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UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549



FORM 10-K



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



For the Fiscal Year Ended December 31, 2004



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 or other jurisdiction of incorporation or organization) |  | (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 whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such
reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No ̈



Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the best of Registrants knowledge, in definitive proxy or information statements incorporated by Reference in Part III of this Form 10-K or any amendment to this Form
10-K. ̈



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



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



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



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ATP OIL & GAS CORPORATION AND SUBSIDIARIES

2004 FORM 10-K ANNUAL REPORT

TABLE OF CONTENTS



|         |  |                                                                                                             |  |     
|-------- |  | ----------------------------------------------------------------------------------------------------------- |  | ----
|         |  |                                                                                                             |  | Page
|Part I   |  |                                                                                                             |  | 6   
|         |  |                                                                                                            
|Item 1.  |  | Business                                                                                                    |  | 6   
|         |  |                                                                                                            
|Item 2.  |  | Properties                                                                                                  |  | 21  
|         |  |                                                                                                            
|Item 3.  |  | Legal Proceedings                                                                                           |  | 24  
|         |  |                                                                                                            
|Item 4.  |  | Submission of Matters to a Vote of Security Holders                                                         |  | 24  
|         |  |                                                                                                            
|Part II  |  |                                                                                                             |  | 27  
|         |  |                                                                                                            
|Item 5.  |  | Market for Registrants Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities |  | 27  
|         |  |                                                                                                            
|Item 6.  |  | Selected Financial Data                                                                                     |  | 28  
|         |  |                                                                                                            
|Item 7.  |  | Managements Discussion and Analysis of Financial Condition and Results of Operations                       |  | 30  
|         |  |                                                                                                            
|Item 7a. |  | Quantitative and Qualitative Disclosures about Market Risk                                                  |  | 44  
|         |  |                                                                                                            
|Item 8.  |  | Financial Statements and Supplementary Data                                                                 |  | 44  
|         |  |                                                                                                            
|Item 9.  |  | Changes in and Disagreements with Accountants on Accounting and Financial Disclosure                        |  | 44  
|         |  |                                                                                                            
|Item 9a. |  | Controls and Procedures                                                                                     |  | 45  
|         |  |                                                                                                            
|Item 9b. |  | Other Information                                                                                           |  | 45  
|         |  |                                                                                                            
|Part III |  |                                                                                                             |  | 46  
|         |  |                                                                                                            
|Item 10. |  | Directors and Executive Officers of Registrant                                                              |  | 46  
|         |  |                                                                                                            
|Item 11. |  | Executive Compensation                                                                                      |  | 46  
|         |  |                                                                                                            
|Item 12. |  | Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters              |  | 46  
|         |  |                                                                                                            
|Item 13. |  | Certain Relationships and Related Transactions                                                              |  | 46  
|         |  |                                                                                                            
|Item 14. |  | Principal Accountant Fees and Services                                                                      |  | 46  
|         |  |                                                                                                            
|Part IV  |  |                                                                                                             |  | 47  
|         |  |                                                                                                            
|Item 15. |  | Exhibits, Financial Statement Schedules and Reports on Form 8-K                                             |  | 47  



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Cautionary Statement About
Forward-Looking Statements



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



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



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



| |  |  | 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.



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



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



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



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



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



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



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



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PART I



|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 North Sea. We primarily
focus our efforts on oil and natural gas properties where previous drilling has encountered reservoirs that appear to contain commercially productive quantities of oil and gas. Many of these properties contain proved undeveloped reserves that are
economically attractive to us but are not strategic to major or exploration-oriented independent oil and gas companies. Our management team has extensive engineering, geological, geophysical, technical and operational expertise in successfully
developing and operating properties in both our current and planned areas of operation.



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



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



Our Business Strategy



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



| |  |  | an existing infrastructure of oil and natural gas pipelines and production/processing platforms;
| | - |  | ------------------------------------------------------------------------------------------------



| |  |  | geographic proximity to developed markets for oil and natural gas;
| | - |  | ------------------------------------------------------------------



| |  |  | a number of properties that major oil companies, exploration-oriented independents and others consider non-strategic; and
| | - |  | -------------------------------------------------------------------------------------------------------------------------



| |  |  | a relatively stable history of consistently applied governmental regulations 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 found to contain proved reserves. Occasionally we will acquire properties where previous drilling has encountered reservoirs that
appear to contain commercially productive quantities of oil and gas even though the reservoirs do not meet the SEC definition of proved reserves. From the inception of operations through March 25, 2005, we have successfully brought to production 37
out of 38 projects from previously undeveloped reservoirs, a 97% success ratio.



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



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



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



Our Strengths



| |  |  | Low Acquisition Cost Structure. We believe that our focus on acquiring properties with minimal cash investment allows us to pursue the acquisition, development and production
of properties that may not be economically attractive to others.
| | - |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Technical Expertise and Significant Experience. We have assembled a technical staff with an average of over 23 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, 2004, we operated all of our properties under development, all of our subsea wells and 85% of our offshore platforms.
| | - |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Employee Ownership. Through employee ownership, we have built a staff whose business decisions are aligned with the interests of our shareholders. Our executive officers and
directors own approximately 37% 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.



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



Competition



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



Regulation



Gulf of Mexico



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



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



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



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



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



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



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



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



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



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



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



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



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



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



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



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



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



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



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



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



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



North Sea



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



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



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



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



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



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



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



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



Risk Factors



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



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



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



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



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



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



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



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



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



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



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



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



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



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



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



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



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



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



In March 2004, we entered into a new term loan, which was subsequently amended in September 2004 (the Term Loan), consisting of a $185.0
million Senior Secured First Lien Term Loan Facility and a $35.0 million Senior Secured Second Lien Term Loan Facility. The Term Loan matures in March 2009 and is secured by substantially all of our oil and gas assets in the Gulf of Mexico and the
U.K. Sector  North Sea and is guaranteed by our wholly owned subsidiaries ATP Energy and ATP Oil & Gas (U.K.) Limited. As of December 31, 2004, we had $218.4 million principal amount outstanding under the Term Loan. The Term Loan contains
customary restrictions, including covenants limiting our ability to incur additional debt, grant liens, make investments, consolidate, merge or acquire other businesses, sell assets, pay dividends and other distributions and enter into transactions
with affiliates. We also are required to maintain specified financial requirements under the terms of our Term Loan including the following, as defined in the Term Loan:



| |  |  | Current Ratio of 1.0/1.0;
| | - |  | -------------------------



| |  |  | Consolidated Net Debt to EBITDAX coverage ratio which is not greater than 3.25/1.0 through June 30, 2004 and 3.0/1.0 at each of the quarters ending thereafter;
| | - |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Consolidated EBITDAX to Interest Expense which is not less than 2.5/1.0 for any four consecutive fiscal quarters commencing with the quarter ended June 30, 2004 and at each of the
quarters ending thereafter;
| | - |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | PV10 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;
| | - |  | ------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | PV10 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;
| | - |  | ----------------------------------------------------------------------------------------------------------------------------



| |  |  | Net Debt to Proved Developed Oil and Gas Reserves of less than $2.50/Mcfe at December 31, 2004 and at each of the years ending thereafter, and
| | - |  | ----------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | the requirement to maintain hedges on no less than 40% of the next twelve months of forecasted production attributable to our proved producing reserves.
| | - |  | --------------------------------------------------------------------------------------------------------------------------------------------------------



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



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



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



| |  |  | 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.



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



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



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



| |  |  | worldwide or regional demand for energy, which is affected by economic conditions;
| | - |  | ----------------------------------------------------------------------------------



| |  |  | 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.



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



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



| |  |  | production is less than expected;
| | - |  | ---------------------------------



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



We may incur substantial impairment writedowns.



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



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



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



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



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



| |  |  | 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; and
| | - |  | ------------------------------------



| |  |  | environmental hazards, such as natural gas leaks, oil spills, pipeline ruptures and discharges of toxic gases.
| | - |  | --------------------------------------------------------------------------------------------------------------



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



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



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



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



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



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



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



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



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



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Rapid growth may place significant demands on our resources.



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



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



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



20



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##### Table of Contents

Employees



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



Available Information



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



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



Gulf of Mexico



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



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



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



21



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##### Table of Contents

North Sea



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



Oil and Natural Gas Reserves



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



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



|                              |  |                 |  |             |  |        
|----------------------------- |  | --------------- |  | ----------- |  | -------
|                              |  | Proved Reserves
|                              |  | Developed       |  | Undeveloped |  | Total  
|Gulf of Mexico                |  |                 |  |             |  |        
|Natural gas (MMcf)            |  | 37,876          |  | 72,851      |  | 110,727
|Oil and condensate (MBbls)    |  | 2,222           |  | 9,444       |  | 11,666 
|Total proved reserves (MMcfe) |  | 51,208          |  | 129,515     |  | 180,723
|North Sea                     |  |                 |  |             |  |        
|Natural gas (MMcf)            |  | 9,210           |  | 85,292      |  | 94,502 
|Oil and condensate (MBbls)    |  |                |  | 2           |  | 2      
|Total proved reserves (MMcfe) |  | 9,210           |  | 85,304      |  | 94,514 
|Total                         |  |                 |  |             |  |        
|Natural gas (MMcf)            |  | 47,086          |  | 158,143     |  | 205,229
|Oil and condensate (MBbls)    |  | 2,222           |  | 9,446       |  | 11,668 
|Total proved reserves (MMcfe) |  | 60,418          |  | 214,819     |  | 275,237



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



|                                                            |  |   |          |  
|----------------------------------------------------------- |  | - | -------- | -
|Net present value of future cash flows, before income taxes |  | $ | 732,822  |  
|Future income taxes, discounted at 10%                      |  |   | (212,539 | )
|                                                            |  |   |          |  
|Standardized measure of discounted future net cash flows    |  | $ | 520,283  |  
|                                                            |  |   |          |  



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##### Table of Contents

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



Drilling Activity



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



|                         |  |                |  |           |  |      |  |      |  |      |  |     
|------------------------ |  | -------------- |  | --------- |  | ---- |  | ---- |  | ---- |  | ----
|                         |  | Gulf of Mexico |  | North Sea
|                         |  | 2004           |  | 2003      |  | 2002 |  | 2004 |  | 2003 |  | 2002
|Gross Development Wells: |  |                |  |           |  |      |  |      |  |      |  |     
|Productive               |  | 10.0           |  | 5.0       |  |     |  |     |  | 1.0  |  |    
|Nonproductive            |  | 2.0            |  |          |  |     |  |     |  |     |  |    
|                         |  |                |  |           |  |      |  |      |  |      |  |     
|Total                    |  | 12.0           |  | 5.0       |  |     |  |     |  | 1.0  |  |    
|                         |  |                |  |           |  |      |  |      |  |      |  |     
|Net Development Wells:   |  |                |  |           |  |      |  |      |  |      |  |     
|Productive               |  | 6.7            |  | 4.3       |  |     |  |     |  | 0.5  |  |    
|Nonproductive            |  | 1.5            |  |          |  |     |  |     |  |     |  |    
|                         |  |                |  |           |  |      |  |      |  |      |  |     
|Total                    |  | 8.2            |  | 4.3       |  |     |  |      |  | 0.5  |  |    
|                         |  |                |  |           |  |      |  |      |  |      |  |     
|Gross Exploratory Wells: |  |                |  |           |  |      |  |      |  |      |  |     
|Productive               |  | 3.0            |  |          |  |     |  |     |  |     |  |    
|Nonproductive            |  |               |  |          |  |     |  |     |  |     |  |    
|                         |  |                |  |           |  |      |  |      |  |      |  |     
|Total                    |  | 3.0            |  |          |  |     |  |     |  |     |  |    
|                         |  |                |  |           |  |      |  |      |  |      |  |     
|Net Exploratory Wells:   |  |                |  |           |  |      |  |      |  |      |  |     
|Productive               |  | 1.3            |  |          |  |     |  |     |  |     |  |    
|Nonproductive            |  |               |  |          |  |     |  |     |  |     |  |    
|                         |  |                |  |           |  |      |  |      |  |      |  |     
|Total                    |  | 1.3            |  |          |  |     |  |      |  |     |  |    
|                         |  |                |  |           |  |      |  |      |  |      |  |     
|Total Gross Wells        |  |                |  |           |  |      |  |      |  |      |  |     
|Productive               |  | 13.0           |  | 5.0       |  |     |  |     |  | 1.0  |  |    
|Nonproductive            |  | 2.0            |  |          |  |     |  |     |  |     |  |    
|                         |  |                |  |           |  |      |  |      |  |      |  |     
|Total                    |  | 15.0           |  | 5.0       |  |     |  |      |  | 1.0  |  |    
|                         |  |                |  |           |  |      |  |      |  |      |  |     
|Total Net Wells          |  |                |  |           |  |      |  |      |  |      |  |     
|Productive               |  | 8.0            |  | 4.3       |  |     |  |     |  | 0.5  |  |    
|Nonproductive            |  | 1.5            |  |          |  |     |  |     |  |     |  |    
|                         |  |                |  |           |  |      |  |      |  |      |  |     
|Total                    |  | 9.5            |  | 4.3       |  |     |  |      |  | 0.5  |  |    
|                         |  |                |  |           |  |      |  |      |  |      |  |     



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



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##### Table of Contents

Productive Wells



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



|      |  |               |  |          
|----- |  | ------------- |  | ---------
|      |  | Gulf ofMexico |  | North Sea
|Gross |  |               |  |          
|Gas   |  | 29.0          |  | 1.0      
|Oil   |  | 4.0           |  |         
|      |  |               |  |          
|Total |  | 33.0          |  | 1.0      
|      |  |               |  |          
|Net   |  |               |  |          
|Gas   |  | 19.8          |  | 0.5      
|Oil   |  | 2.8           |  |         
|      |  |               |  |          
|Total |  | 22.6          |  | 0.5      
|      |  |               |  |          



Acreage



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



|               |  |               |  |                |  |         |  |         |  |         |  |        
|-------------- |  | ------------- |  | -------------- |  | ------- |  | ------- |  | ------- |  | -------
|               |  | Developed (1) |  | Undeveloped(2) |  | Total  
|               |  | Gross         |  | Net            |  | Gross   |  | Net     |  | Gross   |  | Net    
|Gulf of Mexico |  | 142,394       |  | 106,131        |  | 66,543  |  | 61,451  |  | 208,937 |  | 167,582
|North Sea.     |  | 12,078        |  | 6,039          |  | 96,013  |  | 75,740  |  | 108,091 |  | 81,779 
|               |  |               |  |                |  |         |  |         |  |         |  |        
|               |  | 154,472       |  | 112,170        |  | 162,556 |  | 137,191 |  | 317,028 |  | 249,361
|               |  |               |  |                |  |         |  |         |  |         |  |        

---

|(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
|------- | -----------------



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.



|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 2004.



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##### Table of Contents

Executive Officers of the Company and Other Key Employees



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



|                     |  |     |  |                                                      
|-------------------- |  | --- |  | -----------------------------------------------------
|Name                 |  | Age |  | Position                                             
|T. Paul Bulmahn      |  | 61  |  | Chairman and President                               
|Gerald W. Schlief    |  | 57  |  | Senior Vice President                                
|Albert L. Reese, Jr. |  | 55  |  | Chief Financial Officer                              
|Leland E. Tate.      |  | 57  |  | Chief Operations Officer                             
|John E. Tschirhart.  |  | 54  |  | Senior Vice President, International, General Counsel
|Isabel M. Plume.     |  | 45  |  | Chief Communications Officer                         
|Keith R. Godwin      |  | 37  |  | Chief Accounting Officer                             



T. Paul Bulmahn
has served as our Chairman and President since he founded the company in 1991. From 1988 to 1991, Mr. Bulmahn served as President and Director of Harbert Oil & Gas Corporation. From 1984 to 1988, Mr. Bulmahn served as Vice President, General
Counsel of Plumb Oil Company. From 1978 to 1984, Mr. Bulmahn served as counsel for Tennecos interstate gas pipelines and as regulatory counsel in Washington, D.C. From 1973 to 1978, he served the Railroad Commission of Texas, the Public
Utility Commission and the Interstate Commerce Commission as an administrative law judge.



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.



25



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##### Table of Contents

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



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



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



26



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##### Table of Contents



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 28,966,358 shares of common stock and no shares of preferred stock outstanding as of March 25, 2005. There were 101 holders of record of our
common stock as of March 25, 2005. Our common stock is traded on the Nasdaq National Market under the ticker symbol ATPG.



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



|            |  |      |       |     |   |      
|----------- |  | ---- | ----- | --- | - | -----
|            |  | High |       | Low
|2004:       |  |      |       |     |   |      
|4thQuarter  |  | $    | 19.15 |     | $ | 12.11
|3rdQuarter  |  |      | 12.34 |     |   | 7.05 
|2ndQuarter  |  |      | 8.09  |     |   | 5.90 
|1st Quarter |  |      | 6.90  |     |   | 4.71 
|2003:       |  |      |       |     |   |      
|4thQuarter  |  | $    | 6.65  |     | $ | 3.92 
|3rdQuarter  |  |      | 7.05  |     |   | 4.92 
|2ndQuarter  |  |      | 7.75  |     |   | 3.01 
|1stQuarter  |  |      | 5.15  |     |   | 3.65 



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.



