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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, 2003



Commission file number: 000-32261



OR



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



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 ̈No þ



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



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



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ATP OIL & GAS CORPORATION AND SUBSIDIARIES

2003 FORM 10-K ANNUAL REPORT

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                                   |  | 25  
|         |  |                                                                                      
|Part II  |  |                                                                                       |  | 26  
|         |  |                                                                                      
|Item 5.  |  | Market for Registrants Common Units and Related Security Holder Matters               |  | 26  
|         |  |                                                                                      
|Item 6.  |  | Selected Financial Data                                                               |  | 27  
|         |  |                                                                                      
|Item 7.  |  | Managements Discussion and Analysis of Financial Condition and Results of Operations |  | 29  
|         |  |                                                                                      
|Item 7a. |  | Quantitative and Qualitative Disclosures about Market Risk                            |  | 43  
|         |  |                                                                                      
|Item 8.  |  | Financial Statements and Supplementary Data                                           |  | 44  
|         |  |                                                                                      
|Item 9.  |  | Disagreements on Accounting and Financial Disclosure                                  |  | 44  
|         |  |                                                                                      
|Item 9a. |  | Controls and Procedures                                                               |  | 44  
|         |  |                                                                                      
|Part III |  |                                                                                       |  | 45  
|         |  |                                                                                      
|Item 10. |  | Directors and Executive Officers of Registrant                                        |  | 45  
|         |  |                                                                                      
|Item 11. |  | Executive Compensation                                                                |  | 45  
|         |  |                                                                                      
|Item 12. |  | Security Ownership of Certain Beneficial Owners and Management                        |  | 45  
|         |  |                                                                                      
|Item 13. |  | Certain Relationships and Related Transactions                                        |  | 45  
|         |  |                                                                                      
|Item 14. |  | Principal Accountant Fees and Services                                                |  | 45  
|         |  |                                                                                      
|Part IV  |  |                                                                                       |  | 46  
|         |  |                                                                                      
|Item 15. |  | Exhibits, Financial Statement Schedules and Reports on Form 8-K                       |  | 46  



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Cautionary Statement About Forward-Looking Statements



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



This annual report on Form 10-K includes assumptions, expectations, projections, intentions or beliefs about future events. These statements are intended
as forward-looking statements under the Private Securities Litigation Reform Act of 1995. We caution that assumptions, expectations, projections, intentions and beliefs about future events may and often do vary from actual results and
the differences can be material.



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



| |  | 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 natural gas and oil 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 natural gas and oil.
| | - | ------------------------------------------------------------------------------------------------------------------------------------------------



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 timing and extent of changes in natural gas and oil 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
|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 natural gas or oil reserves that is not a development well.



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



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



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



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



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



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



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



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



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



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



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



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PART I



|Item 1. | Business
|------- | --------



General



ATP Oil & Gas Corporation was incorporated in Texas in 1991. We are engaged in the acquisition, development and production of natural gas and oil properties in the Gulf of Mexico and the North Sea. We primarily
focus our efforts on natural gas and oil properties with proved undeveloped reserves that are economically attractive to us but are not strategic to major or exploration-oriented independent oil and gas companies. Our strategy provides assets for us
to develop and produce without the risk, cost or time of exploration. Our management team has extensive engineering, geological, geophysical, technical and operational expertise in successfully developing and operating properties in both our current
and planned areas of operation.



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



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



At December 31, 2003, we had leasehold and other interests in 50 offshore blocks, 26 platforms and 62 wells, including six subsea wells, in the Gulf of
Mexico. We operate 50 of these 62 wells, including all of the subsea wells, and 85% of our offshore platforms. We also had interests in seven blocks and one company-operated subsea well in the U.K. Sector  North Sea. Our average working
interest in our properties at December 31, 2003 was approximately 82%. For more information regarding our operations and assets in the Gulf of Mexico and North Sea, see Note 15, Segment Information, to the Notes to Consolidated Financial
Statements.



Our Business Strategy



Our business strategy is to enhance shareholder value primarily through the
acquisition, development and production of proved natural gas and oil reserves in areas that have:



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



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



| |  | 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 natural gas and oil development and production.
| | - | -----------------------------------------------------------------------------------------------------------------------------------------



We believe our strategy significantly reduces the risks associated with
traditional natural gas and oil exploration. Our focus is to acquire properties that have been explored by others and found to contain proved reserves. From the inception of operations through March 30, 2004, we have successfully brought to
production 35 out of 36 projects with proved undeveloped reserves on properties that were not producing, a 97% success ratio.



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



By focusing on properties that are not strategic to other companies and
properties that are primarily proved but as yet undeveloped, we are able to minimize up front acquisition costs and concentrate available capital on the development phase of these properties. Since our inception in 1991 through December 31, 2003, we
have added 483.1 Bcfe of proved natural gas and oil reserves through acquisitions at a total cost of $77.5 million or $0.16 per Mcfe. Development costs for this same period were approximately $366.5 million.



