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, 2005

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

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

Large accelerated filer  ¨    Accelerated filer  x    Non-accelerated filer  ¨

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, 2005 (the last business day of the Registrant’s most recently completed second fiscal quarter) was approximately $426,436,897. The number of shares of the Registrant’s common stock outstanding as of March 9, 2006 was 29,792,934.

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, 2005, are incorporated by reference in Part III of this Form 10-K.

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

2005 FORM 10-K ANNUAL REPORT

TABLE OF CONTENTS

			Page
Part I			6
	Item 1.	Business	6
	Item 1A.	Risk Factors	12
	Item 1B.	Unresolved Staff Comments	19
	Item 2.	Properties	19
	Item 3.	Legal Proceedings	23
	Item 4.	Submission of Matters to a Vote of Security Holders	23
Part II			25
	Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	25
	Item 6.	Selected Financial Data	26
	Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	28
	Item 7A.	Quantitative and Qualitative Disclosures about Market Risk	43
	Item 8.	Financial Statements and Supplementary Data	43
	Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	43
	Item 9A.	Controls and Procedures	43
	Item 9B.	Other Information	44
Part III			45
	Item 10.	Directors and Executive Officers of Registrant	45
	Item 11.	Executive Compensation	45
	Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	45
	Item 13.	Certain Relationships and Related Transactions	45
	Item 14.	Principal Accountant Fees and Services	45
Part IV			46
	Item 15.	Exhibits, Financial Statement Schedules	46

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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;

• 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 affect the demand for natural gas or oil 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
Bcfe	Billion cubic feet equivalent
MBbls	Thousand barrels of crude oil or other liquid hydrocarbons
Mcf	Thousand cubic feet of natural gas
Mcfe	Thousand cubic feet 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 equivalent
MMBoe	Million barrels of crude oil or other liquid hydrocarbons equivalent
SEC	United States Securities and Exchange Commission
U.S.	United States
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.

PV10 is the pre-tax present value, discounted at 10% per year, of estimated future net revenues from the production of proved reserves, computed by applying sales prices in effect as of the dates of such estimates and held constant throughout the productive life of the reserves (except for consideration of price changes to the extent provided by contractual arrangements), and deducting the estimated future costs to be incurred in developing, producing and abandoning the proved reserves (computed based on current costs and assuming continuation of existing economic conditions).

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

Proved reserves are the estimated quantities of oil and gas which geological and engineering data demonstrate, with reasonable certainty, can be recovered in future years from known reservoirs under existing economic and operating conditions. Reservoirs are considered proved if shown to be economically producible by either actual production or conclusive formation tests. See Regulation S-X, Rule 4-10(a)(2), (3) and (4), (Reg. § 210.4-10) available on the Internet at www.sec.gov/about/forms/regs-x.pdf.

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

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

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

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 with proved producing 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, 2005, we had estimated net proved reserves of 527.5 Bcfe, of which approximately 295.5 Bcfe (56%) was in the North Sea and 232.0 Bcfe (44%) was in the Gulf of Mexico. Year-end reserves were comprised of 353.1 Bcf of natural gas (67%) and 29.1 MMBbls of oil (33%). The majority of our oil reserves (61%) and natural gas reserves (54%) are located in the North Sea with the balance located in the Gulf of Mexico. The estimated pre-tax PV10 of our proved reserves at December 31, 2005 was $2.7 billion. See “Item 2. Properties – Oil and Natural Gas Reserves” for a reconciliation to after-tax PV10.

At December 31, 2005, we had leasehold and other interests in 76 offshore blocks, 53 platforms and 147 wells, including 11 subsea wells, in the Gulf of Mexico. We operate 125 (85%) of these wells, including all of the subsea wells, and 87% of our offshore platforms. We also had interests in 10 blocks and 2 company-operated subsea wells in the North Sea. Our average working interest in our properties at December 31, 2005 was approximately 75%. For more information regarding our operations and assets in the Gulf of Mexico and North Sea, see Note 14, “Segment Information,” to the Notes to Consolidated Financial Statements.

Our Business Strategy

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

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

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

By focusing on properties that are not strategic to other companies, we are able to minimize up front acquisition costs and concentrate available capital on the development phase of these properties. For the three

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year period ending December 31, 2005, we have added 210.7 Bcfe of proved oil and natural gas reserves through acquisitions at a total cost of $70.3 million. Development costs for this same period were approximately $514.0 million.

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

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 24 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, 2005, we operated all of our properties under development, all of our subsea wells and 87% of our offshore platforms.

• Employee Ownership. Through employee ownership, we have assembled a staff whose business decisions are aligned with the interests of our shareholders. As of March 9, 2006, our executive officers and directors own approximately 35% of our common stock.

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

Marketing and Delivery Commitments

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

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

Competition

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

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Regulation

Gulf of Mexico

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

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

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

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.

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

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

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

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

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

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,

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civil and criminal penalties, the imposition of remedial obligations, and the issuance of injunctive relief. Offshore drilling in some areas has been opposed by environmental groups and, in some areas, has been restricted by governmental entities. Moreover, changes in environmental laws and regulations have increased in recent years. Any laws that are enacted or other governmental actions that are taken to prohibit or restrict offshore drilling or to impose more stringent or costly environmental protection requirements could have a material adverse affect on the natural gas and oil industry in general and our offshore operations in particular. While we believe that we are in substantial compliance with current environmental laws and regulations and that continued compliance with existing requirements will not materially affect us, there is no assurance that this trend will continue in the future.

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

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

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

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

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.

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

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

North Sea

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

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

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

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

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

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

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

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

Employees

At December 31, 2005 we had 48 full-time employees in our Houston office, five full-time employees in our London office and two full-time employees in our Netherlands office. None of our employees are covered by a collective bargaining agreement. We regularly use the services of independent consultants and contractors to perform various professional services, particularly in the areas of construction, design, well-site supervision, permitting and environmental assessment. Independent contractors usually perform field and on-site production operation services for us, including gauging, maintenance, dispatching, inspection and well testing.

Available Information

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

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.

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Our actual development results are likely to differ from our estimates of our proved reserves. We may experience production that is less than estimated and 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. Development of our reserves may not occur as scheduled and the actual results may not be as estimated. Development activity may result in downward adjustments in reserves or higher than estimated costs.

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

Any significant variance could materially affect the estimated quantities and PV10 of reserves. Our properties may also be susceptible to hydrocarbon drainage from production by other operators on adjacent properties. In addition, we will likely adjust estimates of proved reserves to reflect production history, results of development, prevailing oil and natural gas prices and other factors, many of which are beyond our control. Actual production, revenues, taxes, development expenditures and operating expenses with respect to our reserves may vary materially from our estimates.

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

The size of our operations and our capital expenditure budget limits the number of properties that we can develop in any given year. Complications in the development of any single material well may result in a material adverse affect on our financial condition and results of operations. For instance, during 2003, we experienced unforeseen production delays and increased development costs in connection with the development of our Helvellyn well in the North Sea. In late 2005, we experienced delays and increased development costs in developing our Gomez project in the Gulf of Mexico as a result of hurricanes Katrina and Rita.

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

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

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

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

We have historically needed and will continue to need substantial amounts of cash to fund our capital expenditure and working capital requirements. Our ongoing capital requirements consist primarily of funding acquisition, development and abandonment of oil and gas reserves and to meet our debt service obligations. Cash paid for capital expenditures for oil and gas properties were approximately $420.5 million, $87.4 million and $83.8 million for the years ended December 31, 2005, 2004 and 2003, 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.

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For 2006, we plan to finance anticipated expenses, debt service and acquisition and development requirements with available cash, funds generated from cash provided by operating activities and net cash proceeds from the potential sale of assets, issuance of debt or new equity offerings.

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

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

In March 2004, we entered into a term loan, which was subsequently amended in September 2004 and again in April 2005 (the “Term Loan”). As amended, the Term Loan provides for an aggregate outstanding principal amount of $350.0 million. The Term Loan matures in March 2010 and is secured by substantially all of our oil and gas assets in the Gulf of Mexico and the U.K. Sector – North Sea and is guaranteed by our wholly owned subsidiaries ATP Energy and ATP Oil & Gas (U.K.) Limited. As of December 31, 2005, we had $347.4 million principal amount outstanding under the Term Loan. The Term Loan contains customary restrictions, including covenants limiting our ability to incur additional debt, grant liens, make investments, consolidate, merge or acquire other businesses, sell assets, pay dividends and other distributions and enter into transactions with affiliates. We also are required to maintain specified financial requirements under the terms of our Term Loan including the following, as defined in the Term Loan:

• Current Ratio of 1.0/1.0;

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

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

• Pre-tax PV-10 of our Total Proved Developed Producing Oil and Gas Reserves to Net Debt of at least 0.5/1.0 at June 30 and December 31 of any fiscal year;

• Pre-tax PV-10 of our Total Proved Oil and Gas Reserves to Net Debt of at least 2.5/1.0 at June 30 and December 31 of any fiscal year;

• the requirement to maintain Commodity Hedging Agreements on no less than 40% nor more than 80% of the next twelve months of forecasted production attributable to our proved producing reserves;

• the requirement to maintain a Maximum Leverage Ratio of no more than 3.0/1.0 at the end of any fiscal quarter;

• the requirement to maintain a Debt to Reserve Amount of no greater than $2.50 through maturity; provided, however, that if such amount is exceeded at the end of the fiscal year ending on December 31, 2005, the covenant shall be retested at June 30, 2006, and

• limit Permitted Business Investments, as defined, to $75.0 million during any fiscal year.

These restrictions may make it difficult for us to successfully execute our business strategy or to compete in our industry with companies not similarly restricted. While we were in compliance with all of the financial covenants in our Term Loan at December 31, 2005 and 2004, during 2003 and in February 2004, we were required to obtain waivers for certain of our financial covenants in our prior credit facility. If we are unable to meet the requirements of our Term Loan or any new financial transaction that we may enter into, we may be required to seek waivers from our lenders and there is no assurance that such waivers would be granted.

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

Our debt, trade payables, preferred stock and related interest and dividend 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; and

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

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.

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

Our revenues, profitability and future growth and the carrying value of our properties depend substantially on the prices we realize for our oil and natural gas production. Because approximately 67% of our estimated proved reserves as of December 31, 2005 were natural gas reserves, our financial results are more sensitive to movements in natural gas prices. Our realized prices also affect the amount of cash flow available for capital expenditures and our ability to borrow and raise additional capital.

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

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

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

• 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

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

• 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 financial 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 financial derivative instruments and fixed price forward sales contracts — our fixed forward sales are designated as normal sales under derivative accounting rules — and these instruments may limit any benefit we would receive from increases in the prices for oil and natural gas. For the years ended December 31, 2005, 2004 and 2003, we realized a loss on settled financial derivatives of $0, $1.2 million and $16.6 million, respectively.

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 non-cash 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 independent reservoir engineers’ estimates of proved reserves. In addition, other factors such as probable and possible reserves are taken into consideration when justified by economic conditions. For each property determined to be impaired, we recognize an impairment loss equal to the difference between the estimated fair value and the carrying value of the property on a depletable unit basis. Fair value is estimated to be the present value of the aforementioned expected future net cash flows. Any impairment charge incurred is recorded in accumulated depreciation, depletion, impairment and amortization to reduce our recorded basis in the asset. Each part of this calculation is subject to a large degree of judgment, including the determination of the depletable units’ estimated reserves, future cash flows and fair value. We recorded no impairments in 2005 and 2004 and an impairment of $11.7 million for the year ended December 31, 2003.

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.

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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.

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

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operational risks. We do not carry business interruption insurance at levels that would provide enough funds for us to continue operating without access to other funds. For some risks, we may not obtain insurance if we believe the cost of available insurance is excessive relative to the risks presented. Because third party contractors and other service providers are used in our offshore operations, we may not realize the full benefit of workmen’s compensation laws in dealing with their employees. In addition, pollution and environmental risks generally are not fully insurable.

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

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

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

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

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

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

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

Our success will depend on our ability to retain and attract experienced geoscientists and other professional staff. As of December 31, 2005, we had 21 engineers, geologist/geophysicists and other technical personnel in our Houston office, two engineers, geologist/geophysicists and other technical personnel in our London location and one engineer in our Netherlands office. We depend to a large extent on the efforts, technical expertise and continued employment of these personnel and members of our management team. If a significant number of them resign or become unable to continue in their present role and if they are not adequately replaced, our business operations could be adversely affected.

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Rapid growth may place significant demands on our resources.

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

• 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.

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 35% of our outstanding shares of common stock as of March 9, 2006. 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.

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 primarily in the Gulf of Mexico and the North Sea. At December 31, 2005, we owned leasehold and other interests in 76

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offshore blocks, 53 platforms and 147 wells, including 11 subsea wells, in the Gulf of Mexico. We operate 125 (85%) of these wells, including all of the subsea wells, and 87% of our offshore platforms. We also had interests in 10 blocks and 2 company-operated subsea wells in the North Sea. Our average working interest in our properties at December 31, 2005 was approximately 75%. As of December 31, 2005, we had leasehold interests located in the Gulf of Mexico and North Sea covering approximately 455,875 gross and 372,280 net acres, of which 265,754 gross acres were developed and 191,353 net acres were developed.

Gulf of Mexico

Acquisitions – During 2005, ATP was active in both government sponsored lease sales and acquisitions of properties from other companies. On March 16, 2005, ATP was the apparent high bidder and was subsequently awarded seven blocks relating to its winning bids at the Central Gulf of Mexico Offshore Lease Sale. ATP owns a 100% working interest in and is the operator of all seven blocks. Two of the blocks are adjacent to the Company’s wholly-owned Mississippi Canyon 711 development. Two additional blocks are contiguous to an existing ATP operated development in the West Cameron area and the remaining three blocks provide for new development area opportunities. On October 12, 2005, ATP was awarded two blocks pursuant to its high bids at the August 2005 Western Gulf of Mexico Offshore Lease Sale. On December 15, 2005 the Minerals Management Service awarded a third block to the Company on which it was the apparent high bidder. ATP is the operator and has a 100% working interest in the three blocks acquired, consisting of Garden Banks 228, High Island A-391 and High Island A-589. Total acquisition cost of the ten blocks was approximately $5.3 million dollars.

ATP made three acquisitions in 2005 from other companies. In the second quarter of 2005, ATP acquired 100% of the working interest in South Marsh Island 166. The property had a temporarily abandoned well which was reentered and completed in 2005. On September 21, 2005, ATP acquired all of BP Exploration & Production Inc.’s (“BP”) interest in four Federal oil and gas leases covering Mississippi Canyon Blocks 173/217 and Desoto Canyon Blocks 133/177, offshore Gulf of Mexico, an oil and gas discovery area named “King’s Peak.” The acquisition also included all of BP’s interest in the Canyon Express Pipeline System.

On October 31, 2005, ATP acquired substantially all of the oil and gas assets of a privately held company. These assets consist of 19 blocks located on the Gulf of Mexico Outer Continental Shelf in less than 600 feet of water. The Company operates most of the properties. Cash acquisition costs of the properties from other companies during 2005 totaled $62.1 million.

Development – During 2005, we incurred development costs of $231.7 million on projects in the Gulf of Mexico. While these costs were spread across several properties, the Company’s development at Mississippi Canyon 711 (Gomez) was responsible for 93% of the costs incurred. During 2005, ATP completed two wells and installed two 27 mile pipelines, one for oil and one for natural gas. ATP acquired the Rowan Midland semi-submersible drilling rig through a structured lease transaction. We converted the rig to a floating production facility and installed processing equipment so that it can serve as the host production platform for the Gomez development. At year-end 2005, we were completing the installation of the facilities. Gomez was placed on production March 9, 2006. Total development costs incurred during 2005 for the Gomez development were $215.2 million.

North Sea

Acquisitions – On June 8, 2005, we increased our ownership in the Tors fields (Garrow and Kilmar) in the Southern Gas Basin of the U.K. North Sea to 100% by acquiring the remaining 25% interest pursuant to an agreement with our partner. The U.K. Secretary of State for Trade and Industry gave approval for ATP Oil & Gas (UK) Limited to own a 100% interest in the Tors fields and to act as the sole development and production operator. Subsequently, in December 2005, ATP Oil & Gas (UK) Limited sold 15% of the ATP 100% working interest in the Tors fields. ATP has completed the Kilmar platform installation and the Kilmar and Garrow pipeline installations at the Tors and has commenced well operations.

During December 2005, we increased our ownership to 100% in the Venture field (Block 49/12a North) in the Southern Gas Basin of the U.K. North Sea. ATP Oil & Gas (UK) Limited, a wholly-owned subsidiary, by acquiring the remaining 50% ownership interest pursuant to a Sale and Purchase Agreement with our

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partner. This 100% ownership will allow us to proceed with the field development plan approval process. The field has been defined by two vertical wells that have been tested at rates of 35 MMcf per day and 74 MMcf per day. Development plans for Venture include a production platform and a pipeline to an offset host platform.

ATP Oil & Gas (UK) Limited recorded net acquisition costs of $7.0 million in 2005 related to these two acquisitions.

Development – During 2005, ATP incurred development costs in the North Sea of $125.9 million primarily at two projects, Tors (Kilmar and Garrow) in the UK Sector and L-06 in the Dutch Sector.

At Tors, we constructed a platform and jacket and installed them at Kilmar during the third quarter of 2005. A pipeline was installed from Garrow to Kilmar and then a second pipeline was installed from Kilmar to the host platform. During the fourth quarter, a drilling rig was brought to location and began drilling the first of three planned wells at Kilmar. This well was being drilled at December 31, 2005, and total depth was achieved and completion operations begun in early March 2006. Total development costs incurred at Tors during 2005 were $96.6 million.