27



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##### Table of Contents

|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, |        
|                                                                                          |  | 2004                     |         |   | 2003 |   |         | 2002 |  |   | 2001    |   |  | 2000 |        
|Statement of Operations Data:                                                             |  |                          |         |   |      |   |         |      |  |   |         |   |  |      |         |   |  |   |         |  
|Revenues:                                                                                 |  |                          |         |   |      |   |         |      |  |   |         |   |  |      |         |   |  |   |         |  
|Oil and gas production                                                                    |  | $                        | 116,123 |   |      | $ | 70,151  |      |  | $ | 80,017  |   |  | $    | 87,873  |   |  | $ | 64,256  |  
|                                                                                          |  |                          |         |   |      |   |         |      |  |   |         |   |  |      |         |   |  |   |         |  
|Cost and operating expenses:                                                              |  |                          |         |   |      |   |         |      |  |   |         |   |  |      |         |   |  |   |         |  
|Lease operating expenses                                                                  |  |                          | 19,531  |   |      |   | 17,173  |      |  |   | 16,764  |   |  |      | 14,806  |   |  |   | 11,559  |  
|Geological and geophysical expenses                                                       |  |                          | 997     |   |      |   | 1,358   |      |  |   | 154     |   |  |      | 1,068   |   |  |   |        |  
|General and administrative                                                                |  |                          | 15,806  |   |      |   | 12,209  |      |  |   | 10,037  |   |  |      | 9,806   |   |  |   | 5,409   |  
|Credit facility costs                                                                     |  |                          | 1,850   |   |      |   | 1,990   |      |  |   | 250     |   |  |      | 175     |   |  |   |        |  
|Non-cash compensation expense                                                             |  |                          |        |   |      |   | (39     | )    |  |   | 595     |   |  |      | 3,364   |   |  |   |        |  
|Depreciation, depletion and amortization                                                  |  |                          | 55,637  |   |      |   | 29,378  |      |  |   | 43,390  |   |  |      | 53,428  |   |  |   | 40,569  |  
|Impairment of oil and gas properties                                                      |  |                          |        |   |      |   | 11,670  |      |  |   | 6,844   |   |  |      | 24,891  |   |  |   | 10,838  |  
|(Gain) loss on abandonment(1)                                                             |  |                          | (251    | ) |      |   | 4,973   |      |  |   |        |   |  |      |        |   |  |   |        |  
|Accretion expense                                                                         |  |                          | 2,069   |   |      |   | 2,752   |      |  |   |        |   |  |      |        |   |  |   |        |  
|Loss on unsuccessful property acquisition(2)                                              |  |                          |        |   |      |   | 8,192   |      |  |   |        |   |  |      | 3,147   |   |  |   |        |  
|Gain on disposition of properties                                                         |  |                          | (6,011  | ) |      |   |        |      |  |   |        |   |  |      |        |   |  |   | (33     | )
|Other                                                                                     |  |                          | 400     |   |      |   |        |      |  |   |        |   |  |      |        |   |  |   | 450     |  
|                                                                                          |  |                          |         |   |      |   |         |      |  |   |         |   |  |      |         |   |  |   |         |  
|Total operating expenses                                                                  |  |                          | 90,028  |   |      |   | 89,656  |      |  |   | 78,034  |   |  |      | 110,685 |   |  |   | 68,792  |  
|                                                                                          |  |                          |         |   |      |   |         |      |  |   |         |   |  |      |         |   |  |   |         |  
|Income (loss) from operations                                                             |  |                          | 26,095  |   |      |   | (19,505 | )    |  |   | 1,983   |   |  |      | (22,812 | ) |  |   | (4,536  | )
|Other income (expense):                                                                   |  |                          |         |   |      |   |         |      |  |   |         |   |  |      |         |   |  |   |         |  
|Interest income                                                                           |  |                          | 627     |   |      |   | 52      |      |  |   | 73      |   |  |      | 884     |   |  |   | 451     |  
|Interest expense                                                                          |  |                          | (22,262 | ) |      |   | (9,678  | )    |  |   | (10,418 | ) |  |      | (10,039 | ) |  |   | (11,907 | )
|Loss on extinguishment of debt                                                            |  |                          | (3,326  | ) |      |   | (3,352  | )    |  |   |        |   |  |      | (926    | ) |  |   |        |  
|Other                                                                                     |  |                          | 280     |   |      |   | 2,244   |      |  |   | 1,081   |   |  |      |        |   |  |   |        |  
|                                                                                          |  |                          |         |   |      |   |         |      |  |   |         |   |  |      |         |   |  |   |         |  
|Income (loss) before income taxes and cumulative effect of change in accounting principle |  |                          | 1,414   |   |      |   | (30,239 | )    |  |   | (7,281  | ) |  |      | (32,893 | ) |  |   | (15,992 | )
|Income tax (expense) benefit                                                              |  |                          | (58     | ) |      |   | (21,224 | )    |  |   | 2,581   |   |  |      | 11,510  |   |  |   | 5,594   |  
|                                                                                          |  |                          |         |   |      |   |         |      |  |   |         |   |  |      |         |   |  |   |         |  
|Income (loss) before cumulative effect of change in accounting principle                  |  |                          | 1,356   |   |      |   | (51,463 | )    |  |   | (4,700  | ) |  |      | (21,383 | ) |  |   | (10,398 | )
|Cumulative effect of change in accounting principle, net of tax(3)                        |  |                          |        |   |      |   | 662     |      |  |   |        |   |  |      |        |   |  |   |        |  
|                                                                                          |  |                          |         |   |      |   |         |      |  |   |         |   |  |      |         |   |  |   |         |  
|Net income (loss)                                                                         |  | $                        | 1,356   |   |      | $ | (50,801 | )    |  | $ | (4,700  | ) |  | $    | (21,383 | ) |  | $ | (10,398 | )
|                                                                                          |  |                          |         |   |      |   |         |      |  |   |         |   |  |      |         |   |  |   |         |  
|Weighted average number of common shares outstanding:                                     |  |                          |         |   |      |   |         |      |  |   |         |   |  |      |         |   |  |   |         |  
|Basic                                                                                     |  |                          | 24,944  |   |      |   | 22,975  |      |  |   | 20,315  |   |  |      | 19,704  |   |  |   | 14,286  |  
|                                                                                          |  |                          |         |   |      |   |         |      |  |   |         |   |  |      |         |   |  |   |         |  
|Diluted                                                                                   |  |                          | 25,271  |   |      |   | 22,975  |      |  |   | 20,315  |   |  |      | 19,704  |   |  |   | 14,286  |  
|                                                                                          |  |                          |         |   |      |   |         |      |  |   |         |   |  |      |         |   |  |   |         |  
|Basic and diluted income (loss) per common share:                                         |  |                          |         |   |      |   |         |      |  |   |         |   |  |      |         |   |  |   |         |  
|Income (loss) before cumulative effect of change in accounting principle                  |  | $                        | 0.05    |   |      | $ | (2.24   | )    |  | $ | (0.23   | ) |  | $    | (1.09   | ) |  | $ | (0.73   | )
|Net income (loss)                                                                         |  | $                        | 0.05    |   |      | $ | (2.21   | )    |  | $ | (0.23   | ) |  | $    | (1.09   | ) |  | $ | (0.73   | )



Table and footnotes
continued on following page



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|                               |  |              |         |      |   |         |      |  |   |         |   |  |      |         |   |  |   |         |  
|------------------------------ |  | ------------ | ------- | ---- | - | ------- | ---- |  | - | ------- | - |  | ---- | ------- | - |  | - | ------- | -
|                               |  | December 31, |        
|                               |  | 2004         |         | 2003 |   |         | 2002 |  |   | 2001    |   |  | 2000 |        
|Balance Sheet Data:            |  |              |         |      |   |         |      |  |   |         |   |  |      |         |   |  |   |         |  
|Cash and cash equivalents      |  | $            | 102,774 |      | $ | 4,564   |      |  | $ | 6,944   |   |  | $    | 5,294   |   |  | $ | 18,136  |  
|Working capital (deficit)      |  |              | 68,330  |      |   | (46,423 | )    |  |   | (13,699 | ) |  |      | (29,071 | ) |  |   | (3,835  | )
|Net oil and gas properties     |  |              | 213,206 |      |   | 189,125 |      |  |   | 119,036 |   |  |      | 133,033 |   |  |   | 98,725  |  
|Total assets                   |  |              | 372,147 |      |   | 217,685 |      |  |   | 182,055 |   |  |      | 177,564 |   |  |   | 161,993 |  
|Total debt                     |  |              | 210,309 |      |   | 115,409 |      |  |   | 86,387  |   |  |      | 100,111 |   |  |   | 116,529 |  
|Total liabilities              |  |              | 314,983 |      |   | 213,353 |      |  |   | 143,508 |   |  |      | 132,572 |   |  |   | 175,172 |  
|Shareholders equity (deficit) |  |              | 57,164  |      |   | 4,332   |      |  |   | 38,547  |   |  |      | 44,992  |   |  |   | (13,179 | )

---

|(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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##### Table of Contents

|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 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;
| | - |  | ---------------------------------



| |  |  | 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. As a result of this strategy, we have successfully brought 37 out of 38 (97%) projects with proved undeveloped reserve to production since our inception.



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



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



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Review of 2004



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



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



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



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



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



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



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



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



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



2005 Operational and Financial Objectives



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



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



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



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



Results of
Operations



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



Oil and Gas Revenues



Revenues presented in the table and the discussion below represent revenue
from sales of our oil and natural gas production volumes. Production sold under fixed price delivery contracts, which have been designated for the normal purchase and sale exemption under SFAS 133, are also included in these amounts. Approximately
47%, 26% and 8% of our oil production was sold under these contracts for the years ended December 31, 2004, 2003 and 2002, respectively. Approximately 46%, 45% and 14% of our natural gas production was sold under these contracts for the comparable
periods. The realized prices below may differ from the market prices in effect during the periods depending on when the fixed price delivery contract was executed.



Table and footnote on following page



33



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|                                           |  |                          |         |   |                           |   |         |                            |  |   |        |   |  |     |    |  |      |   
|------------------------------------------ |  | ------------------------ | ------- | - | ------------------------- | - | ------- | -------------------------- |  | - | ------ | - |  | --- | -- |  | ---- | --
|                                           |  | Years Ended December 31, |         |   | % Change from 2003to 2004 |   |         | % Change from 2002 to 2003 | 
|                                           |  | 2004                     |         |   | 2003                      |   |         | 2002                       |  |   |       
|Production (1):                            |  |                          |         |   |                           |   |         |                            |  |   |        |   |  |     |    |  |      |   
|Natural gas (MMcf)                         |  |                          | 17,816  |   |                           |   | 10,842  |                            |  |   | 17,732 |   |  | 64  | %  |  | (39  | %)
|Oil and condensate (MBbls)                 |  |                          | 765     |   |                           |   | 1,042   |                            |  |   | 1,454  |   |  | (27 | %) |  | (28  | %)
|Total (MMcfe)                              |  |                          | 22,408  |   |                           |   | 17,093  |                            |  |   | 26,457 |   |  | 31  | %  |  | (35  | %)
|                                           |  |                          |         |   |                          
|Revenues (in thousands):                   |  |                          |         |   |                           |   |         |                            |  |   |        |   |  |     |    |  |      |   
|Natural gas                                |  | $                        | 91,251  |   |                           | $ | 52,199  |                            |  | $ | 56,659 |   |  | 75  | %  |  | (8   | %)
|Effects of cash flow hedges                |  |                          | (1,198  | ) |                           |   | (15,302 | )                          |  |   | (2,764 | ) |  | 92  | %  |  | (454 | %)
|                                           |  |                          |         |   |                           |   |         |                            |  |   |        |   |  |     |    |  |      |   
|Total                                      |  | $                        | 90,053  |   |                           | $ | 36,897  |                            |  | $ | 53,895 |   |  | 144 | %  |  | (31  | %)
|                                           |  |                          |         |   |                           |   |         |                            |  |   |        |   |  |     |    |  |      |   
|Oil and condensate                         |  |                          | 25,970  |   |                           |   | 29,601  |                            |  |   | 32,756 |   |  | (12 | %) |  | (10  | %)
|Effects of cash flow hedges                |  |                          |        |   |                           |   | (1,262  | )                          |  |   | (615   | ) |  | 100 | %  |  | (105 | %)
|                                           |  |                          |         |   |                           |   |         |                            |  |   |        |   |  |     |    |  |      |   
|Total                                      |  | $                        | 25,970  |   |                           | $ | 28,339  |                            |  | $ | 32,141 |   |  | (8  | %) |  | (12  | %)
|                                           |  |                          |         |   |                           |   |         |                            |  |   |        |   |  |     |    |  |      |   
|Natural gas, oil and condensate            |  |                          | 117,221 |   |                           |   | 81,800  |                            |  |   | 89,415 |   |  | 43  | %  |  | (9   | %)
|Effects of cash flow hedges                |  |                          | (1,198  | ) |                           |   | (16,564 | )                          |  |   | (3,379 | ) |  | 93  | %  |  | (390 | %)
|                                           |  |                          |         |   |                           |   |         |                            |  |   |        |   |  |     |    |  |      |   
|Total                                      |  | $                        | 116,023 |   |                           | $ | 65,236  |                            |  | $ | 86,036 |   |  | 78  | %  |  | (24  | %)
|                                           |  |                          |         |   |                           |   |         |                            |  |   |        |   |  |     |    |  |      |   
|Average realized sales price per unit:     |  |                          |         |   |                           |   |         |                            |  |   |        |   |  |     |    |  |      |   
|Natural gas (per Mcf)                      |  | $                        | 5.12    |   |                           | $ | 4.82    |                            |  | $ | 3.20   |   |  | 6   | %  |  | 51   | % 
|Effects of cash flow hedges (per Mcf)      |  |                          | (0.07   | ) |                           |   | (1.41   | )                          |  |   | (0.16  | ) |  | 95  | %  |  | (781 | %)
|                                           |  |                          |         |   |                           |   |         |                            |  |   |        |   |  |     |    |  |      |   
|Average realized price (per Mcf)           |  | $                        | 5.05    |   |                           | $ | 3.41    |                            |  | $ | 3.04   |   |  | 48  | %  |  | 12   | % 
|                                           |  |                          |         |   |                           |   |         |                            |  |   |        |   |  |     |    |  |      |   
|Oil and condensate (per Bbl)               |  | $                        | 33.93   |   |                           | $ | 28.42   |                            |  | $ | 22.53  |   |  | 19  | %  |  | 26   | % 
|Effects of cash flow hedges (per Bbl)      |  |                          |        |   |                           |   | (1.21   | )                          |  |   | (0.42  | ) |  | 100 | %  |  | (188 | %)
|                                           |  |                          |         |   |                           |   |         |                            |  |   |        |   |  |     |    |  |      |   
|Average realized price (per Bbl)           |  | $                        | 33.93   |   |                           | $ | 27.21   |                            |  | $ | 22.11  |   |  | 25  | %  |  | 23   | % 
|                                           |  |                          |         |   |                           |   |         |                            |  |   |        |   |  |     |    |  |      |   
|Natural gas, oil and condensate (per Mcfe) |  | $                        | 5.23    |   |                           | $ | 4.79    |                            |  | $ | 3.38   |   |  | 9   | %  |  | 42   | % 
|Effects of cash flow hedges (per Mcfe)     |  |                          | (0.05   | ) |                           |   | (0.97   | )                          |  |   | (0.13  | ) |  | 94  | %  |  | (646 | %)
|                                           |  |                          |         |   |                           |   |         |                            |  |   |        |   |  |     |    |  |      |   
|Average realized price (per Mcfe)          |  | $                        | 5.18    |   |                           | $ | 3.82    |                            |  | $ | 3.25   |   |  | 36  | %  |  | 18   | % 
|                                           |  |                          |         |   |                           |   |         |                            |  |   |        |   |  |     |    |  |      |   

---

|(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.
|--- | ---------------------------------------------------------------------------------------------------------------------------------------------------



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.



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



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Lease Operating Expense



Lease operating expenses include costs incurred to operate and maintain wells and related equipment and facilities. These
costs include, among others, workover expenses, operator fees, processing fees, insurance and transportation. Lease operating expense for the years ended December 31, 2004, 2003 and 2002 was as follows ($ in thousands):



|                        |  |                          |        |                            |   |        |                            |   |        |  |     |    |  |    |  
|----------------------- |  | ------------------------ | ------ | -------------------------- | - | ------ | -------------------------- | - | ------ |  | --- | -- |  | -- | -
|                        |  | Years Ended December 31, |        | % Change from 2003 to 2004 |   |        | % Change from 2002 to 2003 |  
|                        |  | 2004                     |        | 2003                       |   | 2002   |                            |  
|Lease operating expense |  | $                        | 19,531 |                            | $ | 17,173 |                            | $ | 16,764 |  | 14  | %  |  | 2  | %
|Per Mcfe                |  | $                        | 0.87   |                            | $ | 1.00   |                            | $ | 0.63   |  | (13 | %) |  | 59 | %



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.