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



Our Strengths



| |  | 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. For the three-year period ended December 31, 2003, our total average finding and development costs (which do not include future development costs) incurred in the acquisition and
development of our net proved reserves was $0.93 per Mcfe. Finding and development cost per Mcfe is calculated by dividing the net reserve change for the period (excluding production) into the costs incurred for the period, as reported in the
Costs Incurred disclosure required by Statement of Financial Accounting Standard (SFAS) No. 69, Disclosures about Oil and Gas Producing Activities (SFAS 69).
| | - | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  | Technical Expertise and Significant Experience. We have assembled a technical staff with an average of over 20 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, 2003, we operated 85% of our offshore platforms, all of our subsea wells and all of our properties under development.
| | - | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  | 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 51% of our common stock on a fully diluted basis.
| | - | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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



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



Competition



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



Royalty Relief



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



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



Regulation



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



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



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transportation of natural gas, with the stated goal of fostering competition within all phases of the natural gas industry. We cannot predict what further
action the FERC will take on these or related matters, nor can we accurately predict whether the FERCs actions will achieve the goal of increasing competition in markets in which our natural gas is sold. However, we do not believe that any
action taken will affect us in a way that materially differs from the way it affects other natural gas producers, gatherers and marketers.



The Outer Continental Shelf Lands Act, which the FERC implements with regard to transportation and pipeline issues, requires that all pipelines operating
on or across the Outer Continental Shelf provide open-access, non-discriminatory service. There are currently no regulations implemented by FERC under its Outer Continental Shelf Lands Act authority on gatherers and other entities outside the reach
of its Natural Gas Act jurisdiction. The FERC retains authority under the Outer Continental Shelf Lands Act to exercise jurisdiction over gatherers and other entities outside the reach of its Natural Gas Act jurisdiction if necessary to insure
non-discriminatory access to service on the Outer Continental Shelf. We do not believe that any FERC action taken under its Outer Continental Shelf Lands Act jurisdiction will affect us in a way that materially differs from the way it affects other
natural gas producers, gatherers and marketers.



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



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



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



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



The MMS also administers the collection of royalties under the
terms of the Outer Continental Shelf Lands Act and the oil and gas leases issued under the Act. The amount of royalties due is based upon the terms of the oil and gas leases as well as of the regulations promulgated by the MMS. The MMS regulations
governing the calculation of royalties and the valuation of crude oil produced from federal leases currently rely on arms-length sales prices and spot market prices as indicators of value. On August 20, 2003, the MMS issued a proposed rule
that would change certain components of its valuation procedures for the calculation of royalties owed for crude oil sales. The proposed changes include changing the valuation basis for transactions not at arms-length from spot to NYMEX prices
adjusted for locality and quality differentials, and clarifying the treatment of transactions under a joint operating agreement. Final comments on the proposed rule were due on November 10, 2003. We cannot predict whether this proposed rule will
take effect as written, nor



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can we predict whether the proposed rule, if it takes effect, will be challenged in federal court and whether it will withstand such a challenge. We believe
this rule, as proposed, will not have a material impact on our financial condition, liquidity or results of operations.



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



The regulation of pipelines that transport crude oil, condensate and natural
gas liquids is generally more light-handed than the FERCs regulation of gas pipelines under the Natural Gas Act. Regulated pipelines that transport crude oil, condensate, and natural gas liquids are subject to common carrier obligations that
generally ensure non-discriminatory access. With respect to interstate pipeline transportation subject to regulation of the FERC under the Interstate Commerce Act, rates generally must be cost-based, although market-based rates or negotiated
settlement rates are permitted in certain circumstances. Pursuant to FERC Order No. 561, issued in October 1993, the FERC implemented regulations generally grandfathering all previously unchallenged interstate pipeline rates and made these rates
subject to an indexing methodology. Under this indexing methodology, pipeline rates are subject to changes in the Producer Price Index for Finished Goods, minus one percent. A pipeline can seek to increase its rates above index levels provided that
the pipeline can establish that there is a substantial divergence between the actual costs experienced by the pipeline and the rate resulting from application of the index. A pipeline can seek to charge market-based rates if it establishes that it
lacks significant market power. In addition, a pipeline can establish rates pursuant to settlement if agreed upon by all current shippers. A pipeline can seek to establish initial rates for new services through a cost-of-service proceeding, a
market-based rate proceeding, or through an agreement between the pipeline and at least one shipper not affiliated with the pipeline. As provided for in Order No. 561, in July 2000, the FERC issued a Notice of Inquiry seeking comment on whether to
retain or to change the existing oil rate-indexing method. In December 2000, the FERC issued an order concluding that the rate index reasonably estimated the actual cost changes in the pipeline industry and should be continued for another 5-year
period, subject to review in July 2005. In February 2003, on remand of its December 2000 order from the D.C. Circuit, the FERC changed the rate indexing methodology to the Producer Price Index for Finished Goods, but without the subtraction of 1% as
had been done previously. The FERC made the change prospective only, but did allow oil pipelines to recalculate their maximum ceiling rates as though the new rate indexing methodology had been in effect since July 1, 2001. A challenge to FERCs
remand order is currently pending before the D.C. Circuit.