At L-06 in the Dutch Sector, ATP drilled the L06d-S1 well, installed a subsea tree and installed a pipeline to the host platform. At year-end 2005, we were completing the installation of the pipeline and final connections at the host facility. L-06 was placed on production February 26, 2006. Total development costs incurred at L-06 during 2005 were $29.3 million.

Oil and Natural Gas Reserves

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

The following table presents our estimated net proved oil and natural gas reserves at December 31, 2005 based on reserve reports prepared by Ryder Scott Company, L.P., Collarini Associates and DeGolyer and MacNaughton for our Gulf of Mexico reserves, Ryder Scott Company, L.P. for our Netherlands reserves and RPS Energy (formerly RPS Troy-Ikoda) for our U.K. reserves.

	Proved Reserves
	Developed	Undeveloped	Total
Gulf of Mexico
Natural gas (MMcf)	78,833	84,714	163,547
Oil and condensate (MBbls)	5,924	5,490	11,414
Total proved reserves (MMcfe)	114,380	117,650	232,030
North Sea
Natural gas (MMcf)	13,979	175,576	189,555
Oil and condensate (MBbls)	2	17,650	17,652
Total proved reserves (MMcfe)	13,989	281,476	295,465
Total
Natural gas (MMcf)	92,812	260,290	353,102
Oil and condensate (MBbls)	5,926	23,140	29,066
Total proved reserves (MMcfe)	128,369	399,126	527,495

In 2005 our standardized measure of discounted future net cash flows was $1,865.6 million. The present value of future net cash flows attributable to estimated net proved reserves, discounted at 10% per annum, (“PV10”) is a computation of the standardized measure of discounted future net cash flows on a pre-tax basis. The table below provides a reconciliation of PV10 to the standardized measure of discounted future net cash flows at December 31, 2005. PV10 may be considered a non-GAAP financial measure under the SEC’s regulations. We believe PV10 to be an important measure for evaluating the relative significance of our natural gas and oil properties. PV10 is computed on the same basis as the standardized measure of discounted future

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net cash flows but without deducting income taxes. We further believe investors and creditors may utilize our PV10 as a basis for comparison of the relative size and value of our reserves to other companies. However, PV10 is not a substitute for the standardized measure. Our PV10 measure and the standardized measure of discounted future net cash flows (shown below in thousands) do not purport to present the fair value of our natural gas and oil reserves.

Net present value of future cash flows, before income taxes	$	2,684,342
Future income taxes, discounted at 10%		818,762
Standardized measure of discounted future net cash flows	$	1,865,580

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.

Drilling Activity

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

	Gulf of Mexico			North Sea
	2005	2004	2003	2005	2004	2003
Gross Development Wells:
Productive	4.0	10.0	5.0	1.0	—	1.0
Nonproductive	—	2.0	—	1.0	—	—
Total	4.0	12.0	5.0	2.0	—	1.0
Net Development Wells:
Productive	3.4	6.7	4.3	0.5	—	0.5
Nonproductive	—	1.5	—	0.8	—	—
Total	3.4	8.2	4.3	1.3	—	0.5
Gross Exploratory Wells:
Productive	3.0	3.0	—	—	—	—
Nonproductive	1.0	—	—	—	—	—
Total	4.0	3.0	—	—	—	—
Net Exploratory Wells:
Productive	3.0	1.3	—	—	—	—
Nonproductive	0.8	—	—	—	—	—
Total	3.8	1.3	—	—	—	—
Total Gross Wells:
Productive	7.0	13.0	5.0	1.0	—	1.0
Nonproductive	1.0	2.0	—	1.0	—	—
Total	8.0	15.0	5.0	2.0	—	1.0
Total Net Wells:
Productive	6.4	8.0	4.3	0.5	—	0.5
Nonproductive	0.8	1.5	—	0.8	—	—
Total	7.2	9.5	4.3	1.3	—	0.5

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At December 31, 2005 we had one gross development well (0.9 net development well) and one exploratory well (0.25 net exploratory well) 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, 2005:

	Gulf of Mexico	North Sea	Total
Gross
Gas	46.0	1.0	47.0
Oil	6.0	—	6.0
Total	52.0	1.0	53.0
Net
Gas	28.3	0.5	28.8
Oil	4.8	—	4.8
Total	33.1	0.5	33.6

Acreage

The following table summarizes our developed and undeveloped acreage holdings at December 31, 2005. 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	249,722	183,337	98,063	92,971	347,785	276,308
North Sea	16,032	8,016	92,058	87,956	108,090	95,972
	265,754	191,353	190,121	180,927	455,875	372,280

(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.

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, a claimant and/or defendant in various legal proceedings from time to time. Management does not believe that the outcome of these legal proceedings, individually, 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 2005.

Executive Officers of the Company and Other Key Employees

Set forth below are the names, ages (as of March 2, 2006) and titles of the persons currently serving as executive officers of the Company. All executive officers hold office until their successors are elected and qualified.

Name	Age	Position
T. Paul Bulmahn	62	Chairman and President
Gerald W. Schlief	58	Senior Vice President
Albert L. Reese, Jr.	56	Chief Financial Officer
Leland E. Tate	58	Chief Operations Officer
John E. Tschirhart	55	Senior Vice President, International, General Counsel
Isabel M. Plume	46	Chief Communications Officer
Keith R. Godwin	38	Chief Accounting Officer

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

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

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

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

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

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

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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.

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 of preferred stock, par value $0.001 per share. There were 29,792,934 shares of common stock and 175,000 shares of preferred stock outstanding as of March 9, 2006. There were 95 holders of record of our common stock as of March 9, 2006. Our common stock is traded on the NASDAQ National Market under the ticker symbol ATPG.

The following table sets forth the range of high and low 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
2005:
4th Quarter	$	39.20	$	27.91
3rd Quarter		34.00		23.51
2nd Quarter		24.62		17.86
1st Quarter		26.55		16.76
2004:
4th Quarter	$	19.15	$	12.11
3rd Quarter		12.34		7.05
2nd Quarter		8.09		5.90
1st Quarter		6.90		4.71

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

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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”.

	Years Ended December 31,
	2005			2004			2003			2002			2001
Statement of Operations Data:
Revenues:
Oil and gas production	$	146,674		$	116,123		$	70,151		$	80,017		$	87,873
Cost and operating expenses:
Lease operating expenses		23,629			19,531			17,173			16,764			14,806
Exploration expenses		6,208			997			1,358			154			1,068
General and administrative		24,274			15,806			12,209			10,037			9,806
Credit facility costs		—			1,850			1,990			250			175
Non-cash compensation expense		57			—			(39	)		595			3,364
Depreciation, depletion and amortization		64,069			55,637			29,378			43,390			53,428
Impairment of oil and gas properties		—			—			11,670			6,844			24,891
(Gain) loss on abandonment (1)		(732	)		(251	)		4,973			—			—
Accretion expense		3,238			2,069			2,752			—			—
Loss on unsuccessful property acquisition (2)		—			—			8,192			—			3,147
Gain on disposition of properties		(2,743	)		(6,011	)		—			—			—
Other		—			400			—			—			—
Total operating expenses		118,000			90,028			89,656			78,034			110,685
Income (loss) from operations		28,674			26,095			(19,505	)		1,983			(22,812	)
Other income (expense):
Interest income		4,064			627			52			73			884
Interest expense		(35,720	)		(22,262	)		(9,678	)		(10,418	)		(10,039	)
Loss on extinguishment of debt		—			(3,326	)		(3,352	)		—			(926	)
Other		419			280			2,244			1,081			—
Income (loss) before income taxes and cumulative effect of change in accounting principle		(2,563	)		1,414			(30,239	)		(7,281	)		(32,893	)
Income tax (expense) benefit		(153	)		(58	)		(21,224	)		2,581			11,510
Income (loss) before cumulative effect of change in accounting principle		(2,716	)		1,356			(51,463	)		(4,700	)		(21,383	)
Cumulative effect of change in accounting principle, net of tax (3)		—			—			662			—			—
Net income (loss)	$	(2,716	)	$	1,356		$	(50,801	)	$	(4,700	)	$	(21,383	)
Preferred dividends		(9,858	)		—			—			—			—
Net income (loss) available to common shareholders	$	(12,574	)	$	1,356		$	(50,801	)	$	(4,700	)	$	(21,383	)
Weighted average number of common shares outstanding:
Basic		29,080			24,944			22,975			20,315			19,704
Diluted		29,080			25,271			22,975			20,315			19,704
Basic and diluted net income (loss) per share available to common:
Income (loss) before cumulative effect of change in accounting principle	$	(0.43	)	$	0.05		$	(2.24	)	$	(0.23	)	$	(1.09	)
Cumulative effect of change in accounting principle, net of tax		—			—			0.03			—			—
Net income (loss) available to common shareholders		(0.43	)		0.05			(2.21	)		(0.23	)		(1.09	)

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	December 31,
	2005		2004		2003			2002			2001
Balance Sheet Data:
Cash and cash equivalents	$	65,566	$	102,774	$	4,564		$	6,944		$	5,294
Working capital (deficit)		567		68,330		(46,423	)		(13,699	)		(29,071	)
Net oil and gas properties		627,421		213,206		189,125			119,036			133,033
Total assets		823,763		372,147		217,685			182,055			177,564
Long-term debt, including current maturities		340,989		210,309		115,409			86,387			100,111
Capital lease, including current maturities		43,116		—		—			—			—
Total liabilities		606,252		314,983		213,353			143,508			132,572
Shareholders’ equity (deficit)		217,511		57,164		4,332			38,547			44,992

(1) During 2003, we recognized a loss on abandonment of $5.0 million. Of this amount, approximately $4.4 million was attributable to actual costs exceeding the original estimates on two properties. These unforeseen overruns were a result of difficulties in abandoning one of our properties due to the condition of the wells received from the original owner and the collapse of a platform crane. In addition, we incurred significant standby time as a result of Hurricane Claudette.

(2) During 2002 and 2003, ATP was in a dispute over a contract for the sale of an oil and gas property. The dispute was subsequently resolved for $8.2 million. We recorded a charge to income in the fourth quarter of 2003 and paid the amount in the first quarter of 2004. The Court dismissed the lawsuit on April 16, 2004.

(3) Effective January 1, 2003 we adopted SFAS 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).

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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 us to contain commercially productive quantities of oil and gas even though the reservoirs do not meet the SEC definition of proved reserves. We believe that our strategy provides assets for us to develop and produce without the risk, cost or time of traditional exploration.

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

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

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

To enhance the economics and return on investment of a project, we sometimes develop the project to a value creation point and either sell an interest or bring in partners on a promoted basis during the high capital development phase. In 2003, we sold interests in three projects in the Gulf of Mexico on a promoted basis to reduce the amount of capital employed. We continued this practice into 2004 whereupon we sold 25% of our interest in seven projects containing ten offshore blocks in the Gulf of Mexico for $19.5 million, approximately $1.85/Mcfe for proved reserves, of which 93.5% were proved undeveloped reserves. 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 2005

The year 2005 was a year of major growth in proved reserves and significant progress towards a step change in production rates for ATP. The growth in reserves was accomplished through acquisitions during a period of historically high oil and gas prices and the recording of proved reserves at Cheviot in the North Sea. The significant progress in achieving a step change in production rates occurred in spite of one of the most catastrophic hurricane seasons ever experienced in the Gulf of Mexico. We also amended our Term Loan and added additional liquidity of $121.7 million, reduced our leverage by completing a $175.0 million preferred equity offering and added a capital lease for a portion of the development at Gomez in the Gulf of Mexico.

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The hurricane season of 2005 resulted in significant delays in our development activities and resulted in production losses in 2005 at many of our producing properties. Most of the physical damage to our assets was covered by our insurance. At December 31, 2005 we recorded a receivable for approximately $13.5 million (net of $0.5 million in deductibles for hurricanes Katrina and Rita) for our expected insurance recovery of damage assessment costs and repairs which were made during 2005. In 2006, we expect to incur additional insured repair and recovery costs related to these storms of less than $4.0 million. In addition the company expects to recover amounts under our loss of production insurance policy, however due to the uncertainty of the ultimate amount no receivable has been recorded for that expected recovery.

Reserves

At December 31, 2005, we had proved reserves of 527.5 Bcfe, of which 56% are located in the North Sea and the remaining 44% are in the Gulf of Mexico. The pre-tax PV10 of our proved reserves at December 31, 2005 was $2.7 billion. See “Item 2. Properties – Oil and Natural Gas Reserves” for reconciliation to after-tax PV10. In addition, we have scheduled for drilling or completion, properties where previous drilling into the targeted reservoirs indicates to the Company the presence of commercially productive quantities of hydrocarbons even though the reservoirs do not meet the SEC definition of proved reserves. Upon completion of drilling, completion or testing of wells on these blocks and similar properties in the Company’s portfolio, the Company anticipates that it may be able to record proved reserves associated with several of these properties.

Acquisitions

Gulf of Mexico

ATP was active in both of the Minerals Management Service sponsored offshore lease sales during 2005. In addition, ATP closed three transactions for the purchase of minerals in place during 2005. These purchases, which total $67.9 million in acquisition costs, resulted in recording 72.8 Bcfe of proved reserves, of which 40.4% were classified as proved developed.

Western Gulf of Mexico Offshore Lease Sale - ATP acquired three blocks for $2.9 million at the Western Gulf of Mexico Offshore Lease Sale 196 held on August 17, 2005. The blocks are located in approximately 200 to 750 feet of water. All three of the blocks have been previously drilled and the related logs indicate the presence of hydrocarbons. One of the blocks, High Island A-589, which was awarded to ATP in December 2005, has already been added to ATP’s 2006 development program. ATP holds a 100% working interest and serves as operator of each of the blocks.

Central Gulf of Mexico Offshore Lease Sale - ATP acquired seven blocks for $2.4 million at the Central Gulf of Mexico Offshore Lease Sale held March 16, 2005. Two of the blocks are adjacent to the Company’s wholly-owned Mississippi Canyon 711 development. Two additional blocks are contiguous to an existing ATP operated development in the West Cameron area and the remaining three blocks provide access to new development area opportunities. The blocks are located in approximately 125 to 2,900 feet of water. ATP owns a 100% working interest and serves as operator of each property.

South Marsh Island 166 - During the second quarter, ATP acquired South Marsh Island 166. We reentered and completed a temporarily abandoned well which had previously encountered hydrocarbons. As a result of this development work, proved developed reserves were recorded for this property at year-end 2005. ATP holds a 100% working interest in and operates South Marsh Island 166.

King’s Peak - ATP acquired a 55% working interest in the producing property King’s Peak in late September 2005. ATP operates this property located on Mississippi Canyon Blocks 173 and 217 and Desoto Canyon Blocks 133 and 177. King’s Peak contains an estimated 55.7 Bcfe of proved reserves. In addition, the property contains additional development potential from unproved drilling locations.

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Gulf of Mexico Shelf Package - On October 31, 2005, ATP acquired certain oil and gas properties located on the Gulf of Mexico Shelf and contain proved developed producing and proved developed non-producing reserves.

North Sea

Tors - ATP increased its net working interest ownership to 85% in the Tors fields, Garrow and Kilmar, through two separate transactions. First, ATP Oil & Gas (UK) Limited, a wholly-owned subsidiary, acquired a 25% working interest ownership from its partner in the second quarter 2005, and then sold a 15% working interest ownership to a new partner in the fourth quarter 2005. This purchase and sale allowed ATP to reduce its capital exposure and lower its development cost per Mcfe, with the net result of improving the overall return for the project and our shareholders.

Venture – During the fourth quarter of 2005, our wholly-owned subsidiary, ATP Oil & Gas (UK) Limited, increased its working interest ownership to 100% in the Venture field (Block 49/12a North) in the Southern Gas Basin of the U.K. North Sea. The Venture field is located in 75’ of water and has been defined by two vertical wells that have tested at rates of 35 MMcf per day and 74 MMcf per day. Development plans in 2006 include the design and construction of a production platform, the installation of a pipeline to an offset host platform, and the drilling of one well. Planned production is for the first half of 2007.

Operations and Development

Gulf of Mexico Shelf – On the Gulf of Mexico Shelf during 2005, six wells were drilled, including one dry hole. Four of the wells, WC 432 #1, MI 709 A4ST1, HI 74 #1, and BA 578 #1, were completed and placed on production. The remaining well, the SMI 166 #1, will be placed on production following hurricane related repairs and tie-ins to third-party infrastructure.

Mississippi Canyon 711 (MC 711) - During 2005, two wells were completed and made ready for production from the southern portion of the block, two 27-mile pipelines were installed, and the drilling vessel, Rowan Midland, was converted into a floating production platform and moored on location. As of March 8, 2006, development work was essentially complete and we are awaiting first production. ATP operates MC 711 with a 100% working interest.

Tors (Kilmar and Garrow) – During 2005, we constructed and installed the Kilmar jacket and deck, commenced well operations, and installed a 23-kilometer pipeline from Garrow to Kilmar and a 22-kilometer pipeline from Kilmar to an offsetting third-party platform. ENSCO 70 is completing the first of a five-well program after which production will commence. The Garrow platform is currently under construction and is expected to be installed later this year. ATP operates the Tors field with an 85% working interest.

L-06d - On February 27, 2006, we announced first production at L-06d in the Dutch North Sea. ATP now enjoys flowing production in all three of its core areas: the U.S. Gulf of Mexico, the U.K. North Sea, and Dutch North Sea. L-06d production is limited by the capacity of the facilities to 40 - 45 MMcf per day gross.