The 59% increase per Mcfe in 2003 compared to 2002 was primarily attributable to the aforementioned decrease in production
while certain costs remained fixed. In addition, workover activities on eight properties and the effect of higher fixed costs on those properties with lower production rates in 2003 than in 2002 contributed to the increase.



General and Administrative Expense; Credit Facility Expenses



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, 2004, 2003 and 2002 was as follows ($ in thousands):



|                                   |  |                          |        |                            |   |        |                            |   |        |  |    |   |  |    |  
|---------------------------------- |  | ------------------------ | ------ | -------------------------- | - | ------ | -------------------------- | - | ------ |  | -- | - |  | -- | -
|                                   |  | Years Ended December 31, |        | % Change from 2003 to 2004 |   |        | % Change from 2002 to 2003 |  
|                                   |  | 2004                     |        | 2003                       |   | 2002   |                            |  
|General and administrative expense |  | $                        | 15,806 |                            | $ | 12,209 |                            | $ | 10,037 |  | 29 | % |  | 22 | %
|Per Mcfe                           |  | $                        | 0.71   |                            | $ | 0.71   |                            | $ | 0.38   |  | 0  | % |  | 87 | %



The increase in 2004
compared to 2003, on an absolute basis 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.



The increase in 2003 compared to 2002, on both an absolute and a per-unit
basis was primarily due to higher professional fees and compensation related costs.



In 2004 and 2003, we recorded substantial non-recurring costs of $1.9 million and $2.0 million related to expenses incurred on behalf of waivers and amendments executed with our prior credit facilities.



Depreciation, Depletion and Amortization



Depreciation, depletion and amortization expense (DD&A) for
the years ended December 31, 2004, 2003 and 2002 was as follows ($ in thousands):



|         |  |                          |        |                            |   |        |                            |   |        |  |    |   |  |     |   
|-------- |  | ------------------------ | ------ | -------------------------- | - | ------ | -------------------------- | - | ------ |  | -- | - |  | --- | --
|         |  | Years Ended December 31, |        | % Change from 2003 to 2004 |   |        | % Change from 2002 to 2003 |  
|         |  | 2004                     |        | 2003                       |   | 2002   |                            |  
|DD&A     |  | $                        | 55,637 |                            | $ | 29,378 |                            | $ | 43,390 |  | 89 | % |  | (32 | %)
|Per Mcfe |  | $                        | 2.48   |                            | $ | 1.72   |                            | $ | 1.64   |  | 44 | % |  | 5   | % 



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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.



DD&A expense decreased 32% in 2003 as compared to 2002 primarily due to
the 35% decrease in production. The average DD&A per Mcfe increase was due primarily to downward reserve revisions on two of our properties and impairments taken in 2002.



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.



On two of our properties in 2002, the future undiscounted cash flows were less than their individual net book value.
As a result, we recorded impairments of $6.8 million in 2002. The impairments in 2002 were primarily the result of reductions in recoverable reserves. The impairments were calculated as the difference between the carrying value and the estimated
fair value of the impaired depletable unit.



Loss on
Abandonment



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.



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 for $8.2 million. We paid this amount in the first quarter of 2004 and the Court dismissed the lawsuit on April 16, 2004.



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.



Other



In the fourth quarter of 2002, we filed an insurance claim covering the
estimated damages and lost production from the Gulf of Mexico region resulting from the effects of Hurricane Lili in October 2002. At December 31, 2002, we recorded amounts recoverable, net of deductibles, of approximately $1.5 million for damages
to ten properties and lost production on four properties through December 31, 2002. During 2003, we received an additional $2.2 million for damages incurred, based upon the final agreed upon claim with the underwriters.



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##### Table of Contents

Interest Expense



Interest expense increased $12.6 million, to $22.3 million for 2004 from $9.7 million for 2003 primarily due to higher
outstanding debt as a result of the replacement of our prior credit facility with the term loan.



Income Taxes



During 2004, we provided a valuation allowance against all of our deferred tax assets recoded 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



Liquidity and Capital Resources



At December 31, 2004, we had working capital of approximately $68.3 million,
an increase of approximately $114.8 million from December 31, 2003. Our working capital position improved dramatically as a result of several events during 2004 including the following:



| |  |  | the sale in 2004 of 25% of our interest in seven projects containing ten offshore blocks in the Gulf of Mexico for $19.2 million in net proceeds;
| | - |  | -------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | commencement of production during 2004 from 12 new wells of which 11 are in the Gulf of Mexico and one is our Helvellyn well in the North Sea;
| | - |  | ----------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | receipt of net proceeds of approximately $56.0 million in March 2004 from the closing of our new term loan after repayment of borrowings under our prior credit facility and related
expenses;
| | - |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | receipt of net proceeds of approximately $18.4 million in September 2004 from amending our term loan and
| | - |  | --------------------------------------------------------------------------------------------------------



| |  |  | receipt of net proceeds of approximately $53.1 million in December 2004 from a secondary offering of 4,000,000 shares of our common stock.
| | - |  | ------------------------------------------------------------------------------------------------------------------------------------------



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 the sale on a promoted basis of interests in selected properties. We intend to finance our near-term development projects in the Gulf of
Mexico and North Sea through available cash flows, remaining proceeds from our new term loan and the potential sell down of a portion of our interests in the development projects. 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 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.



Cash Flows



|                            |  |                          |         |   |      |   |         |      |  |   |         |  
|--------------------------- |  | ------------------------ | ------- | - | ---- | - | ------- | ---- |  | - | ------- | -
|                            |  | Years Ended December 31, |        
|                            |  | 2004                     |         |   | 2003 |   |         | 2002 | 
|                            |  | (in thousands)           |        
|Cash provided by (used in): |  |                          |         |   |      |   |         |      |  |   |         |  
|Operating activities        |  | $                        | 41,218  |   |      | $ | 51,009  |      |  | $ | 51,298  |  
|Investing activities        |  |                          | (68,651 | ) |      |   | (84,043 | )    |  |   | (35,167 | )
|Financing activities        |  |                          | 125,698 |   |      |   | 30,654  |      |  |   | (14,481 | )



Operating
activities. Net cash provided by operating activities was $41.2 million for the year ended December 31, 2004 compared to $51.0 million for the year ended December 31, 2003. Cash flow from operations decreased primarily due to substantial
drilling activity in the fourth quarter of 2004 and the subsequent increase in amounts due from partners for those capital costs incurred. In addition, we used available cash to reduce amounts owed to third parties in early 2004.



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##### Table of Contents

Investing activities. Cash used in investing activities in 2004 and 2003 was $68.7 million and
$84.0 million, respectively. Developmental capital expenditures in the Gulf of Mexico and North Sea were approximately $77.3 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 discussed below. We also acquired interests in five blocks in the Gulf of Mexico well for $1.2 million in 2004. In 2003, developmental capital expenditures in the Gulf of Mexico and the North Sea were
approximately $57.2 million and $24.7 million, respectively. We also incurred acquisition costs of $1.9 million in the Gulf of Mexico in 2003.



In February 2004, we entered into an agreement to sell 25% of our working interests as of January 1, 2004 in seven Gulf of Mexico (GOM)
properties for $19.5 million. This sale represents 10.6 Bcfe of proved reserves (5.2% of our GOM reserves), 94% of which were proved undeveloped at December 31, 2003. The sale was implemented in two stages. The first stage closed in February 2004
whereby we received $10.5 million for a 25% interest in one property and a 10% interest in six properties. The second stage closed on April 20, 2004 whereby we received $9.0 million for the remaining 15% interests in the six properties (see Note 5
to the Consolidated Financial Statements).



Financing
activities. Cash provided by financing activities in 2004 consisted of net payments of $117.1 million related to our prior credit facility and net proceeds of $212.9 million related to our new term loan and warrants issued. 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. We also incurred deferred financing costs of approximately $13.5 million related to the term loan and its amendment. 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. Cash provided by financing activities in 2003 included the private placement sale of four million
shares of common stock to accredited investors for a total consideration of $11.8 million ($10.9 million net of placement fees and other expenses). In addition, we received net cash proceeds of $23.2 million from our prior and current term loan.



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



|                                                 |  |              |         |   |      |   |        
|------------------------------------------------ |  | ------------ | ------- | - | ---- | - | -------
|                                                 |  | December 31,
|                                                 |  | 2004         |         |   | 2003
|Credit facility                                  |  | $            |        |   |      | $ | 115,409
|Term loan, net of unamortized discount of $8,129 |  |              | 210,309 |   |      |   |       
|                                                 |  |              |         |   |      |   |        
|Total debt                                       |  |              | 210,309 |   |      |   | 115,409
|Less current maturities                          |  |              | (2,200  | ) |      |   |       
|                                                 |  |              |         |   |      |   |        
|Total long-term debt                             |  | $            | 208,109 |   |      | $ | 115,409
|                                                 |  |              |         |   |      |   |        



Term Loan



On March 29, 2004, we entered into a new $185.0 million
term loan (Term Loan) of which $150.0 million is a Senior Secured First Lien Term Loan Facility and $35.0 million is a Senior Secured Second Lien Term Loan Facility. The Term Loan matures in March 2009. 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 and ATP Oil & Gas (U.K.) Limited. We used $116.2 million of the proceeds of the Term Loan to repay
in full our previous credit facility in effect at December 31, 2003. At closing, we received net proceeds of $56.0 million after repaying our previous credit facility, the repurchase of 750,000 warrants associated with the previous credit facility
described below, a 3% original issue discount of $5.6 million and fees associated with the transaction.



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As consideration for an amendment and waivers of non-compliance with certain covenants under our previous
credit facility, on February 16, 2004 we issued warrants to the lender to purchase 750,000 shares of our common stock. The warrants were issued with an exercise price of $6.75 per share, had an expiration of February 16, 2009 and were accounted for
as additional paid-in-capital. The warrants also included the right, under certain conditions, for us to repurchase all of the outstanding warrants for $750,000 prior to May 17, 2004, when the warrants became exercisable. On March 29, 2004, these
warrants were repurchased for $750,000 and retired with a decrease to additional paid-in-capital.



The Term Loan was issued on March 29, 2004 at an average annual interest rate of 10.8%. The $150.0 million term loan bore interest at the base rate plus a
margin of 7.5% or LIBOR (with a 2% floor) plus a margin of 8.5% at the election of ATP. The $35.0 million term loan bore interest at the base rate plus a margin of 9.0% or LIBOR (with a 2% floor) plus a margin of 10.0% at our election.



In connection with the issuance of the Term Loan, we paid fees and
expenses of $8.6 million and 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, the Term Loan was amended to effect the following:



| |  |  | increase the first lien term Loan borrowings by $35.0 million;
| | - |  | --------------------------------------------------------------



| |  |  | decrease the margin on any first lien term loan base rate loan from 8.5% to 5.25%;
| | - |  | ----------------------------------------------------------------------------------



| |  |  | decrease the margin on any first lien term loan LIBOR loan from 9.5% to 6.25%;
| | - |  | ------------------------------------------------------------------------------



| |  |  | eliminate the first lien term loan 2.00% floor for LIBOR, and
| | - |  | -------------------------------------------------------------



| |  |  | increase the amount of permitted business investments from $10.0 million to $25.0 million in any fiscal year and allow for restricted payments up to $5.0 million in any fiscal year.
| | - |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



In addition, under the first and second lien
facilities, the lender consented to the repurchase by the borrower of 1,926,837 of the 2,432,336 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 current fair value of the unregistered warrants as of that date. 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.



Net
proceeds from the additional borrowing were $18.4 million after the warrant repurchase and fees and expenses of $5.0 million. Of the $5.0 million, $4.9 million paid to the Lender was capitalized and is being amortized over the remaining life of the
loan and $0.1 million of third party legal fees was expensed.



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##### Table of Contents

The terms of the Term Loan, as amended September 24, 2004, 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;
| | - |  | -------------------------



| |  |  | Consolidated Net Debt to EBITDAX coverage ratio which is not greater than 3.25/1.0 through June 30, 2004 and 3.0/1.0 at each of the quarters ending thereafter;
| | - |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Consolidated EBITDAX to Interest Expense which is not less than 2.5/1.0 for any four consecutive fiscal quarters commencing with the quarter ended June 30, 2004 and at each of the
quarters ending thereafter;
| | - |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Pre-tax PV10 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 PV10 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;
| | - |  | ------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Net Debt to Proved Developed Oil and Gas Reserves of less than $2.50/Mcfe at December 31, 2004 and at each of the years ending thereafter, and
| | - |  | ----------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | the requirement to maintain hedges on no less than 40% of the next twelve months of forecasted production attributable to our proved producing reserves.
| | - |  | --------------------------------------------------------------------------------------------------------------------------------------------------------



As of December 31, 2004, 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.



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, 2004 (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                  |  | $                      | 218,438 |                  | $ | 2,200     |  | $         | 163,416 |               | $ | 52,822 |  | $ |   
|Interest on long-term debt(1)   |  |                        | 68,686  |                  |   | 20,053    |  |           | 48,633  |               |   |       |  |   |   
|Non-cancelable operating leases |  |                        | 4,117   |                  |   | 640       |  |           | 1,811   |               |   | 1,017  |  |   | 649
|                                |  |                        |         |                  |   |           |  |           |         |               |   |        |  |   |    
|Total contractual obligations   |  | $                      | 291,241 |                  | $ | 22,893    |  | $         | 213,860 |               | $ | 53,839 |  | $ | 649
|                                |  |                        |         |                  |   |           |  |           |         |               |   |        |  |   |    

---

|(1) | Interest is based on rates and quarterly principal payments in effect at December 31, 2004.
|--- | -------------------------------------------------------------------------------------------



Our liabilities also include asset retirement obligations ($4.9 million
current and $20.0 million long-term) that represent the estimated fair value at December 31, 2004 of our obligations with respect to the retirement/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 4 to the
Consolidated Financial Statements.



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##### Table of Contents

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



Oil and gas exploration and production companies may elect to account for
their property costs using either the successful efforts or full cost 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. Selection of the oil and gas accounting method can have a significant
impact on a companys financial results. We use the successful efforts method of accounting and generally pursue acquisitions and development of proved reserves as opposed to exploration activities.



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



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##### Table of Contents

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. Our Gulf of Mexico and
Netherlands reserves quantities are prepared annually by independent petroleum engineers Ryder Scott Company, L.P. and our U.K. Sector  North Sea reserves are prepared annually by independent petroleum consultants RPS Troy Ikoda Limited. 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 4, Asset Retirement Obligations, 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



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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 believes that the recorded amounts, if any, are
reasonable.



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 and price swaps, which are generally placed with major financial institutions or with
counter-parties 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 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, 2004, we had three derivative contracts in place that qualified as cash
flow hedges.



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.



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 shareholders 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. 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.



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##### Table of Contents

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.



|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 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. During 2004, we
hedged approximately 54% of our oil and natural gas production.



|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
|------- | ------------------------------------------------------------------------------------



The Audit Committee of the Board of Directors of ATP annually considers and
appoints ATPs independent auditors. On April 16, 2004, the Audit Committee dismissed KPMG LLP (KPMG) as ATPs independent auditors upon the conclusion of services related to the fiscal year ending December 31, 2003. KPMG
served as ATPs independent auditors since 1997. On April 19, 2004, the Audit Committee voted to



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engage Deloitte & Touche LLP to serve as ATPs independent auditors for the fiscal year ending December 31, 2004. The appointment of Deloitte &
Touche LLP was ratified by ATPs shareholders at the 2004 Annual Meeting.



KPMGs audit reports on ATPs consolidated financial statements as of and for the years ended December 31, 2003 and 2002 did not contain an adverse opinion or disclaimer of opinion, nor were they qualified
or modified as to uncertainty, audit scope or accounting principles, except as follows:



KPMGs audit reports on the consolidated financial statements of ATP as of and for the years ended December 31, 2003 and 2002, contained a separate paragraph stating that As discussed in Note 3 to the
financial statements, effective January 1, 2003, the Company changed its method of accounting for asset retirement obligations, and effective January 1, 2001, the Company changed its method of accounting for derivative financial instruments.
These changes were made and this explanatory language was included pursuant to the required adoption on January 1, 2003 of Statement of Financial Accounting Standard (SFAS) No. 143, Accounting for Asset Retirement
Obligations, and the required adoption on January 1, 2001 of SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended.



