	)		(9,858	)
Net income (loss) available to common shareholders	$	48,620	$	(39,348	)	$	(12,574	)
Shares outstanding
Weighted average shares outstanding - basic		30,793		29,693			29,080
Effect of potentially dilutive securities - stock options and warrants		453		—			—
Unvested restricted stock		55		—			—
Weighted average shares outstanding - diluted		31,301		29,693			29,080
Per share data:
Net income (loss) available to common shareholders - basic	$	1.58	$	(1.33	)	$	(0.43	)
Net income (loss) available to common shareholders - diluted	$	1.55	$	(1.33	)	$	(0.43	)

Note 10 — Income Taxes

Income tax (expense) benefit consisted of the following (in thousands):

	Year Ended December 31,
	2007			2006			2005
Current:
Federal	$	161		$	(570	)	$	(77	)
Foreign		1,018			(1,958	)		(4,025	)
		1,179			(2,528	)		(4,102	)
Deferred:
Federal	$	(22,380	)	$	(4,108	)	$	(517	)
Foreign		70			(15,460	)		224
		(22,310	)		(19,568	)		(293	)
Valuation allowance		21,762			5,302			4,242
Total (expense) benefit	$	631		$	(16,794	)	$	(153	)

Income (loss) before income taxes consisted of the following (in thousands):

	Year Ended December 31,
	2007			2006		2005
Domestic	$	58,259		$	1,506	$	(9,759	)
Foreign		(10,270	)		22,165		7,196
	$	47,989		$	23,671	$	(2,563	)

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

	Year Ended December 31,
	2007		2006		2005
Statutory federal income tax rate	35.00	%	35.00	%	(35.00	)%
Nondeductible and other	1.87		9.97		56.95
Foreign operations	7.17		46.73		149.61
Valuation allowance	(45.35	)	(20.75	)	(165.61	)
	(1.31	)%	70.95	%	5.95	%

Significant components of our deferred tax assets (liabilities) as of December 31, 2007 and 2006 are as follow (in thousands):

	December 31,
	2007			2006
Current deferred:
Deferred income tax assets:
Net operating loss carry forwards	$	78,826		$	—
AMT credit		515			—
Foreign operations		5,978			1,113
Other		1,816			—
Total current deferred income tax assets		87,135			1,113
Less valuation allowance		(3,025	)		—
Net current deferred income tax assets	$	84,110		$	1,113
Noncurrent deferred:
Deferred income tax assets:
Net operating loss carry forwards	$	—		$	40,605
AMT credit		—			676
Stock-based compensation expense		2,074			2,086
Foreign operations		259,737			164,498
Revenue recognition contingency		—			1,879
Asset retirement obligations		5,913			—
Other		1,530			895
Total deferred income tax assets		269,254			210,639
Less valuation allowance		—			(25,126	)
Net noncurrent deferred income tax asset		269,254			185,513
Deferred income tax liabilities:
Fixed asset basis differences		(84,897	)		(18,522	)
Asset retirement obligations		—			(614	)
Foreign operations		(268,971	)		(178,142	)
Other		(642	)		—
Net noncurrent deferred income tax liability	$	(85,256	)	$	(11,765	)

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. In prior years we recorded a valuation allowance to give effect to our judgment that it was more likely than not that some portion or all of our net U.S. deferred tax assets were expected not to be realized in future periods. We continued to carry the valuation allowance based on relevant accounting guidance that suggests that a history of recent losses constitutes significant negative evidence that such deferred tax assets will not be recoverable, and that future expectations at that time about income were overshadowed by such history of losses. As of December 31, 2007, for U.S. tax provision purposes all of our valuation allowance has been released except the portion related to our excess tax benefits from stock options and restricted stock prior to implementation of SFAS No. 123(R). Additionally, the deferred tax asset related to the U.S. net operating loss carry forwards (“NOLs”) as disclosed does not include an additional $19.5 million of net operating loss as we anticipate we will include this amount in our 2007 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, 2007. We have no valuation allowance related to our foreign operations as a result of the taxable income generated by those entities.