Cheviot – During 2005, we evaluated the 3-D seismic survey acquired in 2004, which along with comprehensive Geological and Geophysical (G&G) studies, helped to form a more detailed geologic

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picture of the Cheviot field. We then incorporated this information into a reservoir simulation model and completed the history match of the previous four-year production history of the field. Following optimization studies, we presented all data to a third-party reservoir engineering company, who ultimately assigned 182 Bcfe of proved reserves to the field. ATP operates Cheviot with a 100% working interest.

Financings

The progress we made in 2005 moving our projects closer to commercial production, despite a difficult hurricane season, was supported by three financings. During the second quarter, we amended and improved the terms of our Senior Secured Credit Facility by expanding it to $350.0 million, reducing the interest rate, and extending the maturity to April 2010. Net of transaction costs, this amendment added $121.7 million in additional liquidity. During the third quarter, we issued $175.0 million of non-convertible perpetual preferred stock, which raised net proceeds of $169.4 million. The security does not have a stated maturity and accrues a dividend of 13.5%. Such dividends may be paid in cash under the Preferred Stock Subscription Agreement upon the earlier to occur of full repayment of our existing Term Loan or April 15, 2011. During the fourth quarter, we structured a $44.8 million capital lease to finance the purchase of the drilling vessel, Rowan Midland, to serve as the floating production platform at our Mississippi Canyon 711 property.

Cash flow from operating activities was $43.6 million for the year ended December 31, 2005, compared to $41.2 million in cash flow from operating activities for 2004. We had working capital at December 31, 2005 of $0.6 million, a decrease of approximately $67.8 million from December 31, 2004. This decrease is attributable to our active 2005 capital program, which includes our two relatively large projects Mississippi Canyon 711 and Tors.

We had $65.6 million in cash and cash equivalents on hand at December 31, 2005, compared to $102.8 million in cash and cash equivalents at December 31, 2004. Cash paid for acquisition and development activities for the year 2005 was $420.5 million, compared to $87.4 million in 2004.

2006 Operational and Financial Objectives

We will continue to devote considerable resources to our developments in 2006. During the early part of the year, efforts will be spent completing and bringing to production two of our major developments begun in 2005, Mississippi Canyon 711 in the Gulf of Mexico and the Tors fields in the U.K. Sector of the North Sea. As of February 27, 2006, L-06d had been placed on production. As of March 9, 2006, Mississippi Canyon 711 had been placed on production. The first of three wells planned at the Kilmar portion of Tors fields has reached total depth and the well is going through completion activities. Additional drilling and completion activities are scheduled at both Mississippi Canyon 711 and at the Garrow portion of the Tors fields later in 2006.

In addition to these developments, projects with proved undeveloped reserves at December 31, 2005 that are scheduled for 2006 development, include Venture in the U.K. North Sea and South Marsh Island 189/190 and other properties in the Gulf of Mexico. We also have scheduled for drilling or completion properties in which previous drilling into targeted reservoirs indicates to the Company the presence of commercially productive quantities of hydrocarbons, although these reservoirs did not meet the SEC definition of proved reserves at the end of 2005. For example, High Island A-589 is a property that the Company believes to have commercially productive hydrocarbons and intends to develop in 2006 that is not included in our reserve report at year-end 2005.

We have commenced engineering and procurement activities on our Cheviot property in the U.K. North Sea. Cheviot, our largest property in terms of proved reserves, is a multi-year development with first

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production targeted in 2008. Other potential developments for 2006 in the Gulf of Mexico and North Sea are currently being evaluated. We believe that 2006 production will far exceed that of 2005 as a result of our 2003 through 2005 development programs and projects scheduled for development in 2006.

Our production may command higher realized oil and gas prices in 2006 than in recent years, based on our current hedge position and relatively strong commodity prices. Our revenues, profitability and cash flows are highly dependent upon many factors, particularly our production results and the price of oil and natural gas. To mitigate future price volatility, we may hedge additional production.

Results of Operations

For the year ended December 31, 2005, we reported a net loss available to common shareholders of $12.6 million or $0.43 per share, and for the years ended December 31, 2004 and 2003, we reported net income available to common shareholders of $1.4 million or $0.05 per share and a net loss available to common shareholders of $50.8 million or $2.21 per share, respectively.

Oil and Gas Revenues

Revenues presented in the table and the discussion below represent revenue from sales of our oil and natural gas production volumes. Production sold under fixed price delivery contracts, which have been designated for the normal purchase and sale exemption under SFAS 133, are also included in these amounts. Approximately 61%, 47% and 26% of our oil production was sold under these contracts for the years ended December 31, 2005, 2004 and 2003, respectively. Approximately 54%, 46% and 45% 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.

	Years Ended December 31,								% Change from 2004 to 2005		% Change from 2003 to 2004
	2005		2004			2003
Production (1):
Natural gas (MMcf)		15,614		17,816			10,842		(12	)%	64	%
Oil and condensate (MBbls)		717		765			1,042		(6	)%	(27	)%
Total (MMcfe)		19,914		22,408			17,093		(11	)%	31	%
Revenues (in thousands):
Natural gas	$	116,404	$	91,251		$	52,199		28	%	75	%
Effects of cash flow hedges		40		(1,198	)		(15,302	)	103	%	92	%
Total	$	116,444	$	90,053		$	36,897		29	%	144	%
Oil and condensate	$	30,041	$	25,970		$	29,601		16	%	(12	)%
Effects of cash flow hedges		—		—			(1,262	)	—		100	%
Total	$	30,041	$	25,970		$	28,339		16	%	(8	)%
Natural gas, oil and condensate		146,445		117,221			81,800		25	%	43	%
Effects of cash flow hedges		40		(1,198	)		(16,564	)	103	%	93	%
Total	$	146,485	$	116,023		$	65,236		26	%	78	%
Average realized sales price per unit:
Natural gas (per Mcf)	$	7.46	$	5.12		$	4.82		46	%	6	%
Effects of cash flow hedges (per Mcf)		—		(0.07	)		(1.41	)	100	%	95	%
Average realized price (per Mcf)	$	7.46	$	5.05		$	3.41		48	%	48	%
Oil and condensate (per Bbl)	$	41.92	$	33.93		$	28.42		24	%	19	%
Effects of cash flow hedges (per Bbl)		—		—			(1.21	)	—		100	%
Average realized price (per Bbl)	$	41.92	$	33.93		$	27.21		24	%	25	%
Natural gas, oil and condensate (per Mcfe)	$	7.35	$	5.23		$	4.79		41	%	9	%
Effects of cash flow hedges (per Mcfe)		—		(0.05	)		(0.97	)	100	%	95	%
Average realized price (per Mcfe)	$	7.35	$	5.18		$	3.82		42	%	36	%

(1) In the fourth quarter of 2003, we recorded a settlement of a commodity imbalance of 645 MMcfe from 2002 and 2001 that was excluded from production.

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

Oil and gas revenue increased 43% in 2004 compared to 2003 as the result of 12 properties brought on line during 2004, including our Helvellyn property, located in the U.K. Sector—North Sea. Another component of the increase was a 9% increase in our sales price per Mcfe in 2004 as compared to 2003. Due to the shut down of Helvellyn in September 2004 as a result of maintenance at the receiving terminal and the interruption of Gulf of Mexico production due to the hurricanes experienced during the third quarter of 2004, approximately 1.1 Bcfe of production was deferred into future periods.

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, 2005, 2004 and 2003 was as follows ($ in thousands):

	Years Ended December 31,						% Change from 2004 to 2005		% Change from 2003 to 2004
	2005		2004		2003
Lease operating expense	$	23,629	$	19,531	$	17,173	21	%	14	%
Per Mcfe	$	1.19	$	0.87	$	1.00	37	%	(13	)%

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

The 13% decrease per Mcfe in 2004 compared to 2003 was primarily attributable to the aforementioned increase in production. Additionally, workover activities in 2004 were significantly lower than in 2003.

Exploration

During 2005, exploration expense includes one exploratory, step-out well at our producing Eugene Island 30/71 complex. This well found non-commercial quantities of hydrocarbons, resulting in exploration and dry hole expense of approximately $5.3 million.

General and Administrative

General and administrative expenses are overhead-related expenses, including among others, wages and benefits, legal and accounting fees, insurance, and investor relations expenses. General and administrative expense for the years ended December 31, 2005, 2004 and 2003 was as follows ($ in thousands):

	Years Ended December 31,						% Change from 2004 to 2005		% Change from 2003 to 2004
	2005		2004		2003
General and administrative	$	24,274	$	15,806	$	12,209	54	%	29	%
Per Mcfe	$	1.22	$	0.71	$	0.71	72	%	0	%

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

The increase in 2004 compared to 2003, was primarily due to higher compensation related costs and professional fees related to the implementation of the requirements of Section 404 of the Sarbanes-Oxley Act of 2002.

Credit Facility Cost

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

Depreciation, Depletion and Amortization

Depreciation, depletion and amortization expense (“DD&A”) for the years ended December 31, 2005, 2004 and 2003 was as follows ($ in thousands):

	Years Ended December 31,						% Change from 2004 to 2005		% Change from 2003 to 2004
	2005		2004		2003
DD&A	$	64,069	$	55,637	$	29,378	15	%	89	%
Per Mcfe	$	3.22	$	2.48	$	1.72	30	%	44	%

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

DD&A expense increased 89% in 2004 as compared to 2003 primarily due to the 31% increase in production. The average DD&A per Mcfe increase was due primarily to the increased cost of development for those properties placed on production in 2003 and 2004 and to downward reserve revisions on six of our properties.

Impairments

On two of our properties in 2003, the future undiscounted cash flows were less than their individual net book value, resulting in impairments of $10.7 million in 2003. These impairments were the result of reductions in estimates of recoverable reserves. The impairments were calculated as the difference between the carrying value and the estimated fair value of the impaired depletable unit. We recorded an additional $1.0 million of impairment in 2003 related to SFAS 143. See Note 4, “Asset Retirement Obligations”, to the Consolidated Financial Statements.

(Gain) Loss on Abandonment

During 2005 and 2004, we recognized small net gains on the abandonment of certain properties which we were able to abandon at an aggregate cost less than the asset retirement obligation previously accrued. During 2003, we recognized a loss on abandonment of $5.0 million. Of this amount, approximately $4.4 million was attributable to actual costs exceeding the original estimates on two properties. These unforeseen overruns were a result of difficulties in abandoning one of our properties due to the condition of the wells received from the original owner and the collapse of a platform crane. In addition, we incurred significant standby time as a result of Hurricane Claudette.

(Gain) Loss 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 Southern Gas Basin of the U.K. Sector – North Sea and one property in the Gulf of Mexico. In 2004, we sold 25% of our interest in seven projects containing ten offshore blocks in the Gulf of Mexico and recognized a gain of $6.0 million.

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Loss on Unsuccessful Property Acquisition

During 2002 and 2003, ATP was in a dispute over a contract for the sale of an oil and gas property. The dispute was subsequently resolved and the other party was awarded $8.2 million. We paid this amount in the first quarter of 2004 and the Court dismissed the lawsuit on April 16, 2004.

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 aforementioned funding activities.

Interest Expense

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

Loss on Extinguishment of Debt

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

In the third quarter of 2003, we recognized a $3.4 million loss on the extinguishment of debt related to our prior credit agreement and the repayment of our note payable. The portion of the loss attributable to the prior credit facility ($0.9 million) was related to non-cash deferred financing costs.

Income Taxes

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

Preferred Dividends

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

Liquidity and Capital Resources

At December 31, 2005, we had working capital of approximately $0.6 million, a decrease of approximately $67.8 million from December 31, 2004. This decrease is primarily attributable to our development program and the increased costs of developments precipitated by the hurricanes in 2005. Historically, we have financed our acquisition and development activities through a combination of bank borrowings and proceeds from our equity offerings as well as cash from operations and by the sell-down of a portion of our interests in selected development projects. In 2005, we began developing several major projects which will require significant capital expenditures through the end of 2006. In order to fund these development costs, we expanded the borrowings under our Term Loan in April 2005, in August 2005 we completed a private placement of preferred stock for net proceeds of $169.4 million and in October we entered into a capital lease. As operator of all of our projects in development, we have the ability to significantly control the timing of most of our capital expenditures. We believe the cash flows from operating activities, new or amended debt or equity offerings combined with our ability to control the timing of substantially all of our future development and acquisition requirements will provide us with the flexibility and liquidity to meet our future planned capital requirements.

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Cash Flows

	Years Ended December 31,
	2005			2004			2003
	(in thousands)
Cash provided by (used in):
Operating activities	$	43,588		$	41,218		$	51,009
Investing activities		(414,072	)		(68,651	)		(84,043	)
Financing activities		335,514			125,698			30,654

Operating activities. Net cash provided by operating activities was $43.6 million for the year ended December 31, 2005 compared to $41.2 million for the year ended December 31, 2004. Cash flow from operations increased primarily due to the timing of settlements of operating receivables and payables and higher oil and gas revenues during 2005 compared to 2004. Gas sales increased by $26.4 million, or 29%, and oil sales increased by $4.1 million, or 16%. The increase in sales revenue was attributable to higher average oil and gas prices during 2005.

Investing activities. Cash used in investing activities in 2005 and 2004 was $414.1 million and $68.7 million, respectively. Cash paid for acquisition, development and exploration expenditures of oil and natural gas properties in the Gulf of Mexico and North Sea totaled approximately $296.1 million and $124.4 million, respectively, in 2005, offset by the receipt of $19.8 million in proceeds for the sale of properties. Such expenditures in the Gulf of Mexico and North Sea were approximately $78.5 million and $8.8 million, respectively, in 2004, offset by the receipt of $19.2 million in proceeds for the sale of certain interests in seven of our properties.

Financing activities. Cash provided by financing activities in 2005 consisted primarily of net proceeds of $121.7 million related to our amendment to the Term Loan, after deducting deferred financing costs of approximately $10.4 million related to the amendment and accrued interest and $169.4 million from the issuance of preferred stock, net of issuance costs. Cash provided by financing activities in 2004 consisted of net payments of $166.3 million related to our prior credit facility and net proceeds of $248.5 million related to our new Term Loan and warrants issued, after deducting deferred financing costs of approximately $13.5 million related to the new Term Loan. We repurchased all 750,000 warrants related to our prior credit facility and 1,926,837 warrants related to our term loan for $12.3 million. In addition, we received net proceeds of $53.1 million from a private placement sale of four million shares of common stock to accredited investors in 2004.

The Company’s restricted cash represents a time deposit denominated in British Pounds Sterling which secures an irrevocable stand-by letter of credit for our future abandonment obligations with respect to the Kilmar field in the North Sea. The Letter of Credit and Reimbursement Agreement has an initial term of one year, and it extends for successive one-year terms unless thirty days notice is given of the intention not to extend the letter of credit.

Term Loan

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

	December 31,
	2005			2004
Term loan, net of unamortized discount of $6,386 and $8,129	$	340,989			210,309
Less current maturities		(3,500	)		(2,200	)
Total long-term debt	$	337,489		$	208,109

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

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

On September 24, 2004, our lender consented to our repurchase of 1,926,837 of the 2,452,336 then outstanding second lien facility warrants for a price not to exceed $11,561,022. The warrants were repurchased on September 24, 2004 for $6.00 per warrant which, in management’s estimation, represented the then current fair value of the unregistered warrants. The $11.6 million partial repurchase was recorded as a decrease to additional paid in capital while the debt discount will continue to be amortized over the life of the loan.

On April 14, 2005, we increased our aggregate borrowings under the Term Loans by $132.1 million (from the balance outstanding as of March 31, 2005) to an aggregate outstanding principal amount of $350.0 million. From this increase in borrowings, we received net proceeds of $117.8 million after deducting $3.6 million for accrued and unpaid interest on the Term Loans up to the Amendment Date and $10.7 million for fees and expenses.

The terms of the Term Loan, as amended April 14, 2005, require us to maintain certain covenants. Capitalized terms are defined in the credit agreement for the Term Loan. The covenants include:

• Current Ratio of 1.0/1.0;

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

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

• Pre-tax PV-10 of our Total Proved Developed Producing Oil and Gas Reserves to Net Debt of at least 0.5/1.0 at June 30 and December 31 of any fiscal year;

• Pre-tax PV-10 of our Total Proved Oil and Gas Reserves to Net Debt of at least 2.5/1.0 at June 30 and December 31 of any fiscal year;

• the requirement to maintain Commodity Hedging Agreements on no less than 40% nor more than 80% of the next twelve months of forecasted production attributable to our proved producing reserves;

• the requirement to maintain a Maximum Leverage Ratio of no more than 3.0/1.0 at the end of any fiscal quarter;

• the requirement to maintain a Debt to Reserve Amount of no greater than $2.50 through maturity; provided, however, that if such amount is exceeded at the end of the fiscal year ending on December 31, 2005, the covenant shall be retested at June 30, 2006, and

• limit Permitted Business Investments, as defined, to $75.0 million during any fiscal year.

As of December 31, 2005, we were in compliance with all of the financial covenants of our Term Loan. Significant adverse changes in our expected production levels, commodity prices and reserves or material delays or cost overruns could have a material adverse affect on our financial condition and results of operations and result in our non-compliance with these covenants. An event of non-compliance with any of the required covenants could result in a material mandatory repayment under the Term Loan.