During ATPs two most recent fiscal years and through April 16, 2004, there were no disagreements with KPMG on any
matter of accounting principles or practices, financial statement disclosure, or auditing scope or procedure which, if not resolved to KPMGs satisfaction, would have caused it to make reference to the subject matter in connection with its
report on ATPs consolidated financial statements for such years; and ATP did not consult Deloitte & Touche LLP with respect to the application of accounting principles to a specified transaction, either completed or proposed, or the type
of audit opinion that might be rendered on ATPs consolidated financial statements.



|Item 9a. | Controls and Procedures
|-------- | -----------------------



In order to ensure that the information we must disclose in our filings with the Securities and Exchange Commission is recorded, processed, summarized,
and reported on a timely basis, we have formalized our disclosure controls and procedures. Our principal executive officer and principal financial officer have reviewed and evaluated the effectiveness of our disclosure controls and procedures, as
defined in Exchange Act Rules 13a-15(e) and 15d-15(e), as of December 31, 2004. Based on such evaluation, such officers have concluded that, as of December 31, 2004, our disclosure controls and procedures were effective in timely alerting them to
material information relating to us (and our consolidated subsidiaries) required to be included in our periodic SEC filings. There has been no change in our internal control over financial reporting during the year ended December 31, 2004 that has
materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.



The Sarbanes-Oxley Act of 2002 (the Act) imposed many requirements regarding corporate governance and financial reporting. One requirement
under section 404 of the Act, beginning with this annual report, is for management to report on the Companys internal controls over financial reporting and for our independent registered public accountants to attest to this report. In late
November 2004, the Securities and Exchange Commission issued an exemptive order providing a 45 day extension for the filing of these reports and attestations by eligible companies. We elected to utilize this 45 day extension, therefore, this Form
10-K does not include these reports. These reports will be included in an amended Form 10-K expected to be filed on or before May 2, 2005. Currently, we are not aware of any material weaknesses in our internal controls over financial reporting and
related disclosures.



|Item 9b. | Other Information
|-------- | -----------------



None.



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##### Table of Contents



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 8, 2005 (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 Accountant Fees and Services
|-------- | --------------------------------------



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



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PART IV



|Item 15. | Exhibits, Financial Statement Schedules and Reports on Form 8-K
|-------- | ---------------------------------------------------------------



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



See Index to Consolidated Financial Statements
on page F-1.



(a) (3) Exhibit



|     |  |                                                                                                                                                                                                                                                                                                                            
|---- |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|3.1  |  | Amended and Restated Articles of Incorporation (incorporated by reference to Exhibit 3.1 of ATPs registration statement No. 333-46034 on Form S-1)                                                                                                                                                                        
|     | 
|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  |  | Form of Common Stock Certificate (incorporated by reference to Exhibit 4.1 of ATPs registration statement No. 333-46034 on Form S-1)                                                                                                                                                                                      
|     | 
|4.2  |  | Warrant Shares Registration Rights Agreement dated as of February 16, 2004 by and between the Registrant and each of the Holders set forth on the execution pages thereof (incorporated by
reference to Exhibit 4.1 of ATPs Form 8-K filed on February 27, 2004)                                                          
|     | 
|4.3  |  | Warrant dated as of February 16, 2004 by and between ATP Oil and Gas Corporation and Ableco Holding LLC (incorporated by reference to Exhibit 4.2 of ATPs Form 8-K filed on February 27,
2004)                                                                                                                            
|     | 
|4.4  |  | Warrant dated as of February 16, 2004 by and between ATP Oil & Gas Corporation and Wells Fargo Foothill, Inc. (incorporated by reference to Exhibit 4.3 of ATPs Form 8-K filed on
February 27, 2004)                                                                                                                      
|     | 
|4.5  |  | Warrant Shares Registration Rights Agreement dated as of March 29, 2004 between ATP Oil & Gas Corporation and each of the Holders set forth on the execution pages thereof (incorporated by
reference to Exhibit 4.5 of ATPs Annual Report on Form 10-K for the year ended December 31, 2003)                             
|     | 
|4.6  |  | Warrant Agreement dated as of March 29, 2004 by and among ATP Oil & Gas Corporation and the Holders from time to time of the warrants issued hereunder (incorporated by reference to
Exhibit 4.6 of ATPs Annual Report on Form 10-K for the year ended December 31, 2003)                                                 
|     | 
|10.1 |  | Gas Service Agreement, dated December 31, 1998, between American Citigas Company and ATP Energy, Inc. (incorporated by reference to Exhibit 10.6 of ATPs registration statement No.
333-46034 on Form S-1)                                                                                                                
|     | 
|10.2 |  | Marketing & Natural Gas Purchase Agreement, dated December 1, 1998, between ATP Energy, Inc. and El Paso Energy Marketing Company (incorporated by reference to Exhibit 10.7 of ATPs
registration statement No. 333-46034 on Form S-1)                                                                                    
|     | 
|10.3 |  | 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)                                                                                                                                                                     
|     | 
|10.4 |  | 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)                                                                                                                                             
|     | 
|10.5 |  | ATP Oil & Gas Corporation 2000 Stock Plan (incorporated by reference to Exhibit 10.11 of ATPs Annual Report on Form 10-K for the year ended December 31, 2000)                                                                                                                                                            
|     | 
|10.6 |  | Note Purchase Agreement dated June 29, 2001 between ATP Oil & Gas Corporation and Aquila Energy Capital Corporation (incorporated by reference to Exhibit 10.3 of ATPs Quarterly
Report on Form 10-Q for the quarterly period ended June 30, 2001)                                                                        
|     | 
|10.7 |  | Intercreditor and Subordination Agreement dated June 29, 2001, among ATP Oil & Gas Corporation, Aquila Energy Capital Corporation, BNP Paribas, as Agent, and the Lenders Signatory thereto
(incorporated by reference to Exhibit 10.4 of ATPs Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2001)



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|      |  |                                                                                                                                                                                                                                                                                                                                                           
|----- |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|10.8  |  | Amended and Restated Credit Agreement dated July 31, 2002, among ATP Oil & Gas Corporation, Union Bank of California, N.A., as agent, Guaranty Bank, FSB, as Co-Agent and the Lenders
Signatory thereto (incorporated by reference to Exhibit 10.1 of ATPs Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2002)                   
|      | 
|10.9  |  | First Amendment to Amended and Restated Credit Agreement dated May 12, 2003, among ATP Oil & Gas Corporation, Union Bank of California, N.A., as Agent, Guaranty Bank, FSB, as Co-Agent and
the Lenders Signatory thereto (incorporated by reference to Exhibit 10.1 of ATPs Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2003)
|      | 
|10.10 |  | Second Amended and Restated Financing Agreement dated August 13, 2003, among ATP Oil & Gas Corporation, Ableco Finance LLC, as agent, and Wells Fargo Foothill, Inc., as funding agent
(incorporated by reference to Exhibit 10.1 of ATPs Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2003)                               
|      | 
|10.11 |  | First Amendment to the Second Amended and Restated Financing Agreement dated November 17, 2003, among ATP Oil & Gas Corporation, Ableco Finance LLC, as agent, and Wells Fargo Foothill,
Inc. as funding agent (incorporated by reference to Exhibit 10.2 of ATPs Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2003)       
|      | 
|10.12 |  | Second Amendment to the Second Amended and Restated Financing Agreement dated December, 2003, among ATP Oil & Gas Corporation, Ableco Finance LLC, as agent, and Wells Fargo Foothill, Inc.
as funding agent (incorporated by reference to Exhibit 10.1 of ATPs Form 8-K filed on February 27, 2004)                                                     
|      | 
|10.13 |  | Third Amendment to the Second Amended and Restated Financing Agreement dated February 16, 2004, among ATP Oil & Gas Corporation, Ableco Finance LLC, as agent, and Wells Fargo Foothill,
Inc. as funding agent (incorporated by reference to Exhibit 10.2 of ATPs Form 8-K filed on February 27, 2004)                                                   
|      | 
|10.14 |  | Fourth Amendment to the Second Amended and Restated Financing Agreement dated March 10, 2004, among ATP Oil & Gas Corporation, Ableco Finance LLC, as agent, and Wells Fargo Foothill, Inc.
as funding agent (incorporated by reference to Exhibit 10.14 of ATPs Annual Report on Form 10-K for the year ended December 31, 2003)                        
|      | 
|10.15 |  | First Lien Credit Agreement dated March 29, 2004, among ATP Oil & Gas Corporation and Credit Suisse First Boston, as administrative and funding agent (incorporated by reference to Exhibit
10.15 of ATPs Annual Report on Form 10-K for the year ended December 31, 2003)                                                                               
|      | 
|10.16 |  | Second Lien Credit Agreement dated March 29, 2004, among ATP Oil & Gas Corporation and Credit Suisse First Boston, 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)                                                                              
|      | 
|10.17 |  | Intercreditor Agreement dated as of March 29, 2004 among ATP Oil & Gas Corporation and Credit Suisse First Boston, as first and second lien collateral agents (incorporated by reference to
Exhibit 10.17 of ATPs Annual Report on Form 10-K for the year ended December 31, 2003)                                                                       
|      | 
|10.18 |  | 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 Oil & Gas Corporation, 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)             
|      | 
|10.19 |  | 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 Oil & Gas Corporation, the Lenders, as
administrative agent and as collateral agent for the Lenders (incorporated by reference to Exhibit 10.2 of ATPs Form 8-K filed on September 30, 2004)            
|      | 
|10.20 |  | Subscription and Registration Rights Agreement (incorporated by reference to Exhibit 10.1 of ATPs Form 8-K filed on December 3, 2004)                                                                                                                                                                                                                    
|      | 
|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 Oil & Gas Corporation (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 Troy-Ikoda Limited                                                                                                                                                                                                                                                                                                                         



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|      |  |                                                                           
|----- |  | --------------------------------------------------------------------------
|*31.1 |  | Certificate of Chief Executive Officer (Section 302 of Sarbanes-Oxley Act)
|      | 
|*31.2 |  | Certificate of Chief Financial Officer (Section 302 of Sarbanes-Oxley Act)
|      | 
|*32.1 |  | Certificate of Chief Executive Officer (Section 906 of Sarbanes-Oxley Act)
|      | 
|*32.2 |  | Certificate of Chief Financial Officer (Section 906 of Sarbanes-Oxley Act)

---

|* | Filed herewith
|- | --------------



|(b) | Reports on Form 8-K
|--- | -------------------



Current Report on Form 8-K filed on November 5, 2004, pursuant to Item 2.02, announcing its earnings results for the third quarter of 2004.



Current Report on Form 8-K filed on December 3, 2004, pursuant to Items 1.01
and 3.02, announcing the unregistered sale of equity securities.



Current Report on Form 8-K filed on March 18, 2004, pursuant to Item 2.02, announcing its earnings results for the fourth quarter of 2004.



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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 CorporationBy:

/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 30, 2005.



|                                                |  |                                                               
|----------------------------------------------- |  | --------------------------------------------------------------
|Signature                                       |  | Title                                                         
|                                                | 
|/s/    T. PAUL BULMAHNT. Paul Bulmahn           |  | Chairman, President and Director (Principal Executive Officer)
|                                                | 
|/s/    ALBERT L. REESE,
JR.Albert L. Reese,
Jr. |  | Chief Financial Officer (Principal Financial Officer)         
|                                                | 
|/s/    KEITH R. GODWINKeith R. Godwin           |  | Chief Accounting Officer (Principal Accounting Officer)       
|                                                | 
|/s/    CHRIS A.
BRISACKChris A.
Brisack         |  | Director                                                      
|                                                | 
|/s/    ARTHUR H. DILLYArthur H. Dilly           |  | Director                                                      
|                                                | 
|/s/    GERARD J.
SWONKEGerard J.
Swonke         |  | Director                                                      
|                                                | 
|/s/    ROBERT C.
THOMASRobert C.
Thomas         |  | Director                                                      
|                                                | 
|/s/    WALTER
WENDLANDTWalter
Wendlandt         |  | Director                                                      



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ATP OIL & GAS CORPORATION AND SUBSIDIARIES

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS



|                                                                                                            |  |     
|----------------------------------------------------------------------------------------------------------- |  | ----
|                                                                                                            |  | Page
|ATP OIL & GAS CORPORATION AND SUBSIDIARIES                                                                  |  |     
|                                                                                                            | 
|Report of Independent Registered Public Accounting Firm                                                     |  | F-2 
|                                                                                                            | 
|Report of Independent Registered Public Accounting Firm                                                     |  | F-3 
|                                                                                                            | 
|Consolidated Balance Sheets as of December 31, 2004 and 2003                                                |  | F-4 
|                                                                                                            | 
|Consolidated Statements of Operations for the years ended December 31, 2004, 2003 and 2002                  |  | F-5 
|                                                                                                            | 
|Consolidated Statements of Cash Flows for the years ended December 31, 2004, 2003 and 2002                  |  | F-6 
|                                                                                                            | 
|Consolidated Statements of Shareholders Equity for the years ended December 31, 2004, 2003 and 2002        |  | F-7 
|                                                                                                            | 
|Consolidated Statements of Comprehensive Income (Loss) for the years ended December 31, 2004, 2003 and 2002 |  | F-8 
|                                                                                                            | 
|Notes to Consolidated Financial Statements                                                                  |  | F-9 
|                                                                                                            | 
|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



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##### Table of Contents



REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM



The Board of Directors and Shareholders of

ATP Oil & Gas Corporation:



We have audited the accompanying consolidated balance sheet of ATP Oil & Gas Corporation and subsidiaries (the
Company) as of December 31, 2004 and the related consolidated statement of operations, shareholders equity, comprehensive income (loss) and cash flows for the year ended December 31, 2004. These financial statements are the
responsibility of the Companys management. Our responsibility is to express an opinion on these financial statements based on our audits.



We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we
plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for
our opinion.



In our opinion, such consolidated financial
statements present fairly, in all material respects, the consolidated financial position of the Company as of December 31, 2004 and the consolidated results of its operations and its cash flows for the year ended December 31, 2004, in conformity
with accounting principles generally accepted in the United States of America.



As discussed in Note 3 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 31, 2005



F-2



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##### Table of Contents



REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM



The Board of Directors

ATP Oil & Gas Corporation:



We have audited the accompanying consolidated balance sheet of ATP Oil & Gas Corporation and subsidiaries as of December 31, 2003 and the related
consolidated statements of operations, shareholders equity, comprehensive loss and cash flows for each of the years in the two-year period 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 audits.



We conducted our audits 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 audits provide a reasonable basis for our opinion.



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



As discussed in Note 3 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-3



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##### Table of Contents



ATP OIL & GAS CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(In Thousands, Except Share Amounts)



|                                                                            |  |              |          |   |      |   |          |  
|--------------------------------------------------------------------------- |  | ------------ | -------- | - | ---- | - | -------- | -
|                                                                            |  | December 31, |         
|                                                                            |  | 2004         |          |   | 2003 |  
|Assets                                                                      |  |              |          |   |      |   |          |  
|Current assets:                                                             |  |              |          |   |      |   |          |  
|Cash and cash equivalents                                                   |  | $            | 102,774  |   |      | $ | 4,564    |  
|Accounts receivable (net of allowance of $1,499 and $1,266)                 |  |              | 36,991   |   |      |   | 15,874   |  
|Derivative asset                                                            |  |              | 791      |   |      |   |         |  
|Other current assets                                                        |  |              | 3,788    |   |      |   | 2,461    |  
|                                                                            |  |              |          |   |      |   |          |  
|Total current assets                                                        |  |              | 144,344  |   |      |   | 22,899   |  
|                                                                            |  |              |          |   |      |   |          |  
|Oil and gas properties (using the successful efforts method of accounting): |  |              |          |   |      |   |          |  
|Proved properties                                                           |  |              | 439,887  |   |      |   | 449,131  |  
|Unproved properties not subject to amortization                             |  |              | 10,516   |   |      |   | 1,727    |  
|                                                                            |  |              |          |   |      |   |          |  
|                                                                            |  |              | 450,403  |   |      |   | 450,858  |  
|Less: Accumulated depletion, impairment and amortization                    |  |              | (237,197 | ) |      |   | (261,733 | )
|                                                                            |  |              |          |   |      |   |          |  
|Oil and gas properties, net                                                 |  |              | 213,206  |   |      |   | 189,125  |  
|                                                                            |  |              |          |   |      |   |          |  
|Furniture and fixtures (net of accumulated depreciation)                    |  |              | 741      |   |      |   | 666      |  
|Other assets, net                                                           |  |              | 13,856   |   |      |   | 4,995    |  
|                                                                            |  |              |          |   |      |   |          |  
|Total assets                                                                |  | $            | 372,147  |   |      | $ | 217,685  |  
|                                                                            |  |              |          |   |      |   |          |  
|Liabilities and Shareholders Equity                                        |  |              |          |   |      |   |          |  
|Current liabilities:                                                        |  |              |          |   |      |   |          |  
|Accounts payable and accrued liabilities                                    |  | $            | 68,573   |   |      | $ | 63,054   |  
|Current maturities of long-term debt                                        |  |              | 2,200    |   |      |   |         |  
|Asset retirement obligation                                                 |  |              | 4,925    |   |      |   | 6,102    |  
|Derivative liability                                                        |  |              | 316      |   |      |   | 166      |  
|                                                                            |  |              |          |   |      |   |          |  
|Total current liabilities                                                   |  |              | 76,014   |   |      |   | 69,322   |  
|Long-term debt                                                              |  |              | 208,109  |   |      |   | 115,409  |  
|Asset retirement obligation                                                 |  |              | 19,998   |   |      |   | 15,005   |  
|Deferred revenue                                                            |  |              | 741      |   |      |   | 926      |  
|Other long-term liabilities and deferred obligations                        |  |              | 10,121   |   |      |   | 12,691   |  
|                                                                            |  |              |          |   |      |   |          |  
|Total liabilities                                                           |  |              | 314,983  |   |      |   | 213,353  |  
|                                                                            |  |              |          |   |      |   |          |  
|Commitments and Contingencies                                               |  |              |          |   |      |   |          |  
|Shareholders equity:                                                       |  |              |          |   |      |   |          |  
|Preferred stock: $0.001 par value, 10,000,000 shares authorized             |  |              |         |   |      |   |         |  
|Common stock: $0.001 par value, 100,000,000 shares authorized               |  |              | 29       |   |      |   | 25       |  
|Additional paid in capital                                                  |  |              | 140,628  |   |      |   | 92,277   |  
|Accumulated deficit                                                         |  |              | (88,759  | ) |      |   | (90,115  | )
|Accumulated other comprehensive income                                      |  |              | 6,177    |   |      |   | 3,056    |  
|Treasury stock, at cost                                                     |  |              | (911     | ) |      |   | (911     | )
|                                                                            |  |              |          |   |      |   |          |  
|Total shareholders equity                                                  |  |              | 57,164   |   |      |   | 4,332    |  
|                                                                            |  |              |          |   |      |   |          |  
|Total liabilities and shareholders equity                                  |  | $            | 372,147  |   |      | $ | 217,685  |  
|                                                                            |  |              |          |   |      |   |          |  



See accompanying notes
to the consolidated financial statements.