F-21

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

At December 31, 2007 and 2006, we had net operating loss carry forwards (“NOLs”) for financial statement purposes of approximately $225.2 million and $116.0 million, respectively, which are available to offset future taxable income through 2027. ATP (UK) had NOL’s of $496.0 million and $329.0 million available for corporate tax carry-back at December 31, 2007 and 2006 respectively which are presented in Foreign Operations above.

The adoption of FIN No. 48 above had no material effect on our consolidated financial position or results of operations. The Company and its subsidiaries file income tax returns in the United States federal jurisdiction, two states, the United Kingdom and the Netherlands. Our open tax years in our major jurisdictions are from 2001 to current. We will record to the income tax provision any interest and penalties related to unrecognized tax positions.

In prior years we provided for an uncertainty that relates to a disagreement with the Dutch tax authorities in regard to the timing of the recognition of taxable income on certain cash receipts in 2002. Upon the adoption of FIN No. 48 on January 1, 2007, the amount of the uncertain tax position represented the difference between the tax filing position and the amounts provided for in current liabilities in the accompanying financial statements. In late 2007, we reached agreement with the Dutch tax authorities regarding this uncertainty and the Netherlands income tax provision reflects the agreed-upon settlement at year end. As of December 31, 2007 we had accrued $0.4 million, representing interest on uncertain tax positions. The following table sets forth the changes in our uncertain tax positions for the year ended December 31, 2007 (in thousands):

Balance at January 1, 2007	$	3,831
Decreases based on tax positions taken in prior years		(132	)
Decreases due to settlements with tax authorities		(3,699	)
Balance at December 31, 2007	$	—

F-22

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 11 — Commitments and Contingencies

During 2005, Hurricanes Rita and Katrina caused minimal direct damage to most of our platforms with some platforms, primarily in the Western Gulf, sustaining no damage. In addition, we lost potential revenues due to shut-in production resulting from the storms. ATP has reached final settlement with our underwriters on all claims related to these hurricanes. For the year ended December 31, 2007, ATP recognized $8.6 million of revenues from proceeds realized under our Loss of Production Income (“LOPI”) insurance policies. Such amounts are included in other revenues.

We are a party to a multi-year (life of reserves) firm transportation agreement covering certain production in the North Sea that requires us to pay a pipeline tariff on our nominated contract quantity of natural gas during the contract period, whether or not the volumes are delivered to the pipeline. For any contract period where actual deliveries fall short of contract quantities, we can make up such amounts by delivering volumes over the subsequent four years free of tariff, within certain limitations. While we control our nominations, we are subject to the risk we may be required to prepay or ultimately pay transportation on undelivered volumes.

In the normal course of business, we acquire proved properties with little or no upfront costs, but with a commitment to make payments out of future production, if any. As initial production or designated production levels are achieved, the contingent consideration is accrued and capitalized to the appropriate property. At December 31, 2007, our aggregate exposure under such arrangements totaled approximately $39.6 million, and included net profits interest payable, including accrued interest, of approximately $23.5 million, representing the present value of amounts expected ultimately to be paid from future production of the properties.

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.

Note 12 — Derivative Instruments and Price Risk Management Activities

At December 31, 2007, we had oil and natural gas derivatives that qualified as cash flow hedges with respect to our future production as follows:

Description	Type	Volumes	Price		Net Fair Value Asset (Liability)
			$/Unit		($000)
Oil (Bbls) – Gulf of Mexico
2008	Puts	2,488,800	$	54.67	$	74
2009	Puts	1,496,500		54.00		673
Natural Gas (MMBtu) – North Sea
2008	Swaps	5,599,000	$	8.51	$	(11,335	)
2009	Swaps	4,316,250		8.35		(13,242	)

F-23

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

We also manage our exposure to oil and natural gas price risks by periodically entering into fixed-price forward sale contracts. These physical contracts qualified and have been designated for the normal purchase and sale exemption under SFAS No. 133, as amended.