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Capital Lease

On October 19, 2005, ATP agreed to acquire the Rowan Midland mobile offshore drilling unit (“Vessel”) from Rowandrill, Inc. (“Rowan”) for modification for use as a floating offshore production unit at the Company’s Mississippi Canyon 711 development. The net purchase price of $50 million, after payment of $10.0 million at closing on October 19, 2005, is payable over the succeeding 15 month period (the “Interim Period”) in payments of $1,050,000 per month, with the remaining balance due to Rowan on January 31, 2007. At any time prior to January 31, 2007, the Company has the right, without penalty, to pay the remaining balance of the net purchase price. During the Interim Period, the Vessel is chartered to the Company for use in its production operations in the Gulf of Mexico. At its inception, the company recorded this transaction as a capital lease and recorded an oil and gas asset and corresponding capital lease obligation in the amount of $44.8 million.

Preferred Stock

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

The Subscription Agreement for the Preferred Stock provides for: (1) an initial liquidation preference of $1,000 per share; (2) cumulative quarterly dividends at an initial rate of 13.5%, subject to escalation in the applicable dividend rate under certain conditions; (3) no voting rights; (4) special provisions in the event of a fundamental change in the Company or the satisfaction of the Company’s currently outstanding debt; (5) limitations on incurrence of additional debt; and (6) restrictions on transfer or sale of the Preferred Stock.

The Company has the right to redeem the Preferred Stock at its option at any time after a fundamental change or the later of February 3, 2006 or the specified debt satisfaction date at a premium that declines until February 3, 2009, at which time the preferred stock may be redeemed at 100% of the liquidation preference plus accrued and unpaid dividends.

In the event of a fundamental change in the Company or the repayment of the currently outstanding debt, the Company must notify the preferred stockholders whether it will offer to redeem the preferred stock. If the Company chooses not to offer to redeem the preferred stock, then it will be deemed a fundamental change offer default or a debt satisfaction offer default, as the case may be, and the applicable dividend rate will escalate by 5% per quarter, to a maximum of 25%. Such escalation will continue until either of such defaults is cured, unless the Company has previously exercised its optional redemption right with respect to all of the shares of Series A preferred stock then outstanding. The Company is under no obligation to offer to redeem the preferred stock under any circumstances.

Through December 31, 2005, non-cash preferred dividends aggregating $9.9 million were accrued. Such dividends may be paid in cash under the Preferred Stock Subscription Agreement upon the earlier to occur of full repayment of our existing Term Loan or April 15, 2011.

On March 8, 2006, we announced that we plan to raise $100 million or more through a private placement of non-convertible, perpetual preferred stock (“Series B Preferred Stock”). The Series B Preferred Stock will not be registered under the Securities Act of 1933, and may not be offered or sold in the United States absent registration or an applicable exemption from registration requirements. The Series B Preferred Stock will be offered in a private placement in the United States pursuant to applicable exemptions under the Securities Act of 1933. The terms and conditions of the Subscription Agreement for the Series B Preferred Stock will be identical to that of the Series A Preferred Stock, except for the dividend rate, which may be different. We intend to use the net proceeds from this offering to expand our scope in certain projects, to accelerate our development activities and for general corporate purposes.

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

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

	December 31, 2005	December 31, 2004
Series A 13.5% cumulative perpetual preferred stock; liquidation preference of $1,056 per share; 175,000 shares issued and outstanding at December 31, 2005	184,858	—
Junior participating preferred stock pursuant to the Shareholders Rights Plan; none issued at December 31, 2005	—	—

Recently Issued Accounting Pronouncements

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

Contractual Obligations

We have various commitments primarily related to leases for office space, other property and equipment and other agreements. The following table summarizes certain contractual obligations at December 31, 2005 (in thousands):

	Payments Due By Period
Contractual Obligation	Total		Less Than 1 Year		1-3 Years		4-5 Years		After 5 Years
Long-term debt	$	347,375	$	3,500	$	7,000	$	336,875	$	—
Interest on long-term debt (1)		133,433		34,748		68,441		30,244		—
Long-term capital lease		43,116		8,679		34,437		—		—
Interest on capital lease (1)		4,208		3,921		287		—		—
Non-cancelable operating leases		2,774		755		1,364		636		19
Other long-term liabilities (2)		—		—		—		—		—
Total contractual obligations	$	530,906	$	51,603	$	111,529	$	367,755	$	19

(1) Interest is based on rates and quarterly principal payments in effect at December 31, 2005.

(2) In February 2003, we acquired a 50% working interest in a block located in the Dutch Sector - North Sea. We agreed to develop the property within 60 months from receipt of the funds or return the funds with interest if commercial production was not achieved at the expiration of such time. At December 31, 2005 the balance is reflected as a long-term liability of $8.8 million in the financial statements. The property was developed during 2005 and commenced production in February 2006. We expect to reclass this liability as a reduction to oil and gas properties in the first quarter of 2006 since our obligation under the agreement has now been fulfilled.

Our liabilities also include asset retirement obligations ($7.1 million current and $60.3 million long-term) that represent the estimated fair value at December 31, 2005 of our obligations with respect to the retirement/plugging and abandonment of our oil and gas properties. Each reporting period the liability is accreted to its then present value. The ultimate settlement amount and the timing of the settlement of such obligations is unknown because they are subject to, among other things, federal, state and local regulation and economic factors. See Note 2 to the Consolidated Financial Statements.

39

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 of proved oil and gas properties. Oil and gas reserve estimates, which are the basis for unit-of-production DD&A and the impairment analysis, are inherently imprecise and are expected to change as future information becomes available. In addition, alternatives may exist among various accounting methods. In such cases, the choice of accounting method may also have a significant impact on reported amounts.

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

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 costs relating to producing properties are depleted on the units-of-production method. Proved developed reserves are used in computing unit rates for drilling and development costs and total proved reserves for depletion rates of leasehold, platform and pipeline costs. 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.

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 periodically assessed and any impairment in value is charged to impairment expense. The costs of unproved properties are transferred to proved oil and gas properties upon meeting SEC requirements and amortized on a unit of production.

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 units-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. Most of our Gulf of Mexico reserves and all of our Netherlands reserves quantities are prepared annually by independent petroleum

40

engineers Ryder Scott Company, L.P. The remainder of our 2005 Gulf of Mexico reserves related to newly acquired properties were prepared by DeGolyer and MacNaughton and Collarini Associates. Our U.K. Sector – North Sea reserves are prepared annually by independent petroleum consultants RPS Energy (formerly RPS Troy-Ikoda). See the Supplemental Information (unaudited) in our consolidated financial statements for reserve data related to our properties.

Impairment Analysis

We perform an impairment analysis whenever events or changes in circumstances indicate that an asset’s carrying amount may not be recoverable. To determine if a depletable unit is impaired, we compare the carrying value of the depletable unit to the undiscounted future net cash flows by applying management’s estimates of future oil and gas prices to the estimated future production of oil and gas reserves over the economic life of the property. Future net cash flows are based upon reservoir engineers’ estimates of proved reserves. In addition, other factors such as probable and possible reserves are taken into consideration when justified by economic conditions and actual or planned drilling or other development activities. For a property determined to be impaired, an impairment loss equal to the difference between the carrying value and the estimated fair value of the impaired property will be recognized. Fair value, on a depletable unit basis, is estimated to be the present value of the aforementioned expected future net cash flows. An impairment allowance is provided on an unproved property when we determine that the property will not be developed. Any impairment charge incurred is recorded in accumulated depreciation, depletion, impairment and amortization to reduce our recorded basis in the asset. Each part of this calculation is subject to a large degree of judgment, including the determination of the depletable units’ estimated reserves, future cash flows and fair value.

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. SFAS 143 requires that we estimate the future cost of this obligation, discount it to its present value, and record a corresponding asset and liability in our consolidated balance sheets. The values ultimately derived are based on many significant estimates, including the ultimate expected cost of the obligation, the expected future date of the required cash payment, and interest and inflation rates. Revisions to these estimates may be required based on changes to cost estimates, the timing of settlement, and changes in legal requirements. Any such changes that result in upward or downward revisions in the estimated obligation will result in an adjustment to the related capitalized asset and corresponding liability on a prospective basis. See Note 2 to the Consolidated Financial Statements.

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, with the assistance of counsel makes estimates, if determinable, of ATP’s probable liabilities and records such amounts in the consolidated financial statements. Such estimates may be the minimum amount of a range of probable loss when no single best estimate is determinable. Disclosure is made, when determinable, of any additional possible amount of loss on these claims, or if such estimate cannot be made, that fact is disclosed. Along with our counsel, we monitor developments related to these legal matters and, when appropriate, we make adjustments to recorded liabilities to reflect current facts and circumstances. Although it is difficult to predict the ultimate outcome of these matters, management is not aware of any amounts that need to be recorded and believes that the recorded amounts, if any, are reasonable.

41

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, which have a high degree of historical correlation with actual prices we receive. Under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (“SFAS 133”), all derivative instruments, unless designated as normal purchases and sales, are recorded on the balance sheet at fair value. Changes in the derivative’s fair value are recognized currently in earnings unless specific hedge accounting criteria are met. For qualifying cash flow hedges, the gain or loss on the derivative is deferred in accumulated other comprehensive income (loss) to the extent the hedge is effective. For qualifying fair value hedges, the gain or loss on the derivative is offset by related results of the hedged item in the income statement. Gains and losses on hedging instruments included in accumulated other comprehensive income (loss) are reclassified to oil and natural gas sales revenue in the period that the related production is delivered. Derivative contracts that do not qualify for hedge accounting treatment are recorded as derivative assets and liabilities at market value in the consolidated balance sheet, and the associated unrealized gains and losses are recorded in oil and natural gas revenues. As of December 31, 2005, we had three derivative contracts in place that qualified as cash flow hedges and fourteen gas and oil fixed price futures contracts designated as normal sales contracts.

Valuation of Deferred Tax Asset

We compute income taxes in accordance with SFAS 109. The standard requires 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. SFAS 109 also requires the recording of a valuation allowance if it is more likely than not that some portion or all of a deferred tax asset will not be realized.

SFAS 109 provides for the weighing of positive and negative evidence in determining whether a deferred tax asset is recoverable. We have incurred net operating losses in 2003 and prior years. Relevant accounting guidance suggests that cumulative losses in recent years constitute significant negative evidence, and that future expectations about income are overshadowed by such history of losses. Delays in bringing properties on to production and development cost overruns in 2003 were also significant factors considered in evaluating our deferred tax asset valuation allowance. Accordingly, we established a valuation allowance of $33.6 million as of December 31, 2003. We achieved profitable operations in 2004; however the income generated in 2004 was not sufficient to overcome the negative evidence noted in the prior years. During 2005, we incurred a net loss before income taxes of $2.6 million. See Note 10 “Income Taxes” to the Consolidated Financial Statements.

Stock Based Compensation

We account for our stock-based employee compensation plans under the recognition and measurement principles of Accounting Principles Board (APB) Opinion No. 25, “Accounting for Stock Issued to Employees” (APB 25), and related interpretations. Under APB 25, no compensation expense is recognized when the exercise price of options equals the fair value (market price) of the underlying stock on the date of grant. We have not yet adopted the recently issued SFAS No. 123R, “Share-Based Payment: an Amendment of FASB Statements No 123 and 95” (“SFAS 123R”) and are currently evaluating the expected impact that the adoption of this pronouncement will have on our consolidated financial position, results of operations and cash flows. SFAS 123R is effective for all interim or annual periods beginning after June 15, 2005. See Note 3 “Recently Issued Accounting Pronouncements” to the Consolidated Financial Statements.

Off-Balance Sheet Arrangements

The Company has no off-balance sheet arrangements at December 31, 2005.

42

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

Interest Rate Risk

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

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. We have not utilized derivatives or other financial instruments to hedge the risk associated with the movement in foreign currencies.

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

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

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.

Management’s Report on Internal Control Over Financial Reporting

Management of ATP Oil & Gas Corporation (the “Company”) is responsible for establishing and maintaining adequate internal control over financial reporting for the Company, as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934. Under the supervision and with the participation of the Company’s management, including our principal executive and principal financial officers, the Company conducted an evaluation of the effectiveness of its internal control over financial reporting based on the framework in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the “COSO Framework”). Based on this evaluation under the COSO Framework which was completed on March 13, 2006, management concluded that its internal control over financial reporting was effective as of December 31, 2005.

43

Management’s assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2005 has been audited by the independent registered public accounting firm who audited the Company’s consolidated financial statements as of and for the year ended December 31, 2005, as stated in their report which is included herein.

Item 9B. Other Information.

None.

44

PART III

Item 10. Directors and Executive Officers of Registrant.

Except for the information relating to Executive Officers of the Registrant, which is included in Part 1, Item 4 of this Report, 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 7, 2006 (the “Proxy Statement”).

ATP has adopted a Code of Business Conduct and Ethics that applies to all of ATP’s employees, officers and directors, including its principal executive officer, principal financial officer, principal accounting officer and controller and is available on the Company’s internet website at www.atpog.com. In the event that an amendment to, or a waiver from, a provision of ATP’s Code of Business Conduct and Ethics that applies to any of ATP’s executive officers (including the principal executive officer, principal financial officer, principal accounting officer and controller), or directors is necessary, ATP intends to post such information on its website.

Item 11. Executive Compensation.

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

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

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

Item 13. Certain Relationships and Related Transactions.

None.

Item 14. Principal Accounting Fees and Services.

The information required by Item 15 of Form 10-K is incorporated by reference to the Company’s Proxy Statement.

45

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	Restated Bylaws, incorporated by reference to Exhibit 3.2 of ATP’s registration statement No. 333-46034 on Form S-1.
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	Statement of Resolutions Establishing the 13 1/2% Series A Cumulative Perpetual Preferred Stock of ATP, incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K, dated August 2, 2005.
4.4	Form of Subscription Agreement, incorporated by reference to Exhibit 4.3 to the Company’s Form 8-K, dated August 2, 2005.
4.5	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.
4.6	Statement of Designations of Junior Participating Preferred Stock, incorporated by reference to Exhibit 2 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 1998 Stock Option Plan, incorporated by reference to Exhibit 10.9 of ATP’s Registration Statement No. 333-46034 on Form S-1.
†10.2	First Amendment to the ATP Oil & Gas Corporation 1998 Stock Option Plan, incorporated by reference to Exhibit 10.10 of ATP’s registration statement No. 333-46034 on Form S-1.
†10.3	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.

46

10.4	First Lien Credit Agreement dated March 29, 2004, among ATP and Credit Suisse First Boston (“CSFB”), as administrative and funding agent, incorporated by reference to Exhibit 10.15 of ATP’s Form 10-K for the year ended December 31, 2003.
10.5	Second Lien Credit Agreement dated March 29, 2004, among ATP and CSFB, as administrative and funding agent, incorporated by reference to Exhibit 10.16 of ATP’s Annual Report on Form 10-K for the year ended December 31, 2003
10.6	Intercreditor Agreement dated as of March 29, 2004 among ATP and CSFB, as first and second lien collateral agents, incorporated by reference to Exhibit 10.17 of ATP’s Form 10-K for the year ended December 31, 2003
10.7	Amendment No. 1, Consent, Waiver and Agreement dated as of September 24, 2004 to the First Lien Agreement dated as of March 29, 2004, among ATP, the Lenders, 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 September 30, 2004
10.8	Amendment No. 1, Consent, Waiver and Agreement dated as of September 24, 2004 to the Second Lien Agreement dated as of March 29, 2004, among ATP, the Lenders, 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 September 30, 2004
10.9	Subscription and Registration Rights Agreement, incorporated by reference to Exhibit 10.1 of ATP’s Form 8-K filed on December 3, 2004
10.10	Amendment Agreement dated as of April 14, 2005, to the First Lien Credit Agreement dated as of March 29, 2004, as amended by Amendment No. 1, Consent, Waiver and Agreement dated as of September 24, 2004 among ATP, the Lenders from time to time party thereto and CSFB, as administrative agent and as collateral agent for the Lenders, incorporated by reference to Exhibit 10.1 to ATP’s Form 8-K filed on April 20, 2005.
10.11	Purchase and Sale Agreement, dated as of October 31, 2005, by and between Millennium Offshore Group, Inc. as seller and ATP as buyer, incorporated by reference to Exhibit 10.1 to ATP’s Form 10-Q for the quarter ended September 30, 2005.
10.12	Sale and Purchase Agreement, dated October 19, 2005, by and between Rowandrill, Inc. as seller and ATP as buyer, incorporated by reference to Exhibit 10.2 to ATP’s Form 8-K, dated October 19, 2005.
†10.13	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.
†10.14	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.
†10.15	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.
†10.16	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.
†10.17	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.
†10.18	Employment Agreement between ATP and Gerald W. Schlief, dated December 29, 2005, incorporated by reference to Exhibit 10.6 to ATP’s Form 8-K dated December 30, 2005.
†10.19	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.
†10.20	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.
†10.21	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.
†10.22	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.

47

†10.23	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.
†10.24	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.
16.1	Letter from KPMG LLP, incorporated by reference to Exhibit 16.1 of ATP’s Form 8-K filed on April 23, 2004
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 KPMG LLP.
*23.3	Consent of Ryder Scott Company.
*23.4	Consent of RSP Energy.
*23.5	Consent of Collarini Associates.
*23.6	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

48

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 14, 2006.