F-4



---

##### Table of Contents



ATP OIL & GAS CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(In Thousands, Except Per Share Amounts)



|                                                                                          |  |                          |         |   |      |   |         |      |  |   |         |  
|----------------------------------------------------------------------------------------- |  | ------------------------ | ------- | - | ---- | - | ------- | ---- |  | - | ------- | -
|                                                                                          |  | Years Ended December 31, |        
|                                                                                          |  | 2004                     |         |   | 2003 |   |         | 2002 | 
|Revenues:                                                                                 |  |                          |         |   |      |   |         |      |  |   |         |  
|Oil and gas production                                                                    |  | $                        | 116,123 |   |      | $ | 70,151  |      |  | $ | 80,017  |  
|                                                                                          |  |                          |         |   |      |   |         |      |  |   |         |  
|Costs and operating expenses:                                                             |  |                          |         |   |      |   |         |      |  |   |         |  
|Lease operating expenses                                                                  |  |                          | 19,531  |   |      |   | 17,173  |      |  |   | 16,764  |  
|Geological and geophysical expenses                                                       |  |                          | 997     |   |      |   | 1,358   |      |  |   | 154     |  
|General and administrative expenses                                                       |  |                          | 15,806  |   |      |   | 12,209  |      |  |   | 10,037  |  
|Credit facility expenses                                                                  |  |                          | 1,850   |   |      |   | 1,990   |      |  |   | 250     |  
|Non-cash compensation expense                                                             |  |                          |        |   |      |   | (39     | )    |  |   | 595     |  
|Depreciation, depletion and amortization                                                  |  |                          | 55,637  |   |      |   | 29,378  |      |  |   | 43,390  |  
|Impairment of oil and gas properties                                                      |  |                          |        |   |      |   | 11,670  |      |  |   | 6,844   |  
|Accretion expense                                                                         |  |                          | 2,069   |   |      |   | 2,752   |      |  |   |        |  
|(Gain) loss on abandonment                                                                |  |                          | (251    | ) |      |   | 4,973   |      |  |   |        |  
|Gain on disposition of properties                                                         |  |                          | (6,011  | ) |      |   |        |      |  |   |        |  
|Loss on unsuccessful property acquisition                                                 |  |                          |        |   |      |   | 8,192   |      |  |   |        |  
|Other                                                                                     |  |                          | 400     |   |      |   |        |      |  |   |        |  
|                                                                                          |  |                          |         |   |      |   |         |      |  |   |         |  
|                                                                                          |  |                          | 90,028  |   |      |   | 89,656  |      |  |   | 78,034  |  
|                                                                                          |  |                          |         |   |      |   |         |      |  |   |         |  
|Income (loss) from operations                                                             |  |                          | 26,095  |   |      |   | (19,505 | )    |  |   | 1,983   |  
|                                                                                          |  |                          |         |   |      |   |         |      |  |   |         |  
|Other income (expense):                                                                   |  |                          |         |   |      |   |         |      |  |   |         |  
|Interest income                                                                           |  |                          | 627     |   |      |   | 52      |      |  |   | 73      |  
|Interest expense                                                                          |  |                          | (22,262 | ) |      |   | (9,678  | )    |  |   | (10,418 | )
|Loss on extinguishment of debt                                                            |  |                          | (3,326  | ) |      |   | (3,352  | )    |  |   |        |  
|Other                                                                                     |  |                          | 280     |   |      |   | 2,244   |      |  |   | 1,081   |  
|                                                                                          |  |                          |         |   |      |   |         |      |  |   |         |  
|                                                                                          |  |                          | (24,681 | ) |      |   | (10,734 | )    |  |   | (9,264  | )
|                                                                                          |  |                          |         |   |      |   |         |      |  |   |         |  
|Income (loss) before income taxes and cumulative effect of change in accounting principle |  |                          | 1,414   |   |      |   | (30,239 | )    |  |   | (7,281  | )
|Income tax (expense) benefit                                                              |  |                          | (58     | ) |      |   | (21,224 | )    |  |   | 2,581   |  
|                                                                                          |  |                          |         |   |      |   |         |      |  |   |         |  
|Income (loss) before cumulative effect of change in accounting principle                  |  |                          | 1,356   |   |      |   | (51,463 | )    |  |   | (4,700  | )
|Cumulative effect of change in accounting principle, net of tax                           |  |                          |        |   |      |   | 662     |      |  |   |        |  
|                                                                                          |  |                          |         |   |      |   |         |      |  |   |         |  
|Net income (loss)                                                                         |  | $                        | 1,356   |   |      | $ | (50,801 | )    |  | $ | (4,700  | )
|                                                                                          |  |                          |         |   |      |   |         |      |  |   |         |  
|Basic and diluted income (loss) per common share:                                         |  |                          |         |   |      |   |         |      |  |   |         |  
|Income (loss) before cumulative effect of change in accounting principle                  |  | $                        | 0.05    |   |      | $ | (2.24   | )    |  | $ | (0.23   | )
|Cumulative effect of change in accounting principle, net of tax                           |  |                          |        |   |      |   | 0.03    |      |  |   |        |  
|                                                                                          |  |                          |         |   |      |   |         |      |  |   |         |  
|Net income (loss) per common share                                                        |  | $                        | 0.05    |   |      | $ | (2.21   | )    |  | $ | (0.23   | )
|                                                                                          |  |                          |         |   |      |   |         |      |  |   |         |  
|Weighted average number of common shares:                                                 |  |                          |         |   |      |   |         |      |  |   |         |  
|Basic                                                                                     |  |                          | 24,944  |   |      |   | 22,975  |      |  |   | 20,315  |  
|                                                                                          |  |                          |         |   |      |   |         |      |  |   |         |  
|Diluted                                                                                   |  |                          | 25,271  |   |      |   | 22,975  |      |  |   | 20,315  |  
|                                                                                          |  |                          |         |   |      |   |         |      |  |   |         |  



See accompanying notes
to the consolidated financial statements.



|   
|---
|F-5



---

##### Table of Contents



ATP OIL & GAS CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In Thousands)



|                                                                                          |  |                          |          |   |      |   |          |      |  |   |         |  
|----------------------------------------------------------------------------------------- |  | ------------------------ | -------- | - | ---- | - | -------- | ---- |  | - | ------- | -
|                                                                                          |  | Years Ended December 31, |         
|                                                                                          |  | 2004                     |          |   | 2003 |   |          | 2002 | 
|Cash flows from operating activities:                                                     |  |                          |          |   |      |   |          |      |  |   |         |  
|Net income (loss)                                                                         |  | $                        | 1,356    |   |      | $ | (50,801  | )    |  | $ | (4,700  | )
|Adjustments to reconcile net income (loss) to net cash provided by operating activities  |  |                          |          |   |      |   |          |      |  |   |         |  
|Depreciation, depletion and amortization                                                  |  |                          | 55,637   |   |      |   | 29,378   |      |  |   | 43,390  |  
|Impairment of oil and gas properties                                                      |  |                          |         |   |      |   | 11,670   |      |  |   | 6,844   |  
|Gain on disposition of properties                                                         |  |                          | (6,011   | ) |      |   |         |      |  |   |        |  
|Accretion of discount of asset retirement obligation                                      |  |                          | 2,069    |   |      |   | 2,752    |      |  |   |        |  
|Amortization of deferred financing costs                                                  |  |                          | 2,471    |   |      |   | 1,395    |      |  |   | 1,429   |  
|Loss on extinguishment of debt                                                            |  |                          | 3,326    |   |      |   | 883      |      |  |   |        |  
|Deferred tax assets                                                                       |  |                          |         |   |      |   | 21,224   |      |  |   | (2,352  | )
|Non-cash compensation expense                                                             |  |                          |         |   |      |   | (39      | )    |  |   | 595     |  
|Cumulative effect of change in accounting principle                                       |  |                          |         |   |      |   | (662     | )    |  |   |        |  
|Ineffectiveness of cash flow hedges                                                       |  |                          | 190      |   |      |   | 300      |      |  |   | 279     |  
|Accrued interest and credit facility expenses                                             |  |                          | 1,709    |   |      |   | 5,567    |      |  |   |        |  
|Other non-cash items                                                                      |  |                          | 1,585    |   |      |   | 2,712    |      |  |   | 746     |  
|Changes in assets and liabilities                                                        |  |                          |          |   |      |   |          |      |  |   |         |  
|Accounts receivable and other assets                                                      |  |                          | (22,355  | ) |      |   | 9,775    |      |  |   | (14,659 | )
|Restricted cash                                                                           |  |                          |         |   |      |   | 414      |      |  |   | (414    | )
|Derivative liability                                                                      |  |                          | (166     | ) |      |   | (5,074   | )    |  |   | 5,926   |  
|Accounts payable and accruals                                                             |  |                          | 3,822    |   |      |   | 20,091   |      |  |   | 8,910   |  
|Other long-term assets                                                                    |  |                          | 36       |   |      |   |         |      |  |   | (1,525  | )
|Other long-term liabilities and deferred obligations                                      |  |                          | (2,451   | ) |      |   | 1,424    |      |  |   | 6,829   |  
|                                                                                          |  |                          |          |   |      |   |          |      |  |   |         |  
|Net cash provided by operating activities                                                 |  |                          | 41,218   |   |      |   | 51,009   |      |  |   | 51,298  |  
|                                                                                          |  |                          |          |   |      |   |          |      |  |   |         |  
|Cash flows from investing activities:                                                     |  |                          |          |   |      |   |          |      |  |   |         |  
|Additions and acquisitions of oil and gas properties                                      |  |                          | (87,368  | ) |      |   | (83,803  | )    |  |   | (34,873 | )
|Proceeds from disposition of properties                                                   |  |                          | 19,200   |   |      |   |         |      |  |   |        |  
|Additions to furniture and fixtures                                                       |  |                          | (483     | ) |      |   | (240     | )    |  |   | (294    | )
|                                                                                          |  |                          |          |   |      |   |          |      |  |   |         |  
|Net cash used in investing activities                                                     |  |                          | (68,651  | ) |      |   | (84,043  | )    |  |   | (35,167 | )
|                                                                                          |  |                          |          |   |      |   |          |      |  |   |         |  
|Cash flows from financing activities:                                                     |  |                          |          |   |      |   |          |      |  |   |         |  
|Net proceeds from secondary offering                                                      |  |                          | 53,066   |   |      |   | 10,879   |      |  |   |        |  
|Proceeds from long-term debt                                                              |  |                          | 262,000  |   |      |   | 127,168  |      |  |   | 1,000   |  
|Payments of long-term debt                                                                |  |                          | (166,230 | ) |      |   | (103,921 | )    |  |   | (15,000 | )
|Deferred financing costs                                                                  |  |                          | (13,502  | ) |      |   | (3,827   | )    |  |   | (495    | )
|Repurchase of warrants                                                                    |  |                          | (12,311  | ) |      |   |         |      |  |   |        |  
|Other                                                                                     |  |                          | 2,675    |   |      |   | 355      |      |  |   | 14      |  
|                                                                                          |  |                          |          |   |      |   |          |      |  |   |         |  
|Net cash provided by (used in) financing activities                                       |  |                          | 125,698  |   |      |   | 30,654   |      |  |   | (14,481 | )
|                                                                                          |  |                          |          |   |      |   |          |      |  |   |         |  
|Effect of exchange rate changes on cash                                                   |  |                          | (55      | ) |      |   |         |      |  |   |        |  
|                                                                                          |  |                          |          |   |      |   |          |      |  |   |         |  
|Increase (decrease) in cash and cash equivalents                                          |  |                          | 98,210   |   |      |   | (2,380   | )    |  |   | 1,650   |  
|Cash and cash equivalents, beginning of period                                            |  |                          | 4,564    |   |      |   | 6,944    |      |  |   | 5,294   |  
|                                                                                          |  |                          |          |   |      |   |          |      |  |   |         |  
|Cash and cash equivalents, end of period                                                  |  | $                        | 102,774  |   |      | $ | 4,564    |      |  | $ | 6,944   |  
|                                                                                          |  |                          |          |   |      |   |          |      |  |   |         |  
|Supplemental disclosures of cash flow information:                                        |  |                          |          |   |      |   |          |      |  |   |         |  
|Cash paid during the year for interest                                                    |  | $                        | 17,879   |   |      | $ | 3,187    |      |  | $ | 7,361   |  
|                                                                                          |  |                          |          |   |      |   |          |      |  |   |         |  
|Cash paid during the year for income taxes                                                |  | $                        | 150      |   |      | $ |         |      |  | $ |        |  
|                                                                                          |  |                          |          |   |      |   |          |      |  |   |         |  



See accompanying notes
to the consolidated financial statements.