At December 31, 2007, we had fixed-price contracts in place for the following natural gas and oil volumes:

Period	Volumes	Average Fixed Price (1)
Natural gas (MMBtu)		$	/Unit
Gulf of Mexico:
2008	13,188,000	$	8.30
2009	8,175,000		8.04
North Sea:
2008	16,460,000	$	8.22
2009	2,700,000		8.46
Oil (Bbl) – Gulf of Mexico:
2008	4,360,000	$	76.26
2009	2,736,750		76.01
2010	365,000		68.20
2011	273,000		68.20
(1)    Includes the effect of basis differentials.

In July 2007, we entered into a foreign currency swap agreement which locks in a $2.049 USD/GBP exchange rate. At December 31, 2007, the remaining notional amount of the swap was £18.0 million through March 2008 and was fair valued at $1.2 million.

In January 2008, we entered into an interest rate swap on, initially, $500.0 million of long-term debt which locks the LIBOR portion of our interest rate at 3.1% until 2010.

Note 13 — Segment Information

The Company’s operations are focused in the Gulf of Mexico and in the North Sea. Management reviews and evaluates separately the operations 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. Segment activity for the years ended December 31, is as follows (in thousands):

F-24

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

	Gulf of Mexico			North Sea		Eliminations			Total
2007
Revenues	$	502,904		$	105,031		—		$	607,935
Depreciation, depletion and amortization		184,808			62,570		—			247,378
Impairment of oil and gas properties		25,370			8,972		—			34,342
Income from operations		154,411			7,277		—			161,688
Interest income		25,150			2,319		(19,866	)		7,603
Interest expense		121,302			19,866		(19,866	)		121,302
Income tax (expense) benefit		(457	)		1,088		—			631
Additions to oil and gas properties		768,773			253,161		—			1,021,934
Total assets		1,666,821			640,312		—			2,307,133
2006
Revenues	$	327,609		$	92,212		—		$	419,821
Depreciation, depletion and amortization		126,708			42,996		—			169,704
Impairment of oil and gas properties		19,520			—		—			19,520
Income from operations		80,368			24,904		—			105,272
Interest income		7,231			705		(3,404	)		4,532
Interest expense		57,978			3,444		(3,404	)		58,018
Loss on extinguishment of debt		28,115			—		—			28,115
Income tax expense		570			16,224		—			16,794
Additions to oil and gas properties		379,712			281,639		—			661,351
Total assets		983,147			463,911		—			1,447,058
2005
Revenues	$	135,175		$	11,499	$	—		$	146,674
Depreciation, depletion and amortization		59,144			4,925		—			64,069
Income from operations		22,080			7,013		—			29,093
Interest income		3,879			185		—			4,064
Interest expense		35,718			2		—			35,720
Income tax expense		78			75		—			153
Additions to oil and gas properties		296,060			124,456		—			420,516
Total assets		610,250			213,513		—			823,763

F-25

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 14 — Summarized Quarterly Financial Data (Unaudited)

(In Thousands, Except Per Share Amounts)

	First Quarter			Second Quarter		Third Quarter		Fourth Quarter
2007
Revenues	$	146,347		$	132,153	$	116,738	$	212,697
Costs, expenses and other (1)		87,005			98,686		89,476		171,080
Income from operations (1)		59,342			33,467		27,262		41,617
Net income available to common shareholders (1)		27,434			6,125		2,321		12,740
Net income per common share:
Basic (2)	$	0.89		$	0.20	$	0.08	$	0.39
Diluted (2)	$	0.92		$	0.20	$	0.08	$	0.38
2006
Revenues	$	45,245		$	108,885	$	132,822	$	132,869
Costs and expenses		37,691			77,372		101,701		97,792
Income from operations		7,554			31,513		31,121		35,077
Net income (loss) available to common shareholders (3)(4)		(9,863	)		6,374		1,173		(37,032	)
Net income (loss) per common share:
Basic and diluted (2)	$	(0.34	)	$	0.21	$	0.04	$	(1.24	)

(1)    Included here is an $18.3 million loss on abandonment in the fourth quarter.