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

49

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

	Page
Report of Independent Registered Public Accounting Firm	F-2
Report of Independent Registered Public Accounting Firm	F-4
Consolidated Balance Sheets as of December 31, 2005 and 2004	F-5
Consolidated Statements of Operations for the years ended December 31, 2005, 2004 and 2003	F-6
Consolidated Statements of Cash Flows for the years ended December 31, 2005, 2004 and 2003	F-7
Consolidated Statements of Shareholders’ Equity for the years ended December 31, 2005, 2004 and 2003	F-8
Consolidated Statements of Comprehensive Income (Loss) for the years ended December 31, 2005, 2004 and 2003	F-9
Notes to Consolidated Financial Statements	F-10
Supplemental Information About Oil and Gas Producing Activities	F-29
Schedule II – Valuation and Qualifying Accounts	S-1

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

F-1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders 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, 2005 and 2004, and the related consolidated statements of operations, shareholders’ equity, comprehensive income (loss), and cash flows for each of the two years in the period ended December 31, 2005. We also have audited management’s assessment, included in the accompanying Management’s Report on Internal Control Over Financial Reporting, that the Company maintained effective internal control over financial reporting as of December 31, 2005, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for these financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on these financial statements and financial statement schedules, an opinion on management’s assessment, and an opinion on the effectiveness of the Company’s internal control over financial reporting based on our audits.

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

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

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

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2005 and 2004, and the results of its

F-2

operations and its cash flows for each of the two years in the period ended December 31, 2005, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, management’s assessment that the Company maintained effective internal control over financial reporting as of December 31, 2005, is fairly stated, in all material respects, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Furthermore, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2005, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

As discussed in Note 2 to the consolidated financial statements, effective January 1, 2003, the Company changed its method of accounting for asset retirement obligations.

DELOITTE & TOUCHE LLP

Houston, Texas

March 15, 2006

F-3

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors

ATP Oil & Gas Corporation:

We have audited the accompanying consolidated statements of operations, shareholders’ equity, comprehensive loss, and cash flows of ATP Oil & Gas Corporation and subsidiaries (the Company) for the year ended December 31, 2003. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audit.

We conducted our audit in accordance with 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 consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. 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 audit provides a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the results of operations and cash flows of ATP Oil & Gas Corporation and subsidiaries for the year ended December 31, 2003, in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 2 to the consolidated financial statements, effective January 1, 2003, the Company changed its method of accounting for asset retirement obligations.

KPMG LLP

Houston, Texas

March 29, 2004

F-4

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(In Thousands, Except Share Amounts)

	December 31,
	2005			2004
Assets
Current assets:
Cash and cash equivalents	$	65,566		$	102,774
Restricted cash		12,209			—
Accounts receivable (net of allowance of $367 and $1,499)		83,571			36,991
Derivative asset		—			791
Other current assets		4,454			3,788
Total current assets		165,800			144,344
Oil and gas properties (using the successful efforts method of accounting):
Proved properties		890,402			439,887
Unproved properties not subject to amortization		8,882			10,516
		899,284			450,403
Less: Accumulated depletion, impairment and amortization		(271,863	)		(237,197	)
Oil and gas properties, net		627,421			213,206
Furniture and fixtures (net of accumulated depreciation)		1,175			741
Deferred tax asset		4,025			—
Other assets, net		25,342			13,856
Total assets	$	823,763		$	372,147
Liabilities and Shareholders’ Equity
Current liabilities:
Accounts payable and accruals	$	144,675		$	68,573
Current maturities of long-term debt		3,500			2,200
Current maturities of long-term capital lease		8,679			—
Asset retirement obligation		7,097			4,925
Derivative liability		1,282			316
Total current liabilities		165,233			76,014
Long-term debt		337,489			208,109
Long-term capital lease		34,437			—
Asset retirement obligation		60,267			19,998
Deferred revenue		—			741
Other long-term liabilities and deferred obligations		8,826			10,121
Total liabilities		606,252			314,983
Shareholders’ equity:
Preferred stock: $0.001 par value, 10,000,000 shares authorized; 175,000 shares issued and outstanding at December 31, 2005		184,858			—
Common stock: $0.001 par value, 100,000,000 shares authorized; 29,668,517 issued and 29,592,677 outstanding at December 31, 2005; 28,959,701 issued and 28,883,861 outstanding at December 31, 2004		29			29
Additional paid in capital		149,267			140,628
Accumulated deficit		(101,333	)		(88,759	)
Accumulated other comprehensive income (loss)		(4,693	)		6,177
Unearned compensation		(9,706	)		—
Treasury stock, at cost		(911	)		(911	)
Total shareholders’ equity		217,511			57,164
Total liabilities and shareholders’ equity	$	823,763		$	372,147

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)

	Years Ended December 31,
	2005			2004			2003
Revenues:
Oil and gas production	$	146,674		$	116,123		$	70,151
Costs and operating expenses:
Lease operating		23,629			19,531			17,173
Exploration		6,208			997			1,358
General and administrative		24,274			15,806			12,209
Credit facility		—			1,850			1,990
Non-cash compensation		57			—			(39	)
Depreciation, depletion and amortization		64,069			55,637			29,378
Impairment of oil and gas properties		—			—			11,670
Accretion		3,238			2,069			2,752
(Gain) loss on abandonment		(732	)		(251	)		4,973
Gain on disposition of properties		(2,743	)		(6,011	)		—
Loss on unsuccessful property acquisition		—			—			8,192
Other		—			400			—
		118,000			90,028			89,656
Income (loss) from operations		28,674			26,095			(19,505	)
Other income (expense):
Interest income		4,064			627			52
Interest expense		(35,720	)		(22,262	)		(9,678	)
Loss on extinguishment of debt		—			(3,326	)		(3,352	)
Other		419			280			2,244
		(31,237	)		(24,681	)		(10,734	)
Income (loss) before income taxes and cumulative effect of change in accounting principle		(2,563	)		1,414			(30,239	)
Income tax expense		(153	)		(58	)		(21,224	)
Income (loss) before cumulative effect of change in accounting principle		(2,716	)		1,356			(51,463	)
Cumulative effect of change in accounting principle, net of tax		—			—			662
Net income (loss)		(2,716	)		1,356			(50,801	)
Preferred dividends		(9,858	)		—			—
Net income (loss) available to common shareholders	$	(12,574	)	$	1,356		$	(50,801	)
Basic and diluted income (loss) available to common shareholders per share:
Income (loss) before cumulative effect of change in accounting principle	$	(0.43	)	$	0.05		$	(2.24	)
Cumulative effect of change in accounting principle, net of tax		—			—			0.03
Net income (loss) available to common shareholders		(0.43	)		0.05			(2.21	)
Weighted average number of outstanding common shares:
Basic		29,080			24,944			22,975
Diluted		29,080			25,271			22,975

See accompanying notes to the consolidated financial statements.

F-6

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In Thousands)

	Years Ended December 31,
	2005			2004			2003
Cash flows from operating activities:
Net income (loss)	$	(2,716	)	$	1,356		$	(50,801	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities –
Depreciation, depletion and amortization		64,069			55,637			29,378
Impairment of oil and gas properties		—			—			11,670
Gain on disposition of properties		(2,743	)		(6,011	)		—
Accretion of asset retirement obligation		3,238			2,069			2,752
Dry hole costs		5,341			—			—
Amortization of deferred financing costs		4,173			2,471			1,395
Loss on extinguishment of debt		—			3,326			883
Deferred tax assets		—			—			21,224
Non-cash compensation		57			—			(39	)
Cumulative effect of change in accounting principle		—			—			(662	)
Ineffectiveness of cash flow hedges		(189	)		190			300
Non-cash interest and credit facility expenses		1,742			1,709			5,567
Deferred income taxes		(3,949	)		—			—
Other non-cash items		(1,075	)		1,585			2,712
Changes in assets and liabilities –
Accounts receivable and other assets		(43,095	)		(22,355	)		9,775
Derivative liability		—			(166	)		(5,074	)
Accounts payable and accruals		23,212			3,822			20,091
Other long-term assets		(3,781	)		36			—
Other long-term liabilities and deferred obligations		(696	)		(2,451	)		1,424
Net cash provided by operating activities		43,588			41,218			50,595
Cash flows from investing activities:
Acquisitions and development of oil and gas properties		(420,516	)		(87,368	)		(83,803	)
Proceeds from disposition of properties		19,820			19,200			—
(Increase) decrease in restricted cash		(12,476	)		—			414
Additions to furniture and fixtures		(900	)		(483	)		(240	)
Net cash used in investing activities		(414,072	)		(68,651	)		(83,629	)
Cash flows from financing activities:
Net proceeds from secondary offering		—			53,066			10,879
Proceeds from long-term debt		132,113			262,000			127,168
Principal payments of long-term debt		(3,175	)		(166,230	)		(103,921	)
Proceeds from capital lease		44,774			—			—
Principal payments of capital lease		(1,658	)		—			—
Deferred financing costs		(10,416	)		(13,502	)		(3,827	)
Repurchase of warrants		—			(12,311	)		—
Exercise of stock options		4,507			—			—
Issuance of preferred stock, net of issuance costs		169,437			—			—
Other		(68	)		2,675			355
Net cash provided by financing activities		335,514			125,698			30,654
Effect of exchange rate changes on cash		(2,238	)		(55	)		—
Increase (decrease) in cash and cash equivalents		(37,208	)		98,210			(2,380	)
Cash and cash equivalents, beginning of period		102,774			4,564			6,944
Cash and cash equivalents, end of period	$	65,566		$	102,774		$	4,564

See accompanying notes to the consolidated financial statements.

F-7

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY

(In Thousands)

	2005				2004				2003
	Shares	Amount			Shares	Amount			Shares	Amount
Preferred Stock
Balance, beginning of year	—	$	—		—	$	—		—	$	—
Issuance of preferred stock	175		175,000		—		—		—		—
Preferred dividends	—		9,858		—		—		—		—
Balance, end of year	175	$	184,858		—	$	—		—	$	—
Common Stock
Balance, beginning of year	28,884	$	29		24,520	$	25		20,322	$	20
Issuances of common stock Secondary offering	—		—		4,000		4		4,000		4
Exercise of stock options	443		—		364		—		198		1
Restricted stock	265		—		—		—		—		—
Balance, end of year	29,592	$	29		28,884	$	29		24,520	$	25
Paid-in Capital
Balance, beginning of year		$	140,628			$	92,277			$	81,087
Issuances of capital stock Secondary offering			—				53,062				10,875
Exercise of stock options			4,505				2,675				354
Preferred stock offering costs			(5,628	)			—				—
Value of warrants issued in connection with financings			—				4,925				—
Repurchase of warrants			—				(12,311	)			—
Restricted stock			9,762				—				(39	)
Balance, end of year		$	149,267			$	140,628			$	92,277
Accumulated Deficit
Balance, beginning of year		$	(88,759	)		$	(90,115	)		$	(39,314	)
Net income (loss)			(2,716	)			1,356				(50,801	)
Preferred dividends			(9,858	)			—				—
Balance, end of year		$	(101,333	)		$	(88,759	)		$	(90,115	)
Accumulated Other Comprehensive Income (Loss)
Balance, beginning of year		$	6,177			$	3,056			$	(2,335	)
Other comprehensive income (loss)			(10,870	)			3,121				5,391
Balance, end of year		$	(4,693	)		$	6,177			$	3,056
Unearned Compensation
Balance, beginning of year		$	—			$	—			$	—
Restricted stock			(9,706	)			—				—
Balance, end of year		$	(9,706	)		$	—			$	—
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		$	217,511			$	57,164			$	4,332

See accompanying notes to the consolidated financial statements.

F-8

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(In Thousands)

	Years Ended December 31,
	2005			2004			2003
Net income (loss)	$	(2,716	)	$	1,356		$	(50,801	)
Other comprehensive income (loss):
Reclassification adjustment for settled contracts, net of tax		5			1,055			(627	)
Change in fair value of outstanding hedge positions, net of tax		(1,759	)		(532	)		3,651
Foreign currency translation adjustment, net of tax		(9,116	)		2,598			2,367
Other comprehensive income (loss)		(10,870	)		3,121			5,391
Comprehensive income (loss)	$	(13,586	)	$	4,477		$	(45,410	)

See accompanying notes to the consolidated financial statements.

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 are not 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 Energy), ATP Oil & Gas (UK) Limited and ATP Oil & Gas Netherlands (B.V.). All intercompany transactions are eliminated upon consolidation. Certain reclassifications have been made to the prior year statements 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 obligations with respect to the Kilmar field in the North Sea. The Letter of Credit and Reimbursement Agreement was entered into on July 18, 2005 with an initial term of one year, and it extends for successive one-year terms unless thirty days notice is given of the intention not to extend the letter of credit.

Oil and Gas Producing Activities.

We follow the “successful efforts” method of accounting for oil and gas properties. Under this 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 costs relating to producing properties are depleted on the unit-of-production method. Proved developed reserves are used in computing unit rates for drilling and development costs and total proved reserves for depletion rates of leasehold, platform and pipeline costs. 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 consolidated 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 in accordance with SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets” (“SFAS 144”). To determine if a depletable unit is impaired,

F-10

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

we compare the carrying value of the depletable unit to the undiscounted future net cash flows by applying management’s estimates of future oil and gas prices to the estimated future production of oil and gas reserves over the economic life of the property. Future net cash flows are based upon our independent reservoir engineer’s estimate of proved reserves. In addition, other factors such as probable and possible reserves are taken into consideration when justified by economic conditions and actual or planned drilling or other development activities. For a property determined to be impaired, an impairment loss equal to the difference between the carrying value and the estimated fair value of the impaired property will be recognized. Fair value, on a depletable unit basis, is estimated to be the present value of the aforementioned expected future net cash flows. Any impairment charge incurred is recorded in accumulated depreciation, depletion, impairment and amortization to reduce our recorded basis in the asset. Each part of this calculation is subject to a large degree of judgment, including the determination of the depletable units’ reserves, future cash flows and fair value. We recorded no impairments in 2005 and 2004 and recorded impairments of $11.7 million for the year ended December 31, 2003, primarily due to either depressed oil and natural gas prices, unfavorable operating performance or downward revisions of recoverable reserves or a combination of all.

Unproved oil and gas 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. As of December 31, 2005, no impairments have been recorded on unproved properties.

Asset Retirement Obligations.

Effective January 1, 2003, we adopted SFAS No. 143, “Accounting for Asset Retirement Obligations” (“SFAS 143”). SFAS 143 applies to obligations associated with the retirement of tangible long-lived assets that result from the acquisition, construction and development of the assets and applies whenever law or regulation will eventually require that we abandon those assets. SFAS 143 requires that 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.

At adoption, we recorded a liability for asset retirement obligations of $23.1 million (using a 12.5% discount rate) and a net-of-tax cumulative effect of change in accounting principle of $0.7 million and a related addition to oil and gas properties. Until the assets are ultimately sold or abandoned, we will recognize (i) depletion expense on the additional capitalized costs; (ii) accretion expense as the present value of the future asset retirement obligation increases with the passage of time, and; (iii) the impact, if any, of changes in estimates of the liability. The following table sets forth a reconciliation of the beginning and ending asset retirement obligation for the periods ended December 31, 2005, 2004 and 2003 (in thousands):

	December 31,
	2005			2004			2003
Asset retirement obligation, beginning of year	$	24,923		$	21,107		$	—
Liabilities upon adoption of SFAS 143 on January 1, 2003		—			—			23,135
Liabilities incurred		43,685			3,239			1,392
Liabilities settled		(2,998	)		(1,185	)		(12,170	)
Accretion expense		3,238			2,069			2,752
Foreign currency translation		(525	)		704			—
Loss on abandonment		(732	)		—			4,973
Change in estimate		217			—			1,025
Liabilities settled – assets sold		(444	)		(1,011	)		—
Asset retirement obligation, end of year	$	67,364		$	24,923		$	21,107

Capitalized Interest.

Interest costs during the development phase of certain long-term assets are capitalized and amortized over the related assets’ estimated useful lives. For the year ended December 31, 2003, interest of $0.5 million was capitalized. No interest was capitalized in 2004 and 2005.

F-11

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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.

Other Assets.

Other assets consist of the following (in thousands):

	December 31,
	2005			2004
Debt financing costs	$	23,882		$	13,466
Spare parts inventory		7,370			2,126
Other		50			51
		31,302			15,643
Accumulated amortization		(5,960	)		(1,787	)
	$	25,342		$	13,856

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 or straight-line method (which approximates 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 coincides with our 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 the 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.

Major Customers.

We sell a portion of our oil and gas to end users through various gas marketing companies. For the year ended December 31, 2005, revenues from three purchasers accounted for 48%, 14% and 12%, respectively, of oil and gas production revenues. For the year ended December 31, 2004, revenues from four purchasers accounted for 35%, 21%, 17% and 15%, respectively, of oil and gas production revenues. For the year ended December 31, 2003, revenues from four purchasers accounted for 36%, 35% 15% and 11%, respectively, of oil and gas production revenues. Percentages are calculated on oil and gas revenues before any effects of price risk management activities.

F-12

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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.

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.

Comprehensive Income (Loss)

Comprehensive income (loss) is net income or loss, plus certain other items that are recorded directly to shareholders’ equity. In 2005 and 2003, comprehensive loss was $13.6 million and $45.4 million, respectively. In 2004, comprehensive income was $4.5 million.

Stock-based Compensation.

We have two stock-based employee compensation plans and account for these plans under the recognition and measurement principles of Accounting Principles Board (APB) Opinion No. 25, “Accounting for Stock Issued to Employees” (APB 25), and related interpretations. Under APB 25, no compensation expense is recognized when the exercise price of options equals the fair value (market price) of the underlying stock on the date of grant.