F-6



---

##### Table of Contents



ATP OIL & GAS CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF SHAREHOLDERS EQUITY

(In Thousands)



|                                                       |  |        |  |        |         |   |        |        |        |   |         |        |  |        |  |   |         |  
|------------------------------------------------------ |  | ------ |  | ------ | ------- | - | ------ | ------ | ------ | - | ------- | ------ |  | ------ |  | - | ------- | -
|                                                       |  | 2004   |  |        | 2003    |   |        | 2002   |       
|                                                       |  | Shares |  | Amount |         |   | Shares |        | Amount |   |         | Shares |  | Amount | 
|Common Stock                                           |  |        |  |        |         |   |        |        |        |   |         |        |  |        |  |   |         |  
|Balance, beginning of year                             |  | 24,520 |  | $      | 25      |   |        | 20,322 |        | $ | 20      |        |  | 20,313 |  | $ | 20      |  
|Issuances of common stock                              |  |        |  |        |         |   |        |        |        |   |         |        |  |        |  |   |         |  
|Secondary offering                                     |  | 4,000  |  |        | 4       |   |        | 4,000  |        |   | 4       |        |  |       |  |   |        |  
|Exercise of stock options                              |  | 364    |  |        |        |   |        | 198    |        |   | 1       |        |  | 9      |  |   |        |  
|                                                       |  |        |  |        |         |   |        |        |        |   |         |        |  |        |  |   |         |  
|Balance, end of year                                   |  | 28,884 |  | $      | 29      |   |        | 24,520 |        | $ | 25      |        |  | 20,322 |  | $ | 20      |  
|                                                       |  |        |  |        |         |   |        |        |        |   |         |        |  |        |  |   |         |  
|Paid-in Capital                                        |  |        |  |        |         |   |        |        |        |   |         |        |  |        |  |   |         |  
|Balance, beginning of year                             |  |        |  | $      | 92,277  |   |        |        |        | $ | 81,087  |        |  |        |  | $ | 80,478  |  
|Issuances of common stock                              |  |        |  |        |         |   |        |        |        |   |         |        |  |        |  |   |         |  
|Secondary offering                                     |  |        |  |        | 53,062  |   |        |        |        |   | 10,875  |        |  |        |  |   |        |  
|Exercise of stock options                              |  |        |  |        | 2,675   |   |        |        |        |   | 354     |        |  |        |  |   | 14      |  
|Value of warrants issued in connection with financings |  |        |  |        | 4,925   |   |        |        |        |   |        |        |  |        |  |   |        |  
|Repurchase of warrants                                 |  |        |  |        | (12,311 | ) |        |        |        |   |        |        |  |        |  |   |        |  
|Non-cash compensation expense                          |  |        |  |        |        |   |        |        |        |   | (39     | )      |  |        |  |   | 595     |  
|                                                       |  |        |  |        |         |   |        |        |        |   |         |        |  |        |  |   |         |  
|Balance, end of year                                   |  |        |  | $      | 140,628 |   |        |        |        | $ | 92,277  |        |  |        |  | $ | 81,087  |  
|                                                       |  |        |  |        |         |   |        |        |        |   |         |        |  |        |  |   |         |  
|Accumulated Deficit                                    |  |        |  |        |         |   |        |        |        |   |         |        |  |        |  |   |         |  
|Balance, beginning of year                             |  |        |  | $      | (90,115 | ) |        |        |        | $ | (39,314 | )      |  |        |  | $ | (34,614 | )
|Net income (loss)                                      |  |        |  |        | 1,356   |   |        |        |        |   | (50,801 | )      |  |        |  |   | (4,700  | )
|                                                       |  |        |  |        |         |   |        |        |        |   |         |        |  |        |  |   |         |  
|Balance, end of year                                   |  |        |  | $      | (88,759 | ) |        |        |        | $ | (90,115 | )      |  |        |  | $ | (39,314 | )
|                                                       |  |        |  |        |         |   |        |        |        |   |         |        |  |        |  |   |         |  
|Accumulated Other                                      |  |        |  |        |         |   |        |        |        |   |         |        |  |        |  |   |         |  
|Comprehensive Income (Loss)                            |  |        |  |        |         |   |        |        |        |   |         |        |  |        |  |   |         |  
|Balance, beginning of year                             |  |        |  | $      | 3,056   |   |        |        |        | $ | (2,335  | )      |  |        |  | $ | 19      |  
|Other comprehensive income (loss)                      |  |        |  |        | 3,121   |   |        |        |        |   | 5,391   |        |  |        |  |   | (2,354  | )
|                                                       |  |        |  |        |         |   |        |        |        |   |         |        |  |        |  |   |         |  
|Balance, end of year                                   |  |        |  | $      | 6,177   |   |        |        |        | $ | 3,056   |        |  |        |  | $ | (2,335  | )
|                                                       |  |        |  |        |         |   |        |        |        |   |         |        |  |        |  |   |         |  
|Treasury Stock                                         |  |        |  |        |         |   |        |        |        |   |         |        |  |        |  |   |         |  
|Balance, beginning of year                             |  | 76     |  | $      | (911    | ) |        | 76     |        | $ | (911    | )      |  | 76     |  | $ | (911    | )
|Purchase of treasury stock                             |  |       |  |        |        |   |        |       |        |   |        |        |  |       |  |   |        |  
|                                                       |  |        |  |        |         |   |        |        |        |   |         |        |  |        |  |   |         |  
|Balance, end of year                                   |  | 76     |  | $      | (911    | ) |        | 76     |        | $ | (911    | )      |  | 76     |  | $ | (911    | )
|                                                       |  |        |  |        |         |   |        |        |        |   |         |        |  |        |  |   |         |  
|Total Shareholders Equity                             |  |        |  | $      | 57,164  |   |        |        |        | $ | 4,332   |        |  |        |  | $ | 38,547  |  
|                                                       |  |        |  |        |         |   |        |        |        |   |         |        |  |        |  |   |         |  



See accompanying notes
to the consolidated financial statements.



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ATP OIL & GAS CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(In Thousands)



|                                                                |  |                          |       |   |      |   |         |      |  |   |        |  
|--------------------------------------------------------------- |  | ------------------------ | ----- | - | ---- | - | ------- | ---- |  | - | ------ | -
|                                                                |  | Years Ended December 31, |      
|                                                                |  | 2004                     |       |   | 2003 |   |         | 2002 | 
|Net income (loss)                                               |  | $                        | 1,356 |   |      | $ | (50,801 | )    |  | $ | (4,700 | )
|                                                                |  |                          |       |   |      |   |         |      |  |   |        |  
|Other comprehensive income (loss):                              |  |                          |       |   |      |   |         |      |  |   |        |  
|Reclassification adjustment for settled contracts, net of tax   |  |                          | 1,055 |   |      |   | (627    | )    |  |   | 627    |  
|Change in fair value of outstanding hedge positions, net of tax |  |                          | (532  | ) |      |   | 3,651   |      |  |   | (3,651 | )
|Foreign currency translation adjustment                         |  |                          | 2,598 |   |      |   | 2,367   |      |  |   | 670    |  
|                                                                |  |                          |       |   |      |   |         |      |  |   |        |  
|Other comprehensive income (loss)                               |  |                          | 3,121 |   |      |   | 5,391   |      |  |   | (2,354 | )
|                                                                |  |                          |       |   |      |   |         |      |  |   |        |  
|Comprehensive income (loss)                                     |  | $                        | 4,477 |   |      | $ | (45,410 | )    |  | $ | (7,054 | )
|                                                                |  |                          |       |   |      |   |         |      |  |   |        |  



See accompanying notes
to the consolidated financial statements.



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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.



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, 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



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ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS



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 2004 and impairments of $11.7 million and $6.8 million for the years ended December 31, 2003 and 2002, respectively, 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, 2004, 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. 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.



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 years ended December 31, 2003 and 2002, interest of $0.5 million and $0.3 million, respectively, was capitalized. No interest was capitalized in 2004.



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, |       
|                         |  | 2004         |        |   | 2003 |  
|Debt financing costs     |  | $            | 13,466 |   |      | $ | 3,827 |  
|Spare parts inventory    |  |              | 2,126  |   |      |   | 1,762 |  
|Other                    |  |              | 51     |   |      |   | 10    |  
|                         |  |              |        |   |      |   |       |  
|                         |  |              | 15,643 |   |      |   | 5,599 |  
|Accumulated amortization |  |              | (1,787 | ) |      |   | (604  | )
|                         |  |              |        |   |      |   |       |  
|                         |  | $            | 13,856 |   |      | $ | 4,995 |  
|                         |  |              |        |   |      |   |       |  



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.



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ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS



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, 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. For the year ended December 31, 2002, revenues from four purchasers accounted for 34%, 26% 14% and 14%, respectively, of oil and gas production revenues. Percentages are calculated on oil and
gas revenues before any effects of price risk management activities.



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 2004, comprehensive income was $4.5 million.
In 2003 and 2002, comprehensive loss was $45.4 million and $7.1 million, respectively.



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.



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ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS



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, |      
|                                                                                                                                  |  | 2004                     |       |   | 2003 |   |         | 2002 | 
|Net income (loss) before cumulative effect of change in accounting principle, as reported                                         |  | $                        | 1,356 |   |      | $ | (51,463 | )    |  | $ | (4,700 | )
|Add: Stock based employee compensation expense included in reported net loss, determined under APB 25, net of related tax
effects |  |                          |      |   |      |   | (26     | )    |  |   | 387    |  
|Deduct: Total stock based employee compensation Expense determined under fair value for all awards, net of related tax effects    |  |                          | (51   | ) |      |   | (1,013  | )    |  |   | (2,673 | )
|                                                                                                                                  |  |                          |       |   |      |   |         |      |  |   |        |  
|Pro forma net income (loss) before cumulative effect of change in accounting principle                                            |  | $                        | 1,305 |   |      | $ | (52,502 | )    |  | $ | (6,986 | )
|                                                                                                                                  |  |                          |       |   |      |   |         |      |  |   |        |  
|Earnings (loss) per share:                                                                                                        |  |                          |       |   |      |   |         |      |  |   |        |  
|Basic and diluted  as reported                                                                                                   |  | $                        | 0.05  |   |      | $ | (2.24   | )    |  | $ | (0.23  | )
|Basic and diluted  pro forma                                                                                                     |  | $                        | 0.05  |   |      | $ | (2.29   | )    |  | $ | (0.34  | )



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).



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.



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ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS



Note 3  Recently Issued Accounting Pronouncements



In December 2004, the FASB issued SFAS No. 123R, Share-Based
Payment: an Amendment of FASB Statements No 123 and 95 (SFAS 123R), which requires companies to measure and recognize compensation expense for all stock-based payments at fair value. Stock-based payments include stock option
grants. We grant options to purchase common stock to some our employees and directors under our 2000 plan at prices equal to the market value of the stock on the dates the options were granted. SFAS 123R is effective for all interim or annual
periods beginning after June 15, 2005. Early adoption is encouraged and retroactive application of the provisions of SFAS 123R to the beginning of the fiscal year that includes the effective date is permitted, but not required. We are currently
evaluating the expected impact that the adoption of SFAS 123R will have on our consolidated financial position, results of operations and cash flows and will adopt the provisions in 2005.



Also in December 2004, the FASB issued SFAS No. 153, Exchanges of Nonmonetary Assets, an amendment of Accounting
Principles Board (APB) Opinion No. 29, Accounting for Nonmonetary Transactions (SFAS 153). SFAS 153 redefines the types of nonmonetary exchanges that require fair value measurement. SFAS 153 is effective for nonmonetary transactions
entered into on or after July 1, 2005. We are evaluating the impact of this statement, but adoption of this new accounting standard in 2005 is not expected to have a material impact on our financial condition, results of operations or cash
flows.



The FASB has recently issued Proposed FASB Staff
Position No 19-A, Accounting for Suspended Well Costs(FSP 19-A). If adopted as proposed, FSP 19-A will amend SFAS No. 19, Financial Accounting and Reporting by Oil and Gas Producing Companies (SFAS
19) to provide that in those situations where exploration drilling has been completed and oil and gas reserves have been found, but such reserves cannot be classified as proved when drilling is complete, the drilling costs may be capitalized
if 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. If either of the
criteria is not met, the well is assumed to be impaired and the costs charged to expense. Any well which has not found reserves is charged to expense. Management believes that no adjustment would have been required as of the beginning of and for
each of the three years in the period ended December 31, 2004, from the application of the proposed FSP 19-A.



Note 4  Asset Retirement Obligations



SFAS 143 provides accounting requirements for retirement obligations associated with tangible long-lived assets, including: 1) the timing of liability recognition; 2) initial measurement of the liability; 3)
allocation of asset retirement cost to expense; 4) subsequent measurement of the liability; and 5) financial statement disclosures. SFAS 143 requires that an asset retirement cost should be capitalized as part of the cost of the related long- lived
asset and subsequently allocated to expense using a systematic and rational method. We adopted SFAS 143 on January 1, 2003 and 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.



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ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS



The reconciliation of the beginning and ending asset retirement obligation for the periods ending
December 31, 2004 and 2003 is as follows (in thousands):



|                                                         |  |              |        |   |      |   |         |  
|-------------------------------------------------------- |  | ------------ | ------ | - | ---- | - | ------- | -
|                                                         |  | December 31, |       
|                                                         |  | 2004         |        |   | 2003 |  
|Asset retirement obligation, beginning of period         |  | $            | 21,107 |   |      | $ |        |  
|Liabilities upon adoption of SFAS 143 on January 1, 2003 |  |              |       |   |      |   | 23,135  |  
|Liabilities incurred                                     |  |              | 3,239  |   |      |   | 1,392   |  
|Liabilities settled                                      |  |              | (1,185 | ) |      |   | (12,170 | )
|Accretion expense                                        |  |              | 2,069  |   |      |   | 2,752   |  
|Foreign currency translation                             |  |              | 704    |   |      |   |        |  
|Loss on abandonment                                      |  |              |       |   |      |   | 4,973   |  
|Change in estimate                                       |  |              |       |   |      |   | 1,025   |  
|Liabilities settled  assets sold                        |  |              | (1,011 | ) |      |   |        |  
|                                                         |  |              |        |   |      |   |         |  
|Asset retirement obligation, end of period               |  | $            | 24,923 |   |      | $ | 21,107  |  
|                                                         |  |              |        |   |      |   |         |  



If SFAS 143 had been
applied during the year ended December 31, 2002, on a pro forma basis our reported net loss for such year would have decreased by $0.3 million, or $0.01 per share (basic and diluted).



Note 5  Acquisitions and Dispositions



Gulf of Mexico



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



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.



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ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS



Note 6  Debt



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



|                                                 |  |              |         |   |      |   |        
|------------------------------------------------ |  | ------------ | ------- | - | ---- | - | -------
|                                                 |  | December 31,
|                                                 |  | 2004         |         |   | 2003
|Credit facility                                  |  | $            |        |   |      | $ | 115,409
|Term loan, net of unamortized discount of $8,129 |  |              | 210,309 |   |      |   |       
|                                                 |  |              |         |   |      |   |        
|Total debt                                       |  |              | 210,309 |   |      |   | 115,409
|Less current maturities                          |  |              | (2,200  | ) |      |   |       
|                                                 |  |              |         |   |      |   |        
|Total long-term debt                             |  | $            | 208,109 |   |      | $ | 115,409
|                                                 |  |              |         |   |      |   |        



Term Loan



On March 29, 2004, we entered into a new $185.0 million
term loan (Term Loan) of which $150.0 million is a Senior Secured First Lien Term Loan Facility and $35.0 million is a Senior Secured Second Lien Term Loan Facility. The Term Loan matures in March 2009. 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 and ATP Oil & Gas (U.K.) Limited. We used $116.2 million of the proceeds of the Term Loan to repay
in full our previous credit facility in effect at December 31, 2003. At closing, we received net proceeds of $56.0 million after repaying our previous credit facility, the repurchase of 750,000 warrants associated with the previous credit facility
described below, a 3% original issue discount of $5.6 million and fees associated with the transaction.



As consideration for an amendment and waivers of non-compliance with certain covenants under our previous credit facility, on February 16, 2004 we issued
warrants to the lender to purchase 750,000 shares of our common stock. The warrants were issued with an exercise price of $6.75 per share, had an expiration of February 16, 2009 and were accounted for as additional paid-in-capital. The warrants also
included the right, under certain conditions, for us to repurchase all of the outstanding warrants for $750,000 prior to May 17, 2004, when the warrants became exercisable. On March 29, 2004 these warrants were repurchased for $750,000 and retired
with a decrease to additional paid-in-capital.



The Term Loan
was issued on March 29, 2004 at an average annual interest rate of 10.8%. The $150.0 million term loan bore interest at the base rate plus a margin of 7.5% or LIBOR (with a 2% floor) plus a margin of 8.5% at the election of ATP. The $35.0 million
term loan bore interest at the base rate plus a margin of 9.0% or LIBOR (with a 2% floor) plus a margin of 10.0% at our election.



In connection with the issuance of the Term Loan, we paid fees and expenses of $8.6 million and 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.



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ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS



On September 24, 2004, the Term Loan was amended to effect the following:



| |  |  | increase the first lien term Loan borrowings by $35.0 million;
| | - |  | --------------------------------------------------------------



| |  |  | decrease the margin on any first lien term loan base rate loan from 8.5% to 5.25%;
| | - |  | ----------------------------------------------------------------------------------



| |  |  | decrease the margin on any first lien term loan LIBOR loan from 9.5% to 6.25%;
| | - |  | ------------------------------------------------------------------------------



| |  |  | eliminate the first lien term loan 2.00% floor for LIBOR, and
| | - |  | -------------------------------------------------------------



| |  |  | increase the amount of permitted business investments from $10.0 million to $25.0 million in any fiscal year and allow for restricted payments up to $5.0 million in any fiscal year.
| | - |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



In addition, under the first and second
lien facilities, the lender consented to the repurchase by the borrower of 1,926,837 of the 2,432,336 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 current fair value of the unregistered warrants as of that date. 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.



Net proceeds from the additional borrowing were $18.4 million after the warrant repurchase and fees and expenses of $5.0 million. Of the $5.0 million, $4.9 million paid to the Lender was capitalized and will be amortized over the
remaining life of the loan and $0.1 million of third party legal fees was expensed.



The terms of the Term Loan, as amended September 24, 2004, 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;
| | - |  | -------------------------



| |  |  | Consolidated Net Debt to EBITDAX coverage ratio which is not greater than 3.25/1.0 through June 30, 2004 and 3.0/1.0 at each of the quarters ending thereafter;
| | - |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Consolidated EBITDAX to Interest Expense which is not less than 2.5/1.0 for any four consecutive fiscal quarters commencing with the quarter ended June 30, 2004 and at each of the
quarters ending thereafter;
| | - |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Pre-tax PV10 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 PV10 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;
| | - |  | ------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Net Debt to Proved Developed Oil and Gas Reserves of less than $2.50/Mcfe at December 31, 2004 and at each of the years ending thereafter, and
| | - |  | ----------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | the requirement to maintain hedges on no less than 40% of the next twelve months of forecasted production attributable to our proved producing reserves.
| | - |  | --------------------------------------------------------------------------------------------------------------------------------------------------------



As of December 31, 2004, 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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ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS



Note 7  Equity



Preferred Stock



At December 31, 2004, we had 10,000,000 shares authorized and none issued.