(2)    The sum of the per share amounts per quarter does not equal the total for the year due to changes in the average number of common shares outstanding.

(3)    Net income (loss) available to common shareholders for the fourth quarter 2006 includes approximately $28.1 million of loss on extinguishment of debt and approximately $9.3 million of preferred stock redemption premium.

(4)    Net income (loss) available to common shareholders is net of preferred dividends of $6.8 million in the first quarter, $11.0 million in the second quarter, $11.5 million in the third quarter and $7.6 million in the fourth quarter. The preferred stock was redeemed in November 2006.

F-26

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

SUPPLEMENTAL DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES

Oil and Gas Reserves and Related Financial Data (Unaudited)

Costs Incurred

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, 2007, 2006 and 2005 (in thousands):

	Gulf of Mexico			North Sea		Total
2005
Property acquisition costs:
Proved	$	62,117		$	7,034	$	69,151
Unproved		5,790			—		5,790
Development costs		231,703			125,941		357,644
Exploratory costs		21,989			—		21,989
Oil and gas expenditures		321,599			132,975		454,574
Asset retirement costs		37,494			6,406		43,900
Gain on abandonment		(732	)		—		(732	)
	$	358,361		$	139,381	$	497,742
2006
Property acquisition costs:
Proved	$	39,136		$	—	$	39,136
Unproved		5,147			—		5,147
Development costs		282,095			264,525		546,620
Exploratory costs		40,449			—		40,449
Oil and gas expenditures		366,827			264,525		631,352
Asset retirement costs		18,966			26,112		45,078
Loss on abandonment		9,603			—		9,603
	$	395,396		$	290,637	$	686,033
2007
Property acquisition costs:
Proved	$	21,208		$	—	$	21,208
Unproved		528			—		528
Development costs		588,135			195,637		783,772
Exploratory costs		102,725			61,943		164,668
Oil and gas expenditures		712,596			257,580		970,176
Asset retirement costs		55,179			3,295		58,474
Loss on abandonment		18,649			—		18,649
	$	786,424		$	260,875	$	1,047,299

Oil and Natural Gas Reserves

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. The following table sets forth our net proved oil and gas reserves at December 31, 2004, 2005, 2006 and 2007 and the changes in net proved oil and gas reserves for the years ended December 31, 2005, 2006 and 2007:

F-27

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

SUPPLEMENTAL DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES

	Natural Gas (MMcf)						Oil, Condensate and Natural Gas Liquids (MBbls)
	Gulf of Mexico		North Sea		Total		Gulf of Mexico		North Sea		Total
Proved Reserves at December 31, 2004	110,727		94,502		205,229		11,666		2		11,668
Revisions of previous estimates	(5,845	)	(309	)	(6,154	)	213		—		213
Purchases of minerals in place	71,504		33,094		104,598		437		—		437
Extensions and discoveries	2,119		76,383		78,502		15		17,650		17,665
Sales of minerals in place	(599	)	(12,860	)	(13,459	)	(200	)	—		(200	)
Production	(14,359	)	(1,255	)	(15,614	)	(717	)	—		(717	)
Proved Reserves at December 31, 2005	163,547		189,555		353,102		11,414		17,652		29,066
Revisions of previous estimates	(27,532	)	(5,290	)	(32,822	)	6,417		(79	)	6,338
Purchases of minerals in place	26,533		—		26,533		18,289		—		18,289
Extensions and discoveries	13,637		—		13,637		855		—		855
Production	(19,195	)	(12,029	)	(31,224	)	(3,250	)	(23	)	(3,273	)
Proved Reserves at December 31, 2006	156,990		172,236		329,226		33,725		17,550		51,275
Revisions of previous estimates	10,511		(16,956	)	(6,445	)	7,785		24		7,809
Purchases of minerals in place	27,408		—		27,408		1,648		—		1,648
Extensions and discoveries	17,650		25,384		43,034		3,659		—		3,659
Production	(24,926	)	(12,087	)	(37,013	)	(4,475	)	(23	)	(4,498	)
Proved Reserves at December 31, 2007	187,633		168,577		356,210		42,342		17,551		59,893
	Natural Gas (MMcf)						Oil, Condensate and Natural Gas Liquids (MBbls)
	Gulf of Mexico		North Sea		Total		Gulf of Mexico		North Sea		Total
Proved Developed Reserves at
December 31, 2005	78,833		13,979		92,812		5,924		2		5,926
December 31, 2006	83,099		47,695		130,794		13,839		3		13,842
December 31, 2007	69,845		93,317		163,162		14,111		1		14,112