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



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



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



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



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



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



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



The Oil
Pollution Act of 1990 also imposes other requirements, such as the preparation of an oil spill contingency plan. We have such a plan in place. We are also regulated by the Clean Water Act, which prohibits any discharge into waters of the U.S. except
in strict conformance with discharge permits issued by federal or state agencies. We have obtained, and are in material compliance with, the discharge permits necessary for our operations. We are also subject to similar state and local water quality
laws and regulations for any production or drilling activities that occur in state coastal waters. Failure to comply with the ongoing requirements of the Clean Water Act or inadequate cooperation during a spill event may subject a responsible party
to civil or criminal enforcement actions.



The Comprehensive
Environmental Response, Compensation, and Liability Act, or CERCLA, also known as the Superfund law, imposes liability, without regard to fault or the legality of the original conduct, on some classes of persons that are considered to
have contributed to the release of a hazardous substance into the environment. These persons include the owner or operator of the disposal site or sites where the release occurred and companies that disposed or arranged for the disposal
of the hazardous substances found at the site. Persons who are or were responsible for releases of hazardous substances under CERCLA may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been
released into the environment and for damages to natural resources, and it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances
released into the environment. We could be subject to liability under CERCLA because our drilling and production activities generate relatively small amounts of liquid and solid wastes that may be subject to classification as hazardous substances
under CERCLA. These wastes must be brought to shore for proper



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



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



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



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



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



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



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



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



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



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



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



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



Risk Factors



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



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



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



| |  | make it more difficult or render us unable to satisfy our financial obligations;
| | - | --------------------------------------------------------------------------------



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



| |  | increase our vulnerability to general adverse economic and industry conditions;
| | - | -------------------------------------------------------------------------------



| |  | limit our flexibility in planning for or reacting to changes in our business and the industry in which we operate;
| | - | ------------------------------------------------------------------------------------------------------------------



| |  | place us at a competitive disadvantage compared to some of our competitors that have less financial leverage; and
| | - | -----------------------------------------------------------------------------------------------------------------



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



Our ability to satisfy our obligations and to reduce our total debt depends
on our future operating performance and on economic, financial, competitive and other factors, many of which are beyond our control. We cannot provide assurance that our business will generate sufficient cash flow or that future financings will be
available to provide sufficient proceeds to meet these obligations. The successful execution of our business strategy and the maintenance of our economic viability are also contingent upon our ability to meet our financial obligations.



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



Our current
term loan, established in March 2004, contains customary restrictions, including covenants limiting our ability to incur additional debt, grant liens, make investments, consolidate, merge or acquire other businesses, sell assets, pay dividends and
other distributions and enter into transactions with affiliates. We also are required to meet specified financial ratios under the terms of our term loan. During 2003 and in February 2004, we were required to obtain waivers for certain of our
financial covenants in our prior credit facility. If we are required to seek waivers under our new term loan, there is no assurance that such waivers will be obtained. These restrictions may make it difficult for us to successfully execute our
business strategy or to compete in our industry with companies not similarly restricted.



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



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



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



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



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



Our estimates of our proved natural gas and oil reserves and the estimated
future net revenues from such reserves are based upon various assumptions, including assumptions required by the SEC relating to natural gas and oil prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. This
process requires significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir. Therefore, these estimates are inherently imprecise and the quality and reliability of
this data can vary. For example, we incurred higher than estimated costs in the development of our Helvellyn property in the North Sea as a result of unforeseen delays and development complications.



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



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



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



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



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



We have historically needed and will continue to need substantial amounts of
cash to fund our capital expenditure and working capital requirements. Our ongoing capital requirements consist primarily of funding acquisition, development and abandonment of oil and gas reserves and to meet our debt service obligations. Our
capital expenditures were approximately $83.8 million during 2003, $34.9 million during 2002 and $110.3 million during 2001. Because we have experienced a negative working capital position in past years, we have depended on debt and equity financing
to meet our working capital requirements.



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



| |  | cash provided by operating activities;
| | - | --------------------------------------



| |  | funds available under the new term loan;
| | - | ----------------------------------------



| |  | extended financing arrangements with suppliers and service providers; and
| | - | -------------