Common Stock



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. On February 14, 2005, our registration statement on Form S-3 relating to the resale of these shares became effective.



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. At December 31, 2003, we had 100,000,000 shares authorized, 24,596,196 shares issued, 24,520,356 shares outstanding and 75,840 shares in treasury.



Warrants



At December 31, 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.



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 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.



The following table is a summary of stock option activity:



|                                                               |  |        |           |      |                              |      |        |  |   |                              |   |        |   |      |                              |   |           |   |  |   |     
|-------------------------------------------------------------- |  | ------ | --------- | ---- | ---------------------------- | ---- | ------ |  | - | ---------------------------- | - | ------ | - | ---- | ---------------------------- | - | --------- | - |  | - | ----
|                                                               |  | 2004   |           | 2003 |                              | 2002
|                                                               |  | Shares |           |      | WeightedAverageExercisePrice |      | Shares |  |   | WeightedAverageExercisePrice |   | Shares |   |      | WeightedAverageExercisePrice
|Outstanding at beginning of year                               |  |        | 1,425,244 |      |                              | $    | 8.96   |  |   | 1,685,147                    |   |        | $ | 8.29 |                              |   | 1,637,809 |   |  | $ | 8.52
|Granted                                                        |  |        | 24,000    |      |                              |      | 13.22  |  |   | 50,929                       |   |        |   | 4.53 |                              |   | 86,500    |   |  |   | 3.43
|Exercised                                                      |  |        | (363,505  | )    |                              |      | 7.36   |  |   | (198,189                     | ) |        |   | 1.79 |                              |   | (9,519    | ) |  |   | 1.43
|Forfeited                                                      |  |        | (66,000   | )    |                              |      | 9.53   |  |   | (112,643                     | ) |        |   | 9.63 |                              |   | (29,643   | ) |  |   | 9.09
|                                                               |  |        |           |      |                              |      |        |  |   |                              |   |        |   |      |                              |   |           |   |  |   |     
|Outstanding at end of year                                     |  |        | 1,019,739 |      |                              | $    | 9.59   |  |   | 1,425,244                    |   |        | $ | 8.96 |                              |   | 1,685,147 |   |  | $ | 8.29
|                                                               |  |        |           |      |                              |      |        |  |   |                              |   |        |   |      |                              |   |           |   |  |   |     
|Exercisable at end of year                                     |  |        | 734,864   |      |                              | $    | 9.28   |  |   | 805,244                      |   |        | $ | 8.05 |                              |   | 563,344   |   |  | $ | 6.76
|                                                               |  |        |           |      |                              |      |        |  |   |                              |   |        |   |      |                              |   |           |   |  |   |     
|Weighted average fair value of options granted during the year |  | $      | 4.84      |      |                              |      |        |  | $ | 2.63                         |   |        |   |      |                              | $ | 1.74      |   |  |   |     



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##### Table of Contents

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS



The following table summarizes information about all stock options outstanding at December 31, 2004:



|                         |  |                     |  |                                         |  |                              |       |                   |         |                              |   |      
|------------------------ |  | ------------------- |  | --------------------------------------- |  | ---------------------------- | ----- | ----------------- | ------- | ---------------------------- | - | -----
|                         |  | Options Outstanding |  | Options Exercisable                    
|Range of Exercise Prices |  | NumberOutstanding   |  | WeightedAverageRemainingContractualLife |  | WeightedAverageExercisePrice |       | NumberExercisable |         | WeightedAverageExercisePrice
|$ 1.40 - $ 3.85          |  | 230,239             |  | 1.5 Years                               |  | $                            | 3.64  |                   | 201,489 |                              | $ | 3.66 
|$ 5.73 - $ 6.40          |  | 34,000              |  | 4.0 Years                               |  |                              | 6.28  |                   | 6,000   |                              |   | 6.24 
|$11.24 - $12.17          |  | 722,500             |  | 1.9 Years                               |  |                              | 11.36 |                   | 507,375 |                              |   | 11.37
|$14.00 - $18.54          |  | 33,000              |  | 2.6 Years                               |  |                              | 15.79 |                   | 20,000  |                              |   | 14.00
|                         |  |                     |  |                                         |  |                              |       |                   |         |                              |   |      
|$ 1.40 - $18.54          |  | 1,019,739           |  | 1.9 Years                               |  | $                            | 9.59  |                   | 734,864 |                              | $ | 9.28 
|                         |  |                     |  |                                         |  |                              |       |                   |         |                              |   |      



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 2004, 2003 and 2002, 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 2004, 2003 and 2002 were estimated at the date of grant using a Black-Scholes option-pricing model
with the following weighted average assumptions for grants in 2004, 2003 and 2002: stock price volatility of 59.1% 83.9% and 92.8%, respectively; risk free interest rate of 2.6%, 1.9% and 2.8%, respectively; zero dividend yield; and an expected life
2.5 years.



Non-Cash Compensation Expense. In 2002, we
recorded a non-cash charge to compensation expense of approximately $0.6 million for options granted since September 1999 through the date of our initial public offering on February 5, 2001 (the measurement date). The total expected
expense as of the measurement date was recognized in the periods in which the option vested. Each option was divided into three equal portions corresponding to the three vesting dates (April 10, 2001, February 9, 2002, and February 9, 2003), with
the related compensation cost for each portion amortized straight-line over the period to the vesting date.



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 $157,000, $106,000 and $97,000, for the
years ended December 31, 2004, 2003 and 2002, 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, 2004, 2003 and
2002, we contributed approximately $20,200, $21,300 and $15,500, respectively.



Note 9  Earnings Per Share



Basic
earnings per share is computed by dividing net income or loss available to common shareholders by the weighted average number of common shares outstanding during the period. Diluted earnings per share is determined on the assumption that outstanding
stock options have been converted using the average price for the period. For purposes of computing earnings per share in a loss year, potential common shares have been excluded from the computation of weighted average common shares outstanding
because their effect is antidilutive.



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##### Table of Contents

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS



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



|                                                       |  |                          |        |      |   |         |      |  |   |        |  
|------------------------------------------------------ |  | ------------------------ | ------ | ---- | - | ------- | ---- |  | - | ------ | -
|                                                       |  | Years Ended December 31, |       
|                                                       |  | 2004                     |        | 2003 |   |         | 2002 | 
|Net income (loss) available to common shareholders     |  | $                        | 1,356  |      | $ | (50,801 | )    |  | $ | (4,700 | )
|                                                       |  |                          |        |      |   |         |      |  |   |        |  
|Weighted average shares outstanding  basic            |  |                          | 24,944 |      |   | 22,975  |      |  |   | 20,315 |  
|Effect of dilutive securities  stock options          |  |                          | 231    |      |   |        |      |  |   |       |  
|Effect of dilutive securities  warrants               |  |                          | 96     |      |   |        |      |  |   |       |  
|                                                       |  |                          |        |      |   |         |      |  |   |        |  
|Weighted average shares outstanding  diluted          |  |                          | 25,271 |      |   | 22,975  |      |  |   | 20,315 |  
|                                                       |  |                          |        |      |   |         |      |  |   |        |  
|Net income (loss) per common share  basic and diluted |  | $                        | 0.05   |      | $ | (2.21   | )    |  | $ | (0.23  | )
|                                                       |  |                          |        |      |   |         |      |  |   |        |  



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,
|                                                                                              |  | 2004                     |        |   | 2003 |   |         | 2002
|Current:                                                                                      |  |                          |        |   |      |   |         |      |  |   |      
|Federal                                                                                       |  | $                        | (29    | ) |      | $ |        |      |  | $ | 229  
|Foreign                                                                                       |  |                          | (29    | ) |      |   |        |      |  |   |     
|                                                                                              |  |                          |        |   |      |   |         |      |  |   |      
|                                                                                              |  |                          | (58    | ) |      |   |        |      |  |   | 229  
|                                                                                              |  |                          |        |   |      |   |         |      |  |   |      
|Deferred:                                                                                     |  |                          |        |   |      |   |         |      |  |   |      
|Federal                                                                                       |  |                          | (4,561 | ) |      |   | 9,594   |      |  |   | 2,352
|Foreign                                                                                       |  |                          | 1,568  |   |      |   | 2,828   |      |  |   |     
|                                                                                              |  |                          |        |   |      |   |         |      |  |   |      
|                                                                                              |  |                          | (2,993 | ) |      |   | 12,422  |      |  |   | 2,352
|                                                                                              |  |                          |        |   |      |   |         |      |  |   |      
|Valuation allowance                                                                           |  |                          | 2,993  |   |      |   | (33,646 | )    |  |   |     
|                                                                                              |  |                          |        |   |      |   |         |      |  |   |      
|(Expense) benefit for income taxes before cumulative effect of change in accounting principle |  | $                        | (58    | ) |      | $ | (21,224 | )    |  | $ | 2,581
|                                                                                              |  |                          |        |   |      |   |         |      |  |   |      



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, |       
|         |  | 2004                     |        |   | 2003 |   |         | 2002 | 
|Domestic |  | $                        | 6,027  |   |      | $ | (26,320 | )    |  | $ | (4,889 | )
|Foreign  |  |                          | (4,613 | ) |      |   | (3,919  | )    |  |   | (2,392 | )
|         |  |                          |        |   |      |   |         |      |  |   |        |  
|         |  | $                        | 1,414  |   |      | $ | (30,239 | )    |  | $ | (7,281 | )
|         |  |                          |        |   |      |   |         |      |  |   |        |  



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, |  
|                                  |  | 2004                     |   |  | 2003   |    |  | 2002   |   
|Statutory federal income tax rate |  | 35.00                    | % |  | (35.00 | )% |  | (35.00 | )%
|Nondeductible and other           |  | (3.45                    | ) |  | 0.02   |    |  | (0.39  | ) 
|Foreign operations                |  | 12.92                    |   |  | (6.08  | )  |  |       |   
|Valuation allowance               |  | (40.37                   | ) |  | 111.27 |    |  |       |   
|                                  |  |                          |   |  |        |    |  |        |   
|                                  |  | 4.10                     | % |  | 70.21  | %  |  | (35.39 | )%
|                                  |  |                          |   |  |        |    |  |        |   



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ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS



Significant components of our deferred tax assets (liabilities) as of December 31, 2004 and 2003 are
as follows (in thousands):



|                                     |  |              |         |   |      |   |         |  
|------------------------------------ |  | ------------ | ------- | - | ---- | - | ------- | -
|                                     |  | December 31, |        
|                                     |  | 2004         |         |   | 2003 |  
|Deferred tax assets:                 |  |              |         |   |      |   |         |  
|Net operating loss carryforwards     |  | $            | 36,633  |   |      | $ | 30,564  |  
|AMT credit                           |  |              | 29      |   |      |   |        |  
|Unrealized book losses               |  |              |        |   |      |   | 2,468   |  
|Stock based compensation expense     |  |              | 661     |   |      |   | 1,121   |  
|Foreign equity in subsidiary         |  |              |        |   |      |   | 2,503   |  
|Foreign operations                   |  |              | 16,372  |   |      |   | 14,225  |  
|Other                                |  |              | 732     |   |      |   | 831     |  
|                                     |  |              |         |   |      |   |         |  
|Total gross deferred tax assets      |  |              | 54,427  |   |      |   | 51,712  |  
|Less valuation allowance             |  |              | (30,958 | ) |      |   | (33,646 | )
|                                     |  |              |         |   |      |   |         |  
|Net deferred tax asset               |  |              | 23,469  |   |      |   | 18,066  |  
|                                     |  |              |         |   |      |   |         |  
|                                     |  |             
|Deferred tax liabilities:            |  |              |         |   |      |   |         |  
|Fixed asset basis differences        |  |              | (10,068 | ) |      |   | (2,812  | )
|Asset retirement obligations         |  |              | (1,505  | ) |      |   | (3,857  | )
|Foreign operations                   |  |              | (11,896 | ) |      |   | (11,397 | )
|                                     |  |              |         |   |      |   |         |  
|Total gross deferred tax liabilities |  |              | (23,469 | ) |      |   | (18,066 | )
|                                     |  |              |         |   |      |   |         |  
|Net deferred tax asset               |  | $            |        |   |      | $ |        |  
|                                     |  |              |         |   |      |   |         |  



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.



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 shareholders 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.



At December 31, 2004, 2003 and 2002, we had net operating loss carryforwards
(NOLs) for federal income tax purposes of approximately $104.7 million, $87.3 million, and $55.9 million respectively, which are available to offset future federal taxable income through 2024.



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##### Table of Contents

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS



Note 11  Commitments and Contingencies



Operating Leases



We have commitments under an operating lease agreement for office space. Total rent expense for the years ended December 31, 2004, 2003 and 2002 was
approximately $0.7 million, $0.6 million and $0.5 million respectively. At December 31, 2004, the future minimum rental payments due under the lease are as follows (in thousands):



|           |  |   |      
|---------- |  | - | -----
|2005       |  | $ | 640  
|2006       |  |   | 621  
|2007       |  |   | 606  
|2008       |  |   | 584  
|2009       |  |   | 583  
|Thereafter |  |   | 1,083
|           |  |   |      
|Total      |  | $ | 4,117
|           |  |   |      



Contingencies



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.



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, 2004 and 2003, the U.S recorded balance is reflected as a long-term liability of $10.2 million and $9.2 million, respectively, in the
financial statements.



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.



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ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS



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, 2004, Accumulated Other Comprehensive Income included $0.5 million of unrealized gains on our cash flow hedges. Gains and losses are
reclassified from Accumulated Other Comprehensive Income to the consolidated statement of operations as a component of oil and gas revenues in the period the hedged production occurs. If any ineffectiveness occurs, amounts are recorded directly to
the consolidated statement of operations as a component of oil and gas revenues. All of this deferred 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,
2004, 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 ValueAsset (Liability) |  
|               |  |        |  |      |  | (MMBtu) |  | ($ per MMBtu) |  | ($ in thousands) | 
|Gulf of Mexico |  | 2005   |  | Swap |  | 600,000 |  | 5.62          |  |                 |  | (316                            | )
|Gulf of Mexico |  | 2005   |  | Put  |  | 856,000 |  |              |  | 5.01             |  | 172                             |  
|North Sea      |  | 2005   |  | Swap |  | 270,000 |  | 8.03          |  |                 |  | 619                             |  



During the third
quarter of 2004, we entered into a cash flow hedge of our U.K. production at a price of £0.446 per therm. The net fair value asset has been translated at the December 31, 2004 translation rate of $1.9266 to £1.0. In January 2005, we
entered into additional hedges in the form of fixed forward sales of our gas production in the Gulf of Mexico. As a result of the new hedges, the swap used to hedge production in the North Sea was liquidated.



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.



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##### Table of Contents

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS



At December 31, 2004, we had fixed-price contracts in place for the following oil and gas volumes:



|                     |  |           |  |                      
|-------------------- |  | --------- |  | ---------------------
|Period               |  | Volumes   |  | AverageFixedPrice (1)
|Natural gas (MMBtu): |  |           |  |                      
|2005                 |  | 4,820,000 |  | 5.53                 
|Oil (Bbl):           |  |           |  |                      
|2005                 |  | 382,750   |  | 39.64                

---

|(1) | Includes the effect of basis differentials.
|--- | -------------------------------------------



Thus far, in 2005 we have entered into the following fixed-price contracts:



|                     |  |           |  |                      
|-------------------- |  | --------- |  | ---------------------
|Period               |  | Volumes   |  | AverageFixedPrice (1)
|Natural gas (MMBtu): |  |           |  |                      
|2005                 |  | 4,064,000 |  | 6.89                 
|2006                 |  | 1,710,000 |  | 7.40                 
|Oil (Bbl):           |  |           |  |                      
|2005                 |  | 55,000    |  | 50.45                
|2006                 |  | 300,500   |  | 47.96                

---

|(1) | Includes the effect of basis differentials.
|--- | -------------------------------------------



Also in 2005, we entered into a cash flow hedge of our U.K. production at a
price of £0.56 per therm.