F-28

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

SUPPLEMENTAL DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES

Standardized Measure

The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves for years ended December 31, is shown below (in thousands):

	Gulf of Mexico			North Sea			Total
2005
Future cash inflows	$	2,302,045		$	3,258,706		$	5,560,751
Future operating expenses		(218,912	)		(326,468	)		(545,380	)
Future development costs		(327,584	)		(836,394	)		(1,163,978	)
Future net cash flows		1,755,549			2,095,844			3,851,393
Future income taxes		(379,902	)		(877,744	)		(1,257,646	)
Future net cash flows, after income taxes		1,375,647			1,218,100			2,593,747
10% annual discount		(274,793	)		(453,374	)		(728,167	)
Standardized measure of discounted future net cash flows	$	1,100,854		$	764,726		$	1,865,580
2006
Future cash inflows	$	2,713,100		$	1,811,271		$	4,524,371
Future operating expenses		(323,248	)		(340,167	)		(663,415	)
Future development costs		(959,078	)		(954,284	)		(1,913,362	)
Future net cash flows		1,430,774			516,820			1,947,594
Future income taxes		(296,080	)		(92,183	)		(388,263	)
Future net cash flows, after income taxes		1,134,694			424,637			1,559,331
10% annual discount		(289,524	)		(254,729	)		(544,253	)
Standardized measure of discounted future net cash flows	$	845,170		$	169,908		$	1,015,078
2007
Future cash inflows	$	5,119,273		$	3,019,721		$	8,138,994
Future operating expenses		(462,537	)		(460,667	)		(923,204	)
Future development costs		(1,104,106	)		(837,655	)		(1,941,761	)
Future net cash flows		3,552,630			1,721,399			5,274,029
Future income taxes		(828,384	)		(596,611	)		(1,424,995	)
Future net cash flows, after income taxes		2,724,246			1,124,788			3,849,034
10% annual discount		(698,689	)		(510,378	)		(1,209,067	)
Standardized measure of discounted future net cash flows	$	2,025,557		$	614,410		$	2,639,967

Future cash inflows are computed by applying year-end prices of oil and gas to the year-end estimated future production of proved oil and gas reserves. The base prices used for the standardized measure calculation were public market prices on December 31, 2007 adjusted by differentials to those market prices. These price adjustments were done on a property-by-property basis for the quality of the oil and natural gas and for transportation to the appropriate location. Estimates of future development and production costs are based on year-end costs and assume continuation of existing economic conditions and year-end prices. We will incur significant capital expenditures in the development of our Gulf of Mexico and North Sea oil and gas properties. We believe with reasonable certainty that we will be able to obtain such capital in the normal course of business. The estimated future net cash flows are then discounted using a rate of 10 percent per year to reflect the estimated timing of the future cash flows. The standardized measure of discounted future net cash flows is the future net cash flows less the computed discount.

F-29

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

SUPPLEMENTAL DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES

The following base prices were used in determining the standardized measure as of December 31:

	Natural Gas ($/Mcf)						Oil, Condensate and Natural Gas Liquids ($/Bbl)
	Gulf of Mexico		U.K. North Sea		Dutch North Sea		Gulf of Mexico		U.K. North Sea		Dutch North Sea
2005	$	10.08	$	12.61	$	6.12	$	61.11	$	59.40	$	58.62
2006		5.64		4.72		8.54		61.05		61.49		66.87
2007		6.80		10.09		9.59		96.00		78.68		89.84

Changes in Standardized Measure

Changes in standardized measure of future net cash flows relating to proved oil and natural gas reserves are summarized below (in thousands):