The following table illustrates the effect on net income and earnings per share if we had applied the fair value recognition provisions of SFAS No. 123 “Accounting for Stock Based Compensation” (“SFAS 123”), as amended by SFAS 148 (in thousands, except per share amounts):

	Years Ended December 31,
	2005			2004			2003
Net income (loss) available to common before cumulative effect of change in accounting principle, as reported	$	(12,574	)	$	1,356		$	(51,463	)
Add: Stock based employee compensation expense included in reported net loss, determined under APB 25, net of related tax effects		—			—			(26	)
Deduct: Total stock based employee compensation Expense determined under fair value for all awards, net of related tax effects		(350	)		(51	)		(1,013	)
Pro forma net income (loss) available to common before cumulative effect of change in accounting principle	$	(12,924	)	$	1,305		$	(52,502	)
Earnings (loss) per share:
Basic and diluted – as reported	$	(0.43	)	$	0.05		$	(2.24	)
Basic and diluted – pro forma	$	(0.44	)	$	0.05		$	(2.29	)

See Note 3 “Recently Issued Accounting Pronouncements” below regarding the impact of the adoption of SFAS No. 123R “Share-Based Payment: an Amendment of FASB Statements No 123 and 95” (“SFAS 123R”).

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. Bank debt is variable rate debt and as such, approximates fair values, as interest rates are variable based on prevailing market rates.

Derivative Instruments.

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

Note 3 — Recently Issued Accounting Pronouncements

In February 2006, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 155, “Accounting for Certain Hybrid Financial Instruments – an amendment of FASB Statements No. 133 and 140.” SFAS No. 155 simplifies the accounting for certain hybrid financial instruments, eliminates the FASB’s interim guidance which provides that beneficial interests in securitized financial assets are not subject to the provisions of SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” and eliminates the restriction on the passive derivative instruments that a qualifying special-purpose entity may hold. SFAS No. 155 is effective for all financial instruments acquired or issued after the beginning of an entity’s first fiscal year that begins after September 15, 2006. We do not expect this Statement to have a material impact on our consolidated financial position, results of operations or cash flows.

In November 2005, the FASB issued Staff Position (“FSP”) No. FAS 123(R)-3, “Transition Election Related to Accounting for the Tax Effects of Share-Based Payment Awards,” which provided a practical transition election related to accounting for the tax effects of share-based payment awards to employees as an alternative to the method set forth in paragraph 81 of Statement of Financial Accounting Standards (“SFAS”) No. 123(R). An entity that adopts SFAS No. 123(R) using either the modified retrospective or the modified prospective application may make a one-time election to adopt the transition methodology described in this FSP up to one year after the later of its adoption of SFAS 123(R) or the effective date of this FSP. The Company must adopt SFAS 123(R) and related guidance on January 1, 2006 for its outstanding unvested awards as well as for awards granted, modified, repurchased or canceled on or after that date. The Company is evaluating the potential impact of compensation expense expected to be recognized as a result of adoption of this SFAS 123(R) and related guidance (some of which is discussed below) and has not yet determined if it will make the one-time election allowed by this FSP.

In November 2005, the FASB issued FSP Nos. FAS 115-1 and FAS 124-1, “The Meaning of Other-Than-Temporary Impairment and Its Application to Certain Investments,” which addresses the determination as to when an investment in certain debt and equity securities is considered impaired, whether that impairment is other than temporary, and the measurement of an impairment loss. It also addresses accounting considerations subsequent to the recognition of an other-than-temporary impairment and requires certain disclosures about unrealized losses that have not been recognized as other-than-temporary impairments. We will apply this guidance on January 1, 2006 and do not expect it to have a material impact on our consolidated financial position, results of operations or cash flows.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

In October 2005, the FASB issued FSP No. FAS 13-1, “Accounting for Rental Costs Incurred during a Construction Period.” FSP No. 13-1 provides additional guidance in applying the provisions of SFAS No. 13, “Accounting for Leases,” and Technical Bulletin 85-3, “Accounting for Operating Leases with Scheduled Rent Increases,” by clarifying that there is no distinction between the right to use a leased asset during the construction period and the right to use the asset after the construction period. Therefore, rental costs associated with ground or building operating leases that are incurred during a construction period shall be recognized as rental expense and the rental cost shall be included in income from continuing operations. FSP No. 13-1 is effective for the first reporting period beginning after December 15, 2005. A lessee shall cease capitalizing rental costs as of the effective date of FSP No. 13-1 for operating lease arrangements entered into prior to the effective date. Retrospective application in accordance with SFAS No. 154, “Accounting Changes and Error Corrections,” is permitted but not required. Accordingly, we will adopt this guidance effective January 1, 2006 and do not expect it to have a material impact on our consolidated financial position, results of operations or cash flows.

In September 2005, the Emerging Issues Task Force (EITF) reached a consensus on Issue No. 04-13, “Accounting for Purchases and Sales of Inventory with the Same Counterparty.” EITF Issue 04-13 requires that purchases and sales of inventory with the same counterparty in the same line of business should be accounted for as a single non-monetary exchange, if entered into in contemplation of one another. The consensus is effective for inventory arrangements entered into, modified or renewed in interim or annual reporting periods beginning after March 15, 2006. We do not expect the adoption of this EITF Issue to have a material impact on our consolidated financial position, results of operations or cash flows.

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

In May 2005, the FASB issued SFAS No. 154, “Accounting Changes and Error Corrections—a replacement of APB Opinion No. 20 and FASB Statement No. 3.” SFAS No. 154 changes the requirements for the accounting and reporting of a change in accounting principle, including voluntary changes in accounting principle and changes required by an accounting pronouncement that does not include specific transition provisions. SFAS No. 154 requires retrospective application to prior period financial statements of changes in accounting principle. If impractical to determine either the period-specific effects or the cumulative effect of the change, the new accounting principle would be applied as if it were adopted prospectively from the earliest date practical. The correction of errors in prior period financial statements should be identified as a “restatement.” SFAS No. 154 is effective for fiscal years beginning after December 15, 2005. Accordingly, we will adopt this statement effective January 1, 2006 and do not expect it to have a material impact on our consolidated financial position, results of operations or cash flows.

In April 2005, the FASB issued FSP No. FAS 19-1, “Accounting for Suspended Well Costs.” FSP No. 19-1 amends SFAS No. 19, “Financial Accounting and Reporting by Oil and Gas Producing Companies,” to allow continued capitalization of exploratory well costs beyond one year from the date drilling was completed under circumstances where the well has found a sufficient quantity of reserves to justify its completion as a producing well and the enterprise is making sufficient progress assessing the reserves and the economic and operating viability of the project. FSP No. 19-1 also amends SFAS No. 19 to require enhanced disclosures of

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

suspended exploratory well costs in the notes to the financial statements for annual and interim periods when there has been a significant change from the previous disclosure. We adopted the new requirements in the current period and it did not have a material impact on our consolidated financial position, results of operations or cash flows.

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

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

In December 2004, the FASB issued SFAS No. 153, “Exchanges of Nonmonetary Assets, an Amendment of APB Opinion No. 29,” which provides that all nonmonetary asset exchanges that have commercial substance must be measured based on the fair value of the assets exchanged and any resulting gain or loss recorded. An exchange is defined as having commercial substance if it results in a significant change in expected future cash flows. Exchanges of operating interests by oil and gas producing companies to form a joint venture continue to be exempted. APB Opinion No. 29 previously exempted all exchanges of similar productive assets from fair value accounting, therefore resulting in no gain or loss recorded for such exchanges. SFAS No. 153 became effective for fiscal periods beginning on or after June 15, 2005. We adopted SFAS No. 153 effective July 1, 2005. The adoption of SFAS No. 153 did not have a material impact on consolidated financial position, results of operations or cash flows.

In November 2004, the FASB issued SFAS No. 123(R), “Accounting for Share-Based Payment.” This statement requires companies to measure and recognize compensation expense for all stock-based payments. In addition, companies will be required to calculate this compensation using the fair-value based method, versus the intrinsic value method previously allowed under SFAS No. 123, “Accounting for Stock-Based Compensation.” As issued, this revision was effective for interim periods beginning after June 15, 2005. On April 14, 2005, the Securities and Exchange Commission amended the compliance date for SFAS No. 123(R) to the beginning of the fiscal year that begins after June 15, 2005, or January 1, 2006 for the Company.

Note 4 — Supplemental Disclosures of Cash Flow Information

Supplemental disclosures of cash flow information:

	2005		2004		2003
Cash paid during the year for interest	$	28,085	$	17,879	$	3,187
Cash paid during the year for income taxes	$	—	$	150	$	—

Note 5 — Acquisitions and Dispositions

Gulf of Mexico

On March 16, 2005, ATP was the apparent high bidder and was subsequently awarded seven blocks relating to its winning bids totaling $2.4 million at the Central Gulf of Mexico Offshore Lease Sale. ATP owns a 100% working interest in and is the operator of all seven blocks. Two of the blocks are adjacent to the

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Company’s wholly-owned Mississippi Canyon 711 development. Two additional blocks are contiguous to an existing ATP operated development in the West Cameron area and the remaining three blocks provide for new development area opportunities. Also, in the second quarter of 2005, ATP acquired 100% of the working interest in South Marsh Island 166. The property has a temporarily abandoned well which was reentered and completed in 2005.

On September 21, 2005, ATP acquired all of BP Exploration & Production Inc.’s (“BP”) interest in four Federal oil and gas leases covering Mississippi Canyon Blocks 173/217 and Desoto Canyon Blocks 133/177, offshore Gulf of Mexico, an oil and gas discovery area named “King’s Peak.” The acquisition also included all of BP’s interest in the Canyon Express Pipeline System. The adjusted purchase price for this acquisition was $18.6 million.

On October 12, 2005, ATP was awarded two blocks relating to its winning bids at the Western Gulf of Mexico Offshore Lease Sale held in New Orleans on August 17, 2005. On December 15 the Minerals Management Service awarded a third block to the Company on which it was the apparent high bidder. ATP is the operator and has a 100% working interest in the blocks, Garden Banks 228, High Island A-391 and High Island A-589, which were awarded at a total cost of approximately $2.9 million dollars.

On October 19, 2005, ATP agreed to acquire the Rowan Midland mobile offshore drilling unit (“Vessel”) from Rowandrill, Inc. (“Rowan”) for modification for use as a floating offshore production unit at the Company’s Mississippi Canyon 711 development. The net purchase price of $50.0 million, after payment of $10.0 million at closing on October 19, 2005, is payable over the succeeding 15 month period (the “Interim Period”) in payments of $1,050,000 per month, with the remaining balance due to Rowan on January 31, 2007. At any time prior to January 31, 2007, the Company has the right, without penalty, to pay the remaining balance of the net purchase price. During the Interim Period, the Vessel is chartered to the Company for use in its production operations in the Gulf of Mexico. At its inception, the company recorded this transaction as a capital lease and recorded an oil and gas asset and corresponding capital lease obligation in the amount of $44.8 million.

On October 31, 2005, ATP acquired substantially all of the oil and gas assets of a privately held company, consisting of 19 blocks located on the Gulf of Mexico Outer Continental Shelf in less than 600 feet of water. The reserves are approximately 80% gas and 20% oil and are included in our year-end reserve report. The preliminary adjusted purchase price was $50.0 million in cash (including $10.0 million that was paid upon the attainment of certain cumulative production) plus net liabilities assumed totaling an estimated $14.5 million for future property abandonment operations. The purchase price was allocated $64.0 million to proved oil and gas property, and $0.5 million to unproved property. The acquisition was effective October 1, 2005, and accordingly, the proved property purchase price allocation is expected to be adjusted in future periods in a post-closing settlement expected to occur early in 2006 as settlement components are finalized.

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

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

U.K. Sector - North Sea

On June 8, 2005, we increased our ownership in the Tors fields (Garrow and Kilmar) in the Southern Gas Basin of the U.K. North Sea to 100% by acquiring the remaining 25% interest pursuant to an agreement with our partner. The Secretary of State for Trade and Industry gave approval for ATP Oil & Gas (UK) Limited to

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ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

own a 100% interest in the Tors fields and to act as the sole development and production operator. Subsequently, in December 2005, ATP Oil & Gas (UK) Limited sold 15% of the ATP 100% working interest in the Tors fields.

On December 19, 2005 ATP Oil & Gas Corporation announced that it had increased its ownership to 100% in the Venture field (Block 49/12a North) in the Southern Gas Basin of the U.K. North Sea. ATP Oil & Gas (UK) Limited, a wholly-owned subsidiary, acquiring the remaining 50% ownership interest pursuant to a Sale and Purchase Agreement with our partner. This 100% ownership will allow ATP to proceed with the field development plan approval process.

ATP Oil & Gas (UK) Limited recorded net acquisition costs of $7.0 million in 2005 related to these acquisitions.

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

Note 6 — Debt and Leases

Long-term debt

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

	December 31,
	2005			2004
Term loan, net of unamortized discount of $6,386 and $8,129	$	340,989		$	210,309
Less current maturities		(3,500	)		(2,200	)
Total long-term debt	$	337,489		$	208,109

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

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

On September 24, 2004, our lender consented to our repurchase of 1,926,837 of the 2,452,336 then outstanding second lien facility warrants for a price not to exceed $11,561,022. The warrants were repurchased on September 24, 2004 for $6.00 per warrant which, in management’s estimation, represented the then current fair value of the unregistered warrants. The $11.6 million partial repurchase was recorded as a decrease to additional paid in capital while the debt discount will continue to be amortized over the life of the loan.

On April 14, 2005, we increased our aggregate borrowings under the Term Loans by $132.1 million (from the balance outstanding as of March 31, 2005) to an aggregate outstanding principal amount of $350.0 million.

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ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

From this increase in borrowings, we received net proceeds of $117.8 million after deducting $3.6 million for accrued and unpaid interest on the Term Loans up to the Amendment Date and $10.7 million for fees and expenses.

The terms of the Term Loan, as amended April 14, 2005, require us to maintain certain covenants. Capitalized terms are defined in the credit agreement for the Term Loan. The covenants include:

• Current Ratio of 1.0/1.0;

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

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

• Pre-tax PV-10 of our Total Proved Developed Producing Oil and Gas Reserves to Net Debt of at least 0.5/1.0 at June 30 and December 31 of any fiscal year;

• Pre-tax PV-10 of our Total Proved Oil and Gas Reserves to Net Debt of at least 2.5/1.0 at June 30 and December 31 of any fiscal year;

• the requirement to maintain Commodity Hedging Agreements on no less than 40% nor more than 80% of the next twelve months of forecasted production attributable to our proved producing reserves;

• the requirement to maintain a Maximum Leverage Ratio of no more than 3.0/1.0 at the end of any fiscal quarter;

• the requirement to maintain a Debt to Reserve Amount of no greater than $2.50 through maturity; provided, however, that if such amount is exceeded at the end of the fiscal year ending on December 31, 2005, the covenant shall be retested at June 30, 2006, and

• limit Permitted Business Investments, as defined, to $75.0 million during any fiscal year.

As of December 31, 2005, we were in compliance with all of the financial covenants of our Term Loan. Significant adverse changes in our expected production levels, commodity prices and reserves or material delays or cost overruns could have a material adverse affect on our financial condition and results of operations and result in our non-compliance with these covenants. An event of non-compliance with any of the required covenants could result in a material mandatory repayment under the Term Loan.

Capital Lease

ATP acquired the Rowan Midland as described above for the net purchase price of $50 million, paying $10.0 million at closing on October 19, 2005, and the balance over the succeeding 15 month period (the “Interim Period”) in payments of $1,050,000 per month. The final payment is due to Rowan on January 31, 2007. At any time prior to January 31, 2007, the Company has the right, without penalty, to pay the remaining balance of the net purchase price. During the Interim Period, the Vessel is chartered to the Company for use in its production operations in the Gulf of Mexico. At its inception, the company recorded this transaction as a capital lease and recorded an oil and gas asset and corresponding capital lease obligation in the amount of $44.8 million. Future minimum lease payments, as well as the present value of the net minimum lease payments as of December 31, 2005 are as follows (in thousands):

Year Ending December 31:
2006	$	12,600
2007		34,724
Thereafter		—
Future minimum lease payments		47,324
Less amount representing interest		(4,208	)
Present value of future minimum lease payments	$	43,116

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ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Operating Leases

We have commitments under an operating lease agreement for office space and various leases for office equipment. Total rent expense for the years ended December 31, 2005, 2004 and 2003 was approximately $0.6 million, $0.7 million and $0.6 million respectively. At December 31, 2005, the future minimum rental payments due under operating leases are as follows (in thousands):

Year Ending December 31:
2006	$	755
2007		749
2008		615
2009		396
2010		240
Thereafter		19
Total	$	2,774

Note 7 — Equity

Preferred Stock

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

The Subscription Agreement for the Preferred Stock provides for: (1) an initial liquidation preference of $1,000.00 per share; (2) cumulative quarterly dividends at an initial rate of 13.5%, subject to escalation in the applicable dividend rate under certain conditions; (3) no voting rights; (4) special provisions in the event of a fundamental change in the Company or the satisfaction of the Company’s currently outstanding debt; (5) limitations on incurrence of additional debt; and (6) restrictions on transfer or sale of the Preferred Stock.

The Company has the right to redeem the Preferred Stock at its option at any time after a fundamental change or the later of February 3, 2006 or the specified debt satisfaction date at a premium that declines until February 3, 2009, at which time the preferred stock may be redeemed at 100% of the liquidation preference plus accrued and unpaid dividends.