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. The amount of gas to be purchased was 9,000 MMBtu per day for the first year and 5,000 MMBtu per day for years
two through ten. The contract requires 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 is required to reimburse ATP Energy on a monthly basis
for a portion of this premium during the term of the contract. This portion of the reimbursement is accomplished by a note receivable in favor of ATP. The note receivable bears interest at 6% and has monthly payments of approximately $0.4 million
until January 2009. The balance of the note receivable at December 31, 2004 and 2003 was $16.4 million and $19.8 million, respectively. At December 31, 2004 and 2003, the present value of the remaining premium payments to be made by ATP Energy,
using a discount rate of 6%, was $16.0 million and $19.5 million, respectively. 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 to be paid by ATP Energy over the term of the contract is approximately $49.0 million and the aggregate
amount of payments to be paid to ATP Energy over the term of the note is approximately $45.0 million. At December 31, 2004 the remaining premium to be paid was $18.17 million, which will be reimbursed by the monthly reimbursement from American
Citigas and the remaining deferred obligation discussed below. The terms provide for the immediate termination of the agreement upon non-performance by American Citigas. ATP Energy sells to a third party an identical quantity of natural gas at the
Gas Daily Henry Hub index price less $0.015. This contract is on a month-to-month basis.



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ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS



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 is a non-refundable fee received by ATP Energy and is recognized into income as earned over the life of the contract. At
December 31, 2004 and 2003, the deferred revenue amount was $0.7 million and $0.9 million, respectively. The deferred obligation amount of $4.0 million represented the difference between the premium we agreed to pay for natural gas under the
American Citigas contract and the obligation of American Citigas to partially reimburse us for such premium. Any deferred obligation amount not utilized is refundable if the contract is terminated. The transaction is structured with American Citigas
such that there is no financial impact to ATP Energy associated with the premium paid and reimbursement received other than the $2.0 million realized by ATP Energy. The premium we pay to American Citigas will be approximately the same as the
reimbursement obligation for the remainder of the contract. 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.



Note 14  Segment Information



We follow SFAS No. 131, Disclosures About Segments of an Enterprise
and Related Information, which requires that companies disclose segment data based on how management makes decisions about allocating resources to segments and measuring their performance. We manage our business and identify our segments
based on geographic areas. We have two reportable segments: our operations in the Gulf of Mexico and our operations in the North Sea. Both of these segments involve oil and gas producing activities. Certain financial information regarding our
segments for 2004, 2003 and 2002 is as follows (in thousands):



|                                         |  |               |         |   |          |   |        |       |  |   |         |  
|---------------------------------------- |  | ------------- | ------- | - | -------- | - | ------ | ----- |  | - | ------- | -
|                                         |  | Gulf ofMexico |         |   | NorthSea |   |        | Total | 
|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 |  
|2002                                     |  |               |         |   |          |   |        |       |  |   |         |  
|Revenues                                 |  | $             | 80,017  |   |          | $ |       |       |  | $ | 80,017  |  
|Depreciation, depletion and amortization |  |               | 43,292  |   |          |   | 98     |       |  |   | 43,390  |  
|Impairment of oil and gas properties     |  |               | 6,844   |   |          |   |       |       |  |   | 6,844   |  
|Income (loss) from operations            |  |               | 4,409   |   |          |   | (2,426 | )     |  |   | 1,983   |  
|Additions to oil and gas properties      |  |               | 18,520  |   |          |   | 16,353 |       |  |   | 34,873  |  
|Total assets                             |  |               | 144,069 |   |          |   | 37,986 |       |  |   | 182,055 |  



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##### Table of Contents

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS



Note 15  Summarized Quarterly Financial Data (Unaudited)



(In Thousands, Except Per Share Amounts)



|                                    |  |              |        |   |               |   |              |  |   |               |   |  |   |         |    
|----------------------------------- |  | ------------ | ------ | - | ------------- | - | ------------ |  | - | ------------- | - |  | - | ------- | ---
|                                    |  | FirstQuarter |        |   | SecondQuarter |   | ThirdQuarter |  |   | FourthQuarter |  
|2004                                |  |              |        |   |               |   |              |  |   |               |   |  |   |         |    
|Revenues                            |  | $            | 24,011 |   |               | $ | 32,879       |  | $ | 26,306        |   |  | $ | 32,927  |    
|Costs and expenses                  |  |              | 19,353 |   |               |   | 20,231       |  |   | 19,689        |   |  |   | 30,755  |    
|Income (loss) from operations       |  |              | 4,658  |   |               |   | 12,648       |  |   | 6,617         |   |  |   | 2,172   |    
|Net income (loss)                   |  |              | (2,393 | ) |               |   | 6,926        |  |   | 597           |   |  |   | (3,774  | )  
|Net income (loss) per common share: |  |              |        |   |               |   |              |  |   |               |   |  |   |         |    
|Basic and diluted(1)                |  | $            | (0.10  | ) |               | $ | 0.28         |  | $ | 0.02          |   |  | $ | (0.14   | )  
|2003                                |  |              |        |   |               |   |              |  |   |               |   |  |   |         |    
|Revenues                            |  | $            | 20,441 |   |               | $ | 18,540       |  | $ | 17,179        |   |  | $ | 13,991  |    
|Costs and expenses                  |  |              | 15,445 |   |               |   | 16,667       |  |   | 27,775        |   |  |   | 29,769  | (2)
|Income (loss) from operations       |  |              | 4,996  |   |               |   | 1,873        |  |   | (10,596       | ) |  |   | (15,778 | )  
|Net income (loss)                   |  |              | 2,398  |   |               |   | 431          |  |   | (14,994       | ) |  |   | (38,636 | )  
|Net income (loss) per common share: |  |              |        |   |               |   |              |  |   |               |   |  |   |         |    
|Basic and diluted(1)                |  | $            | 0.12   |   |               | $ | 0.02         |  | $ | (0.61         | ) |  | $ | (1.58   | )  

---

|(1) | 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.
|--- | -------------------------------------------------------------------------------------------------------------------------------------------



|(2) | Includes impairment charges of $10.6 million during the third quarter for two properties and
$1.0 million during the fourth quarter for four properties (See Note 2).
|--- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------



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ATP OIL & GAS CORPORATION

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, 2004, 2003 and 2002.



|                            |  |                |        |   |           |   |        |  |   |         |  
|--------------------------- |  | -------------- | ------ | - | --------- | - | ------ |  | - | ------- | -
|                            |  | Gulf of Mexico |        |   | North Sea |   | Total  | 
|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: |  |                |        |   |           |   |        |  |   |         |  
|Unproved                    |  | $              | 769    |   |           | $ |       |  | $ | 769     |  
|Proved                      |  |                | 1,163  |   |           |   |       |  |   | 1,163   |  
|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 |  
|                            |  |                |        |   |           |   |        |  |   |         |  
|2002                        |  |                |        |   |           |   |        |  |   |         |  
|Property acquisition costs: |  |                |        |   |           |   |        |  |   |         |  
|Unproved                    |  | $              | 959    |   |           | $ |       |  | $ | 959     |  
|Development costs           |  |                | 17,561 |   |           |   | 16,353 |  |   | 33,914  |  
|                            |  |                |        |   |           |   |        |  |   |         |  
|                            |  | $              | 18,520 |   |           | $ | 16,353 |  | $ | 34,873  |  
|                            |  |                |        |   |           |   |        |  |   |         |  

---

|(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.



Gulf of Mexico 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. for all years
presented. Ryder Scott Company, L.P. also prepared such information for our 2004 and 2003 reserves in the Dutch Sector  North Sea. 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 Troy Ikoda Limited for all years presented.



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ATP OIL & GAS CORPORATION

SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES



The following table sets forth our net proved oil and gas reserves at December 31, 2001, 2002, 2003
and 2004 and the changes in net proved oil and gas reserves for the years ended December 31, 2002, 2003 and 2004:



|                                |  |                    |   |  |                                                 |   |  |         |   |  |                |   |  |           |  |        |  
|------------------------------- |  | ------------------ | - |  | ----------------------------------------------- | - |  | ------- | - |  | -------------- | - |  | --------- |  | ------ | -
|                                |  | 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, 2001               |  | 113,880            |   |  | 80,629                                          |   |  | 194,509 |   |  | 6,753          |   |  |          |  | 6,753  |  
|Revisions of previous estimates |  | 1,594              |   |  | 9,314                                           |   |  | 10,908  |   |  | 441            |   |  |          |  | 441    |  
|Purchase of properties          |  | 4,696              |   |  | 20,272                                          |   |  | 24,968  |   |  |               |   |  |          |  |       |  
|Disposition of properties       |  |                   |   |  | (17,115                                         | ) |  | (17,115 | ) |  |               |   |  |          |  |       |  
|Production                      |  | (17,732            | ) |  |                                                |   |  | (17,732 | ) |  | (1,454         | ) |  |          |  | (1,454 | )
|                                |  |                    |   |  |                                                 |   |  |         |   |  |                |   |  |           |  |        |  
|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 properties          |  | 51,527             |   |  | 6,292                                           |   |  | 57,819  |   |  | 7,609          |   |  | 2         |  | 7,611  |  
|Disposition of properties       |  | (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      |  
|Disposition of properties       |  | (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 |  
|                                |  |                    |   |  |                                                 |   |  |         |   |  |                |   |  |           |  |        |  



|                             |  |                    |  |                            |  |        |  |                |  |           |  |      
|---------------------------- |  | ------------------ |  | -------------------------- |  | ------ |  | -------------- |  | --------- |  | -----
|                             |  | 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, 2001            |  | 56,704             |  |                           |  | 56,704 |  | 3,115          |  |          |  | 3,115
|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



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 | 
|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   |  
|                                                         |  |                |           |   |           |   |          |       |  |   |           |  



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##### Table of Contents

ATP OIL & GAS CORPORATION

SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES



|                                                         |  |                |           |   |           |   |          |       |  |   |           |  
|-------------------------------------------------------- |  | -------------- | --------- | - | --------- | - | -------- | ----- |  | - | --------- | -
|                                                         |  | 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   |  
|                                                         |  |                |           |   |           |   |          |       |  |   |           |  
|                                                         |  |                |          
|2002                                                     |  |                |           |   |           |   |          |       |  |   |           |  
|Future cash inflows                                      |  | $              | 649,927   |   |           | $ | 205,629  |       |  | $ | 855,556   |  
|Future operating expenses                                |  |                | (69,215   | ) |           |   | (78,131  | )     |  |   | (147,346  | )
|Future development costs                                 |  |                | (128,803  | ) |           |   | (109,510 | )     |  |   | (238,313  | )
|                                                         |  |                |           |   |           |   |          |       |  |   |           |  
|Future net cash flows                                    |  |                | 451,909   |   |           |   | 17,988   |       |  |   | 469,897   |  
|Future income taxes                                      |  |                | (129,435  | ) |           |   | (929     | )     |  |   | (130,364  | )
|                                                         |  |                |           |   |           |   |          |       |  |   |           |  
|Future net cash flows, after income taxes                |  |                | 322,474   |   |           |   | 17,059   |       |  |   | 339,533   |  
|10% annual discount per annum                            |  |                | (74,770   | ) |           |   | (5,870   | )     |  |   | (80,640   | )
|                                                         |  |                |           |   |           |   |          |       |  |   |           |  
|Standardized measure of discounted future net cash flows |  | $              | 247,704   |   |           | $ | 11,189   |       |  | $ | 258,893   |  
|                                                         |  |                |           |   |           |   |          |       |  |   |           |  



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 PV-10 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, 2002 |  | $              | 4.740 |                       | $ | 2.200                  |  | $              |      |                       | $ | 31.23                  |  | $ |  |  | $ |     
|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



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##### Table of Contents

ATP OIL & GAS CORPORATION

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 | 
|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  |  
|                                              |  |                |         |   |           |   |         |       |  |   |          |  
|                                              |  |                |        
|2002                                          |  |                |         |   |           |   |         |       |  |   |          |  
|Beginning of year                             |  | $              | 172,916 |   |           | $ | 39,748  |       |  | $ | 212,664  |  
|                                              |  |                |         |   |           |   |         |       |  |   |          |  
|Sales of oil and gas, net of production costs |  |                | (72,658 | ) |           |   |        |       |  |   | (72,658  | )
|Net changes in income taxes                   |  |                | (68,837 | ) |           |   | 24,007  |       |  |   | (44,830  | )
|Net changes in price and production costs     |  |                | 192,111 |   |           |   | (30,166 | )     |  |   | 161,945  |  
|Revisions of quantity estimates               |  |                | 13,666  |   |           |   | 10,893  |       |  |   | 24,559   |  
|Accretion of discount                         |  |                | 20,001  |   |           |   | 6,427   |       |  |   | 26,428   |  
|Development costs incurred                    |  |                | 13,163  |   |           |   | 14,413  |       |  |   | 27,576   |  
|Changes in estimated future development costs |  |                | (23,508 | ) |           |   | (10,670 | )     |  |   | (34,178  | )
|Purchases of minerals-in-place                |  |                | 8,252   |   |           |   | 662     |       |  |   | 8,914    |  
|Sales of minerals-in-place                    |  |                |        |   |           |   | (13,664 | )     |  |   | (13,664  | )
|Changes in production rates, timing and other |  |                | (7,402  | ) |           |   | (30,461 | )     |  |   | (37,863  | )
|                                              |  |                |         |   |           |   |         |       |  |   |          |  
|                                              |  |                | 74,788  |   |           |   | (28,559 | )     |  |   | 46,229   |  
|                                              |  |                |         |   |           |   |         |       |  |   |          |  
|End of year                                   |  | $              | 247,704 |   |           | $ | 11,189  |       |  | $ | 258,893  |  
|                                              |  |                |         |   |           |   |         |       |  |   |          |  



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##### Table of Contents

ATP OIL & GAS CORPORATION

SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES



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



Capitalized
Costs Related to Oil and Gas Producing Activities



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



|                                                   |  |                |          |   |           |   |         |       |  |   |          |  
|-------------------------------------------------- |  | -------------- | -------- | - | --------- | - | ------- | ----- |  | - | -------- | -
|                                                   |  | Gulf of Mexico |          |   | North Sea |   |         | Total | 
|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  |  
|                                                   |  |                |          |   |           |   |         |       |  |   |          |  
|2003                                               |  |                |          |   |           |   |         |       |  |   |          |  
|Oil and gas properties:                            |  |                |          |   |           |   |         |       |  |   |          |  
|Unproved                                           |  | $              | 1,727    |   |           | $ |        |       |  | $ | 1,727    |  
|Proved                                             |  |                | 401,027  |   |           |   | 48,104  |       |  |   | 449,131  |  
|Accumulated depletion, impairment and amortization |  |                | (261,733 | ) |           |   |        |       |  |   | (261,733 | )
|                                                   |  |                |          |   |           |   |         |       |  |   |          |  
|                                                   |  | $              | 141,021  |   |           | $ | 48,104  |       |  | $ | 189,125  |  
|                                                   |  |                |          |   |           |   |         |       |  |   |          |  



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 | 
|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  |  
|                                                                                                 |  |                |         |   |           |   |         |       |  |   |         |  
|                                                                                                 |  |                |        
|2002                                                                                             |  |                |         |   |           |   |         |       |  |   |         |  
|Revenues from oil and gas producing activities                                                   |  | $              | 88,151  |   |           | $ |        |       |  | $ | 88,151  |  
|Production costs and other                                                                       |  |                | (16,764 | ) |           |   | (154    | )     |  |   | (16,918 | )
|Depreciation, depletion and amortization                                                         |  |                | (43,292 | ) |           |   | (98     | )     |  |   | (43,390 | )
|Impairment of oil and gas properties                                                             |  |                | (6,844  | ) |           |   |        |       |  |   | (6,844  | )
|Income tax (expense) benefit                                                                     |  |                | (7,438  | ) |           |   | 73      |       |  |   | (7,365  | )
|                                                                                                 |  |                |         |   |           |   |         |       |  |   |         |  
|Results of operations from producing activities (excluding corporate overhead and interest costs |  | $              | 13,813  |   |           | $ | (179    | )     |  | $ | 13,634  |  
|                                                                                                 |  |                |         |   |           |   |         |       |  |   |         |  



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##### Table of Contents

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

SCHEDULE IIVALUATION AND QUALIFYING ACCOUNTS

FOR EACH OF THE THREE YEARS ENDED DECEMBER 31, 2004

(In Thousands)



|                                           |  |                              |        |                             |   |        |                         |  |   |            |   |                        |   |   |  |   |       
|------------------------------------------ |  | ---------------------------- | ------ | --------------------------- | - | ------ | ----------------------- |  | - | ---------- | - | ---------------------- | - | - |  | - | ------
|Description                                |  | Balance atBeginningof Period |        | Charged toCosts andExpenses |   |        | Charged toOtherAccounts |  |   | Deductions |   | Balanceat Endof Period
|2004                                       |  |                              |        |                             |   |        |                         |  |   |            |   |                        |   |   |  |   |       
|Allowance for doubtful accounts            |  | $                            | 1,266  |                             | $ | 279    |                         |  | $ | (46        | ) |                        | $ |  |  | $ | 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
|                                           |  |                              |        |                             |  
|2002                                       |  |                              |        |                             |   |        |                         |  |   |            |   |                        |   |   |  |   |       
|Allowance for doubtful accounts            |  | $                            | 1,423  |                             | $ | (86    | )                       |  | $ | (71        | ) |                        | $ |  |  | $ | 1,266 





S-1