	Gulf of Mexico			North Sea			Total
2005
Beginning of year	$	381,819		$	138,464		$	520,283
Sales of oil and gas, net of production costs		(114,938	)		(9,505	)		(124,443	)
Net changes in income taxes		(145,748	)		(468,180	)		(613,928	)
Net changes in price and production costs		436,929			592,277			1,029,206
Revisions of quantity estimates		(29,865	)		(4,345	)		(34,210	)
Extensions and discoveries		20,677			401,910			422,587
Accretion of discount		52,772			19,740			72,512
Development costs incurred		104,171			76,872			181,043
Changes in estimated future development costs		(29,273	)		(18,488	)		(47,761	)
Purchases of minerals-in-place		403,481			181,398			584,879
Sales of minerals-in-place		(8,472	)		(86,315	)		(94,787	)
Changes in production rates, timing and other		29,301			(59,102	)		(29,801	)
		719,035			626,262			1,345,297
End of year	$	1,100,854		$	764,726		$	1,865,580
2006
Beginning of year	$	1,100,854		$	764,726		$	1,865,580
Sales of oil and gas, net of production costs		(266,663	)		(74,541	)		(341,204	)
Net changes in income taxes		66,437			488,796			555,233
Net changes in price and production costs		(502,759	)		(835,690	)		(1,338,449	)
Revisions of quantity estimates		53,283			(18,842	)		34,441
Extensions and discoveries		86,468			—			86,468
Accretion of discount		139,250			129,184			268,434
Development costs incurred		67,750			344,158			411,908
Changes in estimated future development costs		(13,336	)		(186,158	)		(199,494	)
Purchases of minerals-in-place		168,595			—			168,595
Changes in production rates, timing and other		(54,709	)		(441,725	)		(496,434	)
		(255,684	)		(594,818	)		(850,502	)
End of year	$	845,170		$	169,908		$	1,015,078

F-30

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

SUPPLEMENTAL DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES

	Gulf of Mexico			North Sea			Total
2007
Beginning of year	$	845,170		$	169,908		$	1,015,078
Sales of oil and gas, net of production costs		(421,468	)		(85,190	)		(506,658	)
Net changes in income taxes		(378,036	)		(215,728	)		(593,764	)
Net changes in price and production costs		1,000,519			450,636			1,451,155
Revisions of quantity estimates		457,626			(63,985	)		393,641
Extensions and discoveries		334,880			165,548			500,428
Accretion of discount		107,038			20,823			127,861
Development costs incurred		378,654			90,097			468,751
Changes in estimated future development costs		(319,454	)		16,959			(302,495	)
Purchases of minerals-in-place		180,636			—			180,636
Changes in production rates, timing and other		(160,008	)		65,342			(94,666	)
		1,180,387			444,502			1,624,889
End of year	$	2,025,557		$	614,410		$	2,639,967

Sales of oil and natural gas, net of oil and natural gas operating expenses, are based on historical pre-tax results. Sales of oil and natural gas properties, extensions and discoveries, purchases of minerals-in-place and the changes due to revisions in standardized variables are reported on a pre-tax discounted basis, while the accretion of discount is presented on an after-tax basis.

Capitalized Costs Related to Oil and Gas Producing Activities

The following table summarizes capitalized costs related to our oil and gas operations (in thousands):

	Gulf of Mexico			North Sea			Total
2005
Oil and gas properties:
Unproved	$	8,607		$	275		$	8,882
Proved		706,301			184,101			890,402
Accumulated depletion, impairment and amortization		(253,831	)		(18,032	)		(271,863	)
	$	461,077		$	166,344		$	627,421
2006
Oil and gas properties:
Unproved	$	54,012		$	2,177		$	56,189
Proved		1,019,324			463,839			1,483,163
Accumulated depletion, impairment and amortization		(378,523	)		(65,184	)		(443,707	)
	$	694,813		$	400,832		$	1,095,645
2007
Oil and gas properties:
Unproved	$	86,301		$	2,114		$	88,415
Proved		1,743,909			724,614			2,468,523
Accumulated depletion, impairment and amortization		(587,360	)		(138,998	)		(726,358	)
	$	1,242,850		$	587,730		$	1,830,580

Results of Operations for Oil and Gas Producing Activities

The results of operations for oil and gas producing activities below exclude non-oil and gas revenues, general and administrative expenses, interest charges, interest income and interest capitalized. Income tax expense was determined by applying the statutory rates to pretax operating results (in thousands).