In the event of a fundamental change in the Company or the repayment of the currently outstanding debt, the Company must notify the preferred stockholders whether it will offer to redeem the preferred stock. If the Company chooses not to offer to redeem the preferred stock, then it will be deemed a fundamental change offer default or a debt satisfaction offer default, as the case may be, and the applicable dividend rate will escalate by 5% per quarter, to a maximum of 25%. Such escalation will continue until either of such defaults is cured, unless the Company has previously exercised its optional redemption right with respect to all of the shares of Series A preferred stock then outstanding. The Company is under no obligation to offer to redeem the preferred stock under any circumstances.

Through December 31, 2005, non-cash preferred dividends aggregating $9.9 million were accrued. Such dividends may be paid in cash under the Preferred Stock Subscription Agreement upon the earlier to occur of full repayment of our existing Term Loan or April 15, 2011.

On March 8, 2006, we announced that we plan to raise $100 million or more through a private placement of non-convertible, perpetual preferred stock (“Series B Preferred Stock”). The Series B Preferred Stock will not be registered under the Securities Act of 1933, and may not be offered or sold in the United States absent registration or an applicable exemption from registration requirements. The Series B Preferred Stock will be offered in a private placement in the United States pursuant to applicable exemptions under the Securities Act of 1933. The terms and conditions of the Subscription Agreement for the Series B Preferred Stock will be

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

identical to that of the Series A Preferred Stock, except for the dividend rate, which may be different. We intend to use the net proceeds from this offering to expand our scope in certain projects, to accelerate our development activities and for general corporate purposes.

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

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

	December 31, 2005	December 31, 2004
Series A 13 1/2% cumulative perpetual preferred stock; liquidation preference of $1,056 per share; 175,000 shares issued and outstanding at December 31, 2005	184,858	—
Junior participating preferred stock pursuant to the Shareholders Rights Plan; none issued at December 31, 2005	—	—

Common Stock

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

On December 1, 2004, we completed a private placement of four million shares of common stock to accredited investors for a total consideration of $56.0 million and received net proceeds of $53.1 million after placement fees and expenses. At December 31, 2004, we had 100,000,000 shares authorized, 28,959,701 shares issued, 28,883,861 shares outstanding and 75,840 shares in treasury. On February 14, 2005, our registration statement on Form S-3 relating to the resale of these shares became effective.

Warrants

At December 31, 2005 and 2004, we had 525,499 warrants outstanding to purchase common stock at $7.25 which expire in March 2010.

Note 8 — Stock and Other Compensation Plans

In December 1998, the Board of Directors approved the 1998 Stock Option Plan (the “1998 Plan”) to provide increased incentive for its employees and directors. The 1998 Plan authorizes the granting of incentive and nonqualified stock options for up to 2,678,571 shares of common stock to eligible participants and expires five years after the closing date of our IPO. One third of the options were exercisable on April 10, 2001 with each remaining third exercisable on the first and second anniversaries of the IPO. Options granted under this plan remain exercisable by the employees owning such options, but no new options will be granted under this plan. As of February 2005, the remaining options outstanding under this plan were exercised.

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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

On December 29, 2005, we granted 265,363 shares of restricted stock with a weighted average grant date fair value of $36.79 per share to key members of management. Such restricted stock grants vest over a three-year period and are subject to forfeiture, and cannot be sold, transferred or disposed of during the restriction period. The holders of the shares have voting rights with respect to such shares. We will recognize compensation expense pro rata over the vesting period of these shares.

The following table is a summary of stock option activity:

	2005					2004					2003
	Shares			Weighted Average Exercise Price		Shares			Weighted Average Exercise Price		Shares			Weighted Average Exercise Price
Outstanding at beginning of year		1,019,739		$	9.59		1,425,244		$	8.96		1,685,147		$	8.29
Granted		440,075			21.24		24,000			13.22		50,929			4.53
Exercised		(443,453	)		10.17		(363,505	)		7.36		(198,189	)		1.79
Forfeited		—					(66,000	)		9.53		(112,643	)		9.63
Outstanding at end of year		1,016,361		$	14.38		1,019,739		$	9.59		1,425,244		$	8.96
Exercisable at end of year		496,286		$	9.18		734,864		$	9.28		805,244		$	8.05
Weighted average fair value of options granted during the year	$	6.56				$	4.84				$	2.63

The following table summarizes information about all stock options outstanding at December 31, 2005:

	Options Outstanding				Options Exercisable
Range of Exercise Prices	Number Outstanding	Weighted Average Remaining Contractual Life	Weighted Average Exercise Price		Number Exercisable	Weighted Average Exercise Price
$ 1.40 - $ 3.85	150,575	0.7 Years	$	3.62	139,013	$	3.63
$ 5.73 - $ 6.40	28,750	3.0 Years		6.28	11,875		6.26
$11.24 - $12.17	380,711	1.4 Years		11.35	330,148		11.36
$14.00 - $18.54	25,000	2.1 Years		16.36	15,250		14.97
$20.49 - $23.40	413,475	4.4 Years		20.67	—		—
$31.67 - $37.01	17,850	4.9 Years		34.68	—		—
$ 1.40 - $37.01	1,016,361	2.6 Years	$	14.38	496,286	$	9.18

We have elected to follow APB 25 and related interpretations in accounting for our stock option plans. Accordingly, no compensation expense, except as specifically described below, has been recognized for employee stock option plans. The pro forma effect on net income and earnings per share in 2005, 2004 and 2003, had we applied the fair-value-recognition provisions of SFAS 123, are shown in Note 2.

The fair values of options granted during the years 2005, 2004 and 2003 were estimated at the date of grant using a Black-Scholes option-pricing model with the following weighted average assumptions for grants in 2005, 2004 and 2003: stock price volatility of 48.9% 57.1% and 83.9%, respectively; risk free interest rate of 3.7%, 2.6% and 1.9%, respectively; zero dividend yield; and an expected life 2.5 years.

F-22

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 $190,000, $157,000 and $106,000, for the years ended December 31, 2005, 2004 and 2003, 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, 2005, 2004 and 2003, we contributed approximately $22,800, $20,200 and $21,300, respectively.

Note 9 — Earnings Per Share

Basic earnings per share is computed by dividing net income or loss by the weighted average number of shares of common stock (other than unvested restricted stock) outstanding during the period. Diluted earnings per share is determined on the assumption that outstanding stock options and warrants have been converted using the average price for the period. For purposes of computing earnings per share in a loss year, potential common shares are excluded from the computation of weighted average common shares outstanding if their effect is antidilutive. In the table below, potential common stock equivalents of 1,086,340 (including 263,818 unvested restricted shares) and 158,411 have been excluded from the calculations for 2005 and 2003, respectively, because their effect would be antidilutive.

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

	Year Ended December 31,
	2005			2004		2003
Income
Income (loss) before cumulative effect of change in accounting principle	$	(2,716	)	$	1,356	$	(51,463	)
Less preferred dividends		(9,858	)		—
Income (loss) available to common shareholders		(12,574	)		1,356		(51,463	)
Cumulative effect of change in accounting principle, net of tax		—					662
Net income (loss) available to common shareholders	$	(12,574	)	$	1,356	$	(50,801	)
Shares outstanding
Weighted average shares outstanding - basic		29,080			24,944		22,975
Effect of potentially dilutive securities - stock options and warrants		—			327		—
Unvested restricted stock		—			—		—
Weighted average shares outstanding - diluted		29,080			25,271		22,975
Basic and diluted income (loss) available to common shareholders per share:
Income (loss) before cumulative effect of change in accounting principle	$	(0.43	)	$	0.05	$	(2.24	)
Cumulative effect of change in accounting principle		—			—		0.03
Net income (loss) available to common shareholders		(0.43	)		0.05		(2.21	)

Note 10 — Income Taxes

The (expense) benefit for income taxes before cumulative effect of change in accounting principle consisted of the following (in thousands):

	Years Ended December 31,
	2005			2004			2003
Current:
Federal	$	(77	)	$	(29	)	$	—
Foreign		(4,025	)		(29	)		—
		(4,102	)		(58	)		—
Deferred:
Federal		(517	)		(4,561	)		9,594
Foreign		224			1,568			2,828
		(293	)		(2,993	)		12,422
Valuation allowance		4,242			2,993			(33,646	)
(Expense) benefit for income taxes before cumulative effect of change in accounting principle	$	(153	)	$	(58	)	$	(21,224	)

F-23

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The income (loss) before income taxes and the cumulative effect of change in accounting principle consisted of the following (in thousands):

	Years Ended December 31,
	2005			2004			2003
Domestic	$	(9,760	)	$	6,027		$	(26,320	)
Foreign		7,196			(4,613	)		(3,919	)
	$	(2,564	)	$	1,414		$	(30,239	)

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

	Years Ended December 31,
	2005		2004		2003
Statutory federal income tax rate	(35.00	)%	35.00	%	(35.00	)%
Nondeductible and other	56.95		(3.45	)	0.02
Foreign operations	149.61		12.92		(6.08	)
Valuation allowance	(165.61	)	(40.37	)	111.27
	5.95	%	4.10	%	70.21	%

Significant components of our deferred tax assets (liabilities) as of December 31, 2005 and 2004 are as follows (in thousands):

	December 31,
	2005			2004
Deferred tax assets:
Net operating loss carry forwards	$	46,285		$	36,633
AMT credit		106			29
Stock based compensation expense		440			661
Foreign operations		48,803			16,372
Revenue recognition contingency		4,025			—
Other		1,541			732
Total gross deferred tax assets		101,200			54,427
Less valuation allowance		(30,262	)		(30,958	)
Net deferred tax asset		70,938			23,469
Deferred tax liabilities:
Fixed asset basis differences		(16,916	)		(10,068	)
Asset retirement obligations		(1,944	)		(1,505	)
Foreign operations		(48,053	)		(11,896	)
Total gross deferred tax liabilities		(66,913	)		(23,469	)
Net deferred tax asset	$	4,025		$	—

Upon adoption of SFAS 143 on January 1, 2003, we recorded a cumulative effect of change in accounting principle of $0.7 million, after taxes of $0.3 million.

We compute income taxes in accordance with SFAS No. 109, “Accounting for Income Taxes” (“SFAS 109”). The standard requires 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. SFAS 109 also requires the recording of a valuation allowance if it is more likely than not that some portion or all of a deferred tax asset will not be realized.

F-24

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

In 2003, we recorded an income tax expense of $21.2 million primarily due to us recording a valuation allowance of $33.6 million against our deferred tax asset as required by SFAS 109. SFAS 109 provides for the weighing of positive and negative evidence in determining whether a deferred tax asset is recoverable. While we recorded net income in 2004, we have incurred net operating losses in 2003 and prior consecutive years. Relevant accounting guidance suggests that cumulative losses in recent years constitute significant negative evidence, and that future expectations about income are overshadowed by such history of losses. Delays in bringing properties on to production and development cost overruns in 2003 were also significant factors considered in evaluating our deferred tax asset valuation allowance. Although we achieved profitable operations in 2004; the income generated during the year was not sufficient to overcome the negative evidence noted in the prior years.

Our valuation allowance decreased during 2004 by $2.7 million. This change was a result of an increase in deferred tax assets related to foreign operations of $1.6 million and a decrease in deferred tax assets related to domestic operations of $2.2 million. The change in the valuation allowance attributable to taxes recorded directly to shareholder’s equity was an increase of $0.3 million. Additionally, the gross deferred tax asset and valuation allowances have been changed by $2.4 million to reflect certain adjustments including those necessary to agree to tax returns as filed.

During 2005, our valuation allowance decreased by $0.7 million. This change was a result of a decrease in deferred tax assets related to foreign operations of $3.7 million and a decrease in deferred tax assets related to domestic operations of $0.5 million. The change in the valuation allowance attributable to taxes recorded directly to shareholder’s equity was an increase of $3.5 million.

In February 2003, we acquired a 50% working interest in a block located in the Dutch Sector - North Sea. The remaining 50% interest is owned by a Dutch company who participates on behalf of the Dutch state. In April 2003, we received €7.4 million from the partner related to development costs on this block. We agreed to develop the property within 60 months from receipt of the funds or return the funds with interest if commercial production is not achieved at the expiration of such time. At December 31, 2005 and 2004, the U.S recorded balance is reflected as a long-term liability of $8.8 million and $10.2 million, respectively, in the financial statements. The property was developed during 2005 and commenced production in February 2006. We expect to reclassify this liability as a reduction to oil and gas properties in the first quarter of 2006 since our obligation under the agreement has now been fulfilled.

At the time of receipt, we determined the payment was not taxable at that time due to the obligation for substantial future performance. During a recent tax audit of our Dutch subsidiary, the tax authorities have concluded that receipt of the payment was a taxable event at the time of receipt and taxes and interest are currently due on this payment in the amount of approximately €3.4 million ($4.0 million). Accordingly, we have provided for this contingency and recorded a current liability in the amount of the taxes and interest. We recorded a deferred tax asset for this contingency, however we have not recorded a valuation allowance against this deferred tax asset as it resulted form a timing difference on the revenue recognition of the receipt of the payment. We do not agree with the position that has been asserted and, if necessary, we will defend our position vigorously.

At December 31, 2005, 2004 and 2003, we had net operating loss carry forwards (“NOLs”) for federal income tax purposes of approximately $132.2 million, $104.7 million, and $87.3 million respectively, which are available to offset future federal taxable income through 2025.

Note 11 — Commitments and Contingencies

Contingencies

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

F-25

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

downtime in excess of ninety days after the event. The company is assessing the insured damages and any expected recoveries under the loss of production policy. We have recorded a receivable for the expected recovery of repair costs incurred related to these storms through December 31, 2005 in the amount of $13.5 million. Additionally, we expect to incur insured repair and recovery costs in 2006 related to these storms of less than $4.0 million. We have not yet determined the amount of recovery related to the loss of production policy and accordingly have not included any receivable in the financial statements for any potential recovery under the loss of production policy.

In December 2004, our Board of Directors approved and we announced ambitious Company targets coupled with a unique incentive program applicable to our employees. If the Company targets under the ATP Employee Volvo Challenge Plan (the “Plan”) are met, we will award each employee other than our President, a 2006 Volvo S60. Following the end of each fiscal quarter, we evaluate our performance with respect to the stated targets and accrue the earned future cost of any expected benefits pursuant to the Plan.

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

During 2005, we purchased additional interest in the Tors property in the U.K. sector of the North Sea, and agreed to pay the seller contingent consideration of £2 million 180 days after first production, interest on such amount if the payment date meets certain criteria, a second contingent payment of £1 million after a cumulative 40 Bcf of production is achieved from the property, and a third contingent payment of £1 million after a cumulative 80 Bcf of production.

Litigation

During 2002 and 2003, ATP was in a dispute over a contract for the sale of an oil and gas property. The dispute was subsequently resolved for $8.2 million. We recorded a charge to income in the fourth quarter of 2003 and paid the amount in the first quarter of 2004. The Court dismissed the lawsuit on April 16, 2004.

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

Note 12 — Derivative Instruments and Price Risk Management Activities

Derivative financial instruments, utilized to manage or reduce commodity price risk related to our production are accounted for under the provisions of SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (“SFAS 133”) and related interpretations. Under this standard, all derivatives are carried on the balance sheet at fair value. If the derivative is designated as a fair value hedge, the changes in the fair value of the derivative and of the hedged item attributable to the hedged risk are recognized in earnings. If the derivative is designated as a cash flow hedge, the effective portions of changes in the fair value of the derivative are recorded in other comprehensive income and are recognized in the consolidated statement of operations when the hedged item affects earnings. Ineffective portions of changes in the fair value of cash flow hedges are recognized in current earnings. Derivative contracts that do not qualify for hedge accounting are recorded at fair value on our consolidated balance sheet and the associated unrealized gains and losses are recorded as a component of revenues in the current period.

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

At December 31, 2005 and 2004, Accumulated Other Comprehensive Income included $1.3 million and $0.5 million of unrealized gains on our cash flow hedges, respectively. Gains and losses are reclassified from Accumulated Other Comprehensive Income to the consolidated statement of operations as a component of oil and gas revenues in the period the hedged production occurs. If any ineffectiveness occurs, amounts are

F-26

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

recorded directly to the consolidated statement of operations as a component of oil and gas revenues. All of this deferred gain will be reversed during the period in which the forecasted transactions actually occur. At December 31, 2003, we had no derivatives in place that were designated as cash flow hedges.

At December 31, 2005, we had three natural gas derivatives that qualified as cash flow hedges with respect to our future natural gas production as follows:

Area	Period	Type	Volumes	Average Price	Floor Price	Net Fair Value Asset (Liability)
			(MMBtu)	($ per MMBtu)		($ in thousands)
North Sea	2006	Swap	540,000	11.03	—	5,956

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

At December 31, 2005, we had fixed-price contracts in place for the following oil and gas volumes:

Period	Volumes	Average Fixed Price (1)
Natural gas (MMBtu):
2006	5,342,000	8.35
Oil (Bbl):
2006	300,500	47.96

(1) Includes the effect of basis differentials.

Note 13 — ATP Energy Gas Purchase Transaction

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

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

ATP Energy received $6.0 million in connection with these transactions, of which $2.0 million was recorded as deferred revenue and $4.0 million was recorded as deferred obligations. The deferred revenue amount of $2.0 million was a non-refundable fee received by ATP Energy and was recognized into income as earned over the life of the contract. At December 31, 2004, the deferred revenue amount was $0.7 million. The deferred obligation amount of $4.0 million represented the difference between the premium we agreed to pay for natural gas under the American Citigas contract and the obligation of American Citigas to partially

F-27

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

reimburse us for such premium. The transaction was structured with American Citigas such that there was no financial impact to ATP Energy associated with the premium paid and reimbursement received other than the $2.0 million realized by ATP Energy. ATP Energy entered into the transactions to earn the fee for agreeing to market the volumes of natural gas specified in the American Citigas contract.