F-31

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

SUPPLEMENTAL DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES

	Gulf of Mexico			North Sea			Total
2005
Oil and gas production	$	135,175		$	11,499		$	146,674
Lease operating		21,624			2,005			23,629
Exploration		6,075			133			6,208
Depreciation, depletion and amortization		58,857			4,768			63,625
Accretion of asset retirement obligation		2,476			762			3,238
Gain on abandonment		(732	)		—			(732	)
(Gain) loss on disposal of oil and gas properties		4,681			(7,424	)		(2,743	)
Income before income taxes		42,194			11,255			53,449
Income tax expense		(14,768	)		(5,648	)		(20,416	)
Results of operations from producing activities (excluding corporate overhead and interest costs)	$	27,426		$	5,607		$	33,033
2006
Oil and gas production	$	321,970		$	92,212		$	414,182
Other revenues		5,639			—			5,639
Total revenues		327,609			92,212			419,821
Lease operating		54,775			17,671			72,446
Exploration		1,465			766			2,231
Depreciation, depletion and amortization		126,365			42,781			169,146
Impairment of oil and gas properties		19,520			—			19,520
Accretion of asset retirement obligation		6,068			2,008			8,076
Loss on abandonment		9,603			—			9,603
Income before income taxes		109,813			28,986			138,799
Income tax expense		(38,435	)		(12,845	)		(51,280	)
Results of operations from producing activities (excluding corporate overhead and interest costs)	$	71,378		$	16,141		$	87,519
2007
Oil and gas production	$	494,293		$	105,031		$	599,324
Other revenues		8,611			—			8,611
Total revenues		502,904			105,031			607,935
Lease operating		72,750			18,943			91,693
Exploration		12,930			826			13,756
Depreciation, depletion and amortization		184,808			62,570			247,378
Impairment of oil and gas properties		25,370			8,972			34,342
Accretion of asset retirement obligation		8,486			3,631			12,117
Loss on abandonment		18,649			—			18,649
Income before income taxes		179,911			10,089			190,000
Income tax expense		(62,969	)		(5,045	)		(68,014	)
Results of operations from producing activities (excluding corporate overhead and interest costs)	$	116,942		$	5,044		$	121,986

F-32

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS

FOR EACH OF THE THREE YEARS ENDED DECEMBER 31, 2007

(In Thousands)

	Balance at Beginning of Period		Charged to Costs and Expenses			Charged to Other Accounts			Deduction		Balance at End of Period
2005
Allowance for doubtful accounts	$	1,499	$	—		$	(1,132	)	$	—	$	367
Valuation allowance on deferred tax assets		30,958		(4,242	)		3,546			—		30,262
2006
Allowance for doubtful accounts	$	367	$	126		$	(84	)	$		$	409
Valuation allowance on deferred tax assets		30,262		(5,302	)		166					25,126
2007
Allowance for doubtful accounts	$	409	$	(27	)	$	—		$	—	$	382
Valuation allowance on deferred tax assets		25,126		(21,762	)		(339	)				3,025

S-1

EX-23.1

EXHIBIT 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference in Registration Statement Nos. 333-105699 and 333-121662 on Form S-3, and Registration Statement No. 333-60762 on Form S-8 of ATP Oil & Gas Corporation of our reports dated March 7, 2008, relating to the financial statements and financial statement schedule of ATP Oil & Gas Corporation (which report expresses an unqualified opinion and includes an explanatory paragraph relating to the Company’s adoption of Statement of Financial Accounting Standards No. 123(R), “Share-Based Payment,” effective January 1, 2006), and of the effectiveness of internal control over financial reporting (which report expresses an adverse opinion on the effectiveness of the Company's internal control over financial reporting because of a material weakness) appearing in this Annual Report on Form 10-K of ATP Oil & Gas Corporation for the year ended December 31, 2007.

/s/ DELOITTE & TOUCHE LLP

Houston, Texas

March 7, 2008

EX-23.2

Exhibit 23.2

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS

We hereby consent to the use of our report, dated February 8, 2008 relating to the proved oil and gas reserves of ATP Oil & Gas Corporation as of December 31, 2007, to the information derived from such report and to the reference to this firm as an expert in the annual report on Form 10-K.

/s/ Ryder Scott Company, L.P.

Houston, Texas

February 29, 2008

EX-23.3

Exhibit 23.3

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS

We hereby consent to the use of our report, dated January 25, 2008, relating to the proved oil and gas reserves of ATP Oil & Gas Corporation as of December 31, 2007, to the information derived from such report and to the reference to this firm as an expert in the annual report on Form 10-K.

/s/ RPS Energy limited

February 29, 2008

EX-23.4

Exhibit 23.4

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS

We hereby consent to the use of our report, dated February 8, 2008, relating to the proved oil and gas reserves of ATP Oil & Gas Corporation as of December 31, 2007, to the information derived from such report and to the reference to this firm as an expert in the annual report on Form 10-K.

Collarini Associates

/s/ M. C. Reece

Mitch Reece, P. E.

President

February 26, 2008

EX-23.5

Exhibit 23.5

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS

We hereby consent to the references to DeGolyer and Macnaughton, and to the incorporation of the information contained in our “Appraisal Report as of December 31, 2007 on Certain Properties owned by ATP Oil and Gas Corporation” (our Report), in the Annual Report on Form 10-K of ATP Oil & Gas Corporation.

/s/ DeGolyer and MacNaughton

February 29, 2008

EX-31.1

EXHIBIT 31.1

ATP OIL & GAS CORPORATION

Section 302 Certification of Principal Executive Officer

I, T. Paul Bulmahn, certify that:

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

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

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

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

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

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

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

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: March 7, 2008	/s/ T. Paul Bulmahn
	Chairman, Chief Executive Officer and President

EX-31.2

EXHIBIT 31.2

ATP OIL & GAS CORPORATION

Section 302 Certification of Principal Financial Officer

I, Albert L. Reese, Jr., certify that:

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

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

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

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

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

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

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

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: March 7, 2008	/s/ Albert L. Reese, Jr.
	Albert L. Reese, Jr. Chief Financial Officer

EX-32.1

Exhibit 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of ATP Oil & Gas Corporation (the “Company”) on Form 10-K for the period ending December 31, 2007 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), the undersigned hereby certifies, pursuant to 18 U.S.C. Sec. 1350, as adopted pursuant to Sec. 906 of the Sarbanes-Oxley Act of 2002, in his capacity as an officer of the Company, that:

(1) the Report fully complies with the requirements of section 13 (a) or 15 (d) of the Securities Exchange Act of 1934; and

(2) the information contained in the Report fairly presents, in all material respects, the financial condition and the results of operations of the Company.

Date: March 7, 2008	By:	/s/ T. Paul Bulmahn
		T. Paul Bulmahn Chairman, Chief Executive Officer and President

EX-32.2

Exhibit 32.2

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of ATP Oil & Gas Corporation (the “Company”) on Form 10-K for the period ending December 31, 2007 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), the undersigned hereby certifies, pursuant to 18 U.S.C. Sec. 1350, as adopted pursuant to Sec. 906 of the Sarbanes-Oxley Act of 2002, in his capacity as an officer of the Company, that:

(1) the Report fully complies with the requirements of section 13 (a) or 15 (d) of the Securities Exchange Act of 1934; and

(2) the information contained in the Report fairly presents, in all material respects, the financial condition and the results of operations of the Company.

Date: March 7, 2008	By:	/s/ Albert L. Reese, Jr.
		Albert L. Reese, Jr. Chief Financial Officer