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

Note 14 — Segment Information

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

	Gulf of Mexico			North Sea			Total
2005
Revenues	$	135,175		$	11,499		$	146,674
Depreciation, depletion and amortization		59,144			4,925			64,069
Income from operations		21,661			7,013			28,674
Additions to oil and gas properties		296,060			124,456			420,516
Total assets		610,250			213,513			823,763
2004
Revenues	$	98,236		$	17,887		$	116,123
Depreciation, depletion and amortization		41,020			14,617			55,637
Income (loss) from operations		30,875			(4,780	)		26,095
Additions to oil and gas properties		78,521			8,847			87,368
Total assets		317,043			55,104			372,147
2003
Revenues	$	70,151		$	—		$	70,151
Depreciation, depletion and amortization		29,185			193			29,378
Impairment of oil and gas properties		11,670			—			11,670
Loss from operations		(15,564	)		(3,941	)		(19,505	)
Additions to oil and gas properties		59,105			24,698			83,803
Total assets		161,041			56,644			217,685

Note 15 — Summarized Quarterly Financial Data (Unaudited)

(In Thousands, Except Per Share Amounts)

	First Quarter			Second Quarter			Third Quarter			Fourth Quarter
2005
Revenues	$	36,980		$	33,488		$	26,342		$	49,864
Costs and expenses		30,181			29,220			24,915			33,684
Income from operations		6,799			4,268			1,427			16,180
Net income (loss) available to common shareholders (1)		1,000			(3,322	)		(10,577	)		325
Net income (loss) per common share:
Basic and diluted (2)	$	0.03		$	(0.11	)	$	(0.36	)	$	0.01
2004
Revenues	$	24,011		$	32,879		$	26,306		$	32,927
Costs and expenses		19,353			20,231			19,689			30,755
Income from operations		4,658			12,648			6,617			2,172
Net income (loss) available to common shareholders		(2,393	)		6,926			597			(3,774	)
Net income (loss) per common share:
Basic and diluted (2)	$	(0.10	)	$	0.28		$	0.02		$	(0.14	)

(1) The Company recognized $3.8 million of dividends in-kind related to its Series A 13.5% cumulative perpetual preferred stock in the third quarter of 2005 and $6.1 million in the fourth quarter of 2005.

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

F-28

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

SUPPLEMENTAL INFORMATION 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 years ended December 31, 2005, 2004 and 2003 (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
2004
Property acquisition costs:
Unproved	$	1,192		$	—	$	1,192
Development costs		65,667			8,847		74,514
Exploratory costs		11,662			—		11,662
Oil and gas expenditures		78,521			8,847		87,368
Asset retirement costs		2,935			—		2,935
Gain on abandonment		(251	)		—		(251	)
	$	81,205		$	8,847	$	90,052
2003
Property acquisition costs:
Proved	$	1,163		$	—	$	1,163
Unproved		769			—		769
Development costs		57,173			24,698		81,871
Oil and gas expenditures		59,105			24,698		83,803
Asset retirement costs (1)		14,182			2,358		16,540
Loss on abandonment		4,973			—		4,973
	$	78,260		$	27,056	$	105,316

(1) This amount includes $15.4 million of asset retirement costs as a result of implementation of SFAS 143 on January 1, 2003.

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.

For 2005, most of our Gulf of Mexico reserves and all of our Netherlands reserves quantities were prepared by independent petroleum engineers Ryder Scott Company, L.P. The remainder of our 2005 Gulf of Mexico reserves related to newly acquired properties and were prepared by DeGolyer and MacNaughton and Collarini Associates. In all other years, Gulf of Mexico and the Dutch Sector – North Sea reserves quantities as well as certain information regarding future production and discounted cash flows were prepared by independent petroleum engineers Ryder Scott Company, L.P. Reserves quantities as well as certain information regarding future production and discounted cash flows for the U.K. Sector – North Sea were prepared by independent petroleum consultants RPS Energy (formerly RPS Troy-Ikoda) for all years presented.

F-29

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES

The following table sets forth our net proved oil and gas reserves at December 31, 2002, 2003, 2004 and 2005 and the changes in net proved oil and gas reserves for the years ended December 31, 2003, 2004 and 2005:

	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, 2002	102,438		93,100		195,538		5,740		—	5,740
Revisions of previous estimates	(6,311	)	1,640		(4,671	)	(106	)	—	(106	)
Purchase of minerals in place	51,527		6,292		57,819		7,609		2	7,611
Sales of minerals in place	(6,779	)	—		(6,779	)	(258	)	—	(258	)
Production	(10,842	)	—		(10,842	)	(1,042	)	—	(1,042	)
Proved Reserves at December 31, 2003	130,033		101,032		231,065		11,943		2	11,945
Revisions of previous estimates	83		(2,062	)	(1,979	)	901		—	901
Extensions and discoveries	2,002		—		2,002		7		—	7
Sales of minerals in place	(8,044	)	—		(8,044	)	(419	)	—	(419	)
Production	(13,347	)	(4,468	)	(17,815	)	(766	)	—	(766	)
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

	Natural Gas (MMcf)			Oil and Condensate (MBbls)
	Gulf of Mexico	North Sea	Total	Gulf of Mexico	North Sea	Total
Proved Developed Reserves at
December 31, 2002	34,068	—	34,068	2,318	—	2,318
December 31, 2003	30,062	15,740	45,802	1,697	—	1,697
December 31, 2004	37,876	9,210	47,086	2,222	—	2,222
December 31, 2005	78,833	13,979	92,812	5,924	2	5,926

Standardized Measure

The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves as of year-end 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 per annum		(274,793	)		(453,374	)		(728,167	)
Standardized measure of discounted future net cash flows	$	1,100,854		$	764,726		$	1,865,580

F-30

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES

	Gulf of Mexico			North Sea			Total
2004
Future cash inflows	$	1,142,853		$	500,755		$	1,643,608
Future operating expenses		(161,795	)		(91,477	)		(253,272	)
Future development costs		(272,317	)		(142,340	)		(414,657	)
Future net cash flows		708,741			266,938			975,679
Future income taxes		(200,084	)		(81,755	)		(281,839	)
Future net cash flows, after income taxes		508,657			185,183			693,840
10% annual discount per annum		(126,838	)		(46,719	)		(173,557	)
Standardized measure of discounted future net cash flows	$	381,819		$	138,464		$	520,283
	Gulf of Mexico			North Sea			Total
2003
Future cash inflows	$	1,183,743		$	497,739		$	1,681,482
Future operating expenses		(140,113	)		(85,041	)		(225,154	)
Future development costs		(267,150	)		(132,973	)		(400,123	)
Future net cash flows		776,480			279,725			1,056,205
Future income taxes		(227,880	)		(95,066	)		(322,946	)
Future net cash flows, after income taxes		548,600			184,659			733,259
10% annual discount per annum		(139,210	)		(46,997	)		(186,207	)
Standardized measure of discounted future net cash flows	$	409,390		$	137,662		$	547,052

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 PV10 calculation were public market prices on December 31 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 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 cash flows is the future net cash flows less the computed discount.

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

	Natural Gas			Oil and Condensate
	Gulf of Mexico	U.K. Sector North Sea	Dutch Sector North Sea	Gulf of Mexico	U.K. Sector North Sea	Dutch Sector North Sea
December 31, 2003	5.965	5.160	4.160	32.55	—	30.00
December 31, 2004	6.180	5.509	4.950	43.46	—	40.02
December 31, 2005	10.080	12.613	6.120	61.11	59.40	58.62

F-31

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES

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			76,872			76,976
Changes in estimated future development costs		53,273			(18,488	)		34,785
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		50,822			(59,102	)		(8,280	)
		719,035			626,262			1,345,297
End of year	$	1,100,854		$	764,726		$	1,865,580
2004
Beginning of year	$	409,390		$	137,662		$	547,052
Sales of oil and gas, net of production costs		(83,636	)		(14,156	)		(97,792	)
Net changes in income taxes		19,431			2,705			22,136
Net changes in price and production costs		63,623			13,937			77,560
Revisions of quantity estimates		22,068			(6,366	)		15,702
Extensions and discoveries		10,503			—			10,503
Accretion of discount		57,472			19,930			77,402
Development costs incurred		37,513			1,779			39,292
Changes in estimated future development costs		(43,302	)		(8,242	)		(51,544	)
Sales of minerals-in-place		(34,328	)		—			(34,328	)
Changes in production rates, timing and other		(76,915	)		(8,785	)		(85,700	)
		(27,571	)		802			(26,769	)
End of year	$	381,819		$	138,464		$	520,283
2003
Beginning of year	$	247,704		$	11,189		$	258,893
Sales of oil and gas, net of production costs		(64,664	)		—			(64,664	)
Net changes in income taxes		(69,396	)		(61,129	)		(130,525	)
Net changes in price and production costs		112,261			168,317			280,578
Revisions of quantity estimates		(27,612	)		4,426			(23,186	)
Accretion of discount		34,364			1,170			35,534
Development costs incurred		42,750			5,365			48,115
Changes in estimated future development costs		(18,885	)		(9,940	)		(28,825	)
Purchases of minerals-in-place		212,623			2,007			214,630
Sales of minerals-in-place		(17,966	)		—			(17,966	)
Changes in production rates, timing and other		(41,789	)		16,257			(25,532	)
		161,686			126,473			288,159
End of year	$	409,390		$	137,662		$	547,052

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.

F-32

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES

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
2004
Oil and gas properties:
Unproved	$	8,063		$	2,453		$	10,516
Proved		381,004			58,883			439,887
Accumulated depletion, impairment and amortization		(221,996	)		(15,201	)		(237,197	)
	$	167,071		$	46,135		$	213,206

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).

	Gulf of Mexico			North Sea			Total
2005
Revenues from oil and gas producing activities	$	135,175		$	11,499		$	146,674
Production costs and other		(27,698	)		(2,138	)		(29,836	)
Depreciation, depletion, amortization and accretion		(59,145	)		(4,924	)		(64,069	)
Income tax (expense) benefit		(16,916	)		(1,287	)		(18,203	)
Results of operations from producing activities (excluding corporate overhead and interest costs	$	31,416		$	3,150		$	34,566
2004
Revenues from oil and gas producing activities	$	99,334		$	17,887		$	117,221
Production costs and other		(16,239	)		(4,289	)		(20,528	)
Depreciation, depletion, amortization and accretion		(42,592	)		(15,114	)		(57,706	)
Income tax (expense) benefit		(14,176	)		440			(13,736	)
Results of operations from producing activities (excluding corporate overhead and interest costs	$	26,327		$	(1,076	)	$	25,251
2003
Revenues from oil and gas producing activities	$	81,800		$	—		$	81,800
Production costs and other		(17,511	)		(1,020	)		(18,531	)
Depreciation, depletion, amortization and accretion		(31,553	)		(577	)		(32,130	)
Impairment of oil and gas properties		(11,670	)		—			(11,670	)
Income tax (expense) benefit		(7,373	)		463			(6,910	)
Results of operations from producing activities (excluding corporate overhead and interest costs	$	13,693		$	(1,134	)	$	12,559

F-33

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS

FOR EACH OF THE THREE YEARS ENDED DECEMBER 31, 2005

(In Thousands)

Description	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
2004
Allowance for doubtful accounts	$	1,266	$	233		$	—		$	—	$	1,499
Valuation allowance on deferred tax assets		33,646		(2,993	)		305			—		30,958
2003
Allowance for doubtful accounts	$	1,266	$	—		$	—		$	—	$	1,266
Valuation allowance on deferred tax assets		—		33,646			—			—		33,646

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 and Subsidiaries of our report dated March 14, 2006, relating to the financial statements and financial statement schedule of ATP Oil & Gas Corporation and Subsidiaries and management’s report on the effectiveness of internal control over financial reporting, appearing in this Annual Report on Form 10-K of ATP Oil and Gas Corporation and Subsidiaries for the year ended December 31, 2005 (which report expresses an unqualified opinion and includes an explanatory paragraph relating to a change in method of accounting for asset retirement obligations in 2003).

/s/ Deloitte & Touche LLP

     Deloitte & Touche LLP

Houston, Texas

March 15, 2006

EX-23.2

Exhibit 23.2

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors

ATP Oil & Gas Corporation:

We consent to the incorporation by reference in the Registration Statement on Form S-8 (No. 333-60762) and Registration Statements on Form S-3 (No. 333-105699 and No. 333-121662) of ATP Oil & Gas Corporation and subsidiaries of our report dated March 29, 2004, with respect to the consolidated statements of operations, shareholders’ equity, comprehensive loss and cash flows for the year ended December 31, 2003, which report appears in ATP Oil & Gas Corporation and subsidiaries’ Annual Report on Form 10-K as of and for the year ended December 31, 2005.

Our report on the consolidated financial statements refers to a change in the method of accounting for asset retirement obligations, effective January 1, 2003.

/s/ KPMG LLP

Houston, Texas

March 14, 2006

EX-23.3

Exhibit 23.3

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS

We hereby consent to the use of the name Ryder Scott Company, L.P. and of references to Ryder Scott Company, L.P. and to the inclusion of and references to our reports, or information contained therein, dated 20^th January 2006, prepared for ATP Oil & Gas Corporation annual report on Form 10-K for the year ended 31^st December 2005, and the incorporation by reference to the report prepared by Ryder Scott Company, L.P. into ATP Oil & Gas Corporation’s previously filed Registration Forms S-3 (Nos. 333-105699 and 333-121662) and on Form S-8 (No. 333-60762).

/s/ Ryder Scott Company, L.P.

Ryder Scott Company, L.P.

March 14, 2006

EX-23.4

Exhibit 23.4

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS

We hereby consent to the use of the name RPS Energy and of references to RPS Energy and to the inclusion of and references to our report, or information contained therein, dated 13^th February 2006, prepared for ATP Oil & Gas (UK) Limited in the ATP Oil & Gas Corporation annual report on Form 10-K for the year ended 31^st December 2005, and the incorporation by reference to the report prepared by RPS Energy into ATP Oil & Gas Corporation’s previously filed Registration Forms S-3 (Nos. 333-105699 and 333-121662) and on Form S-8 (No. 333-60762).

/s/ F.O. Boundy

RPS Energy

10 March 2006

EX-23.5

Exhibit 23.5

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS

We hereby consent to the use of the name Collarini Associates and of references to Collarini Associates and to the inclusion of and references to our report, or information contained therein, dated 13^th January 2006, prepared for ATP Oil & Gas Corporation annual report on Form 10-K for the year ended 31^st December 2005, and the incorporation by reference to the report prepared by Collarini Associates into ATP Oil & Gas Corporation’s previously filed Registration Forms S-3 (Nos. 333-105699 and 333-121662) and on Form S-8 (No. 333-60762).

Collarini Associates

/s/ Mitch Reece, V.P.

13th day of March 2006

EX-23.6

Exhibit 23.6

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS

We hereby consent to the reference to DeGolyer and MacNaughton, to the incorporation of the information contained in our “Appraisal Report as of December 31, 2005 on Certain Properties owned by ATP Oil & Gas Corporation” (our Report), and to references to our Report in the Annual Report on Form 10-K of ATP Oil & Gas Corporation for the year ended December 31, 2005 In addition, we hereby consent to the incorporation by reference of such reference to DeGolyer and MacNaughton and to our Report in ATP Oil & Gas Corporation’s previously filed Registration Statements on Form S-3 (Nos. 333-105699 and 333-121662) and on Form S-8 (No. 333-60762).

Very truly yours,

/s/ DeGolyer and McNaughton

DeGolyer and MacNaughton

March 14, 2006

EX-31.1

EXHIBIT 31.1

ATP OIL & GAS CORPORATION

Section 302 Certification of Principal Executive Officer

I, T. Paul Bulmahn, Chief Executive Officer and President (Principal Executive Officer) certify that:

1. I have reviewed this Form 10-K for the annual period ended December 31, 2005 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 14, 2006	/s/ T. Paul Bulmahn
		CEO & President

EX-31.2

EXHIBIT 31.2

ATP OIL & GAS CORPORATION

Section 302 Certification of Principal Financial Officer

I, Albert L. Reese, Jr., Chief Financial Officer (Principal Financial Officer) certify that:

1. I have reviewed this Form 10-K for the annual period ended December 31, 2005 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 14, 2006	/s/ Albert L. Reese
		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

I, T. Paul Bulmahn, Chairman and Chief Executive Officer of ATP Oil & Gas Corporation (the “Company”), do hereby certify that the Annual Report on Form 10-K (the “Report”) for the year ended December 31, 2005, filed with the Securities Exchange Commission on the date hereof:

1) 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 represents, in all material respects, the financial condition and the results of operations of the Company.

Date:	March 14, 2006	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

I, Albert L. Reese, Jr., Chief Financial Officer of ATP Oil & Gas Corporation (the “Company”), do hereby certify that the Annual Report on Form 10-K (the “Report”) for the year ended December 31, 2005, filed with the Securities Exchange Commission on the date hereof:

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

4) the information contained in the Report fairly represents, in all material respects, the financial condition and the results of operations of the Company.

March 14, 2006	By:	/s/ Albert L. Reese, Jr.
		Albert L. Reese, Jr. Chief Financial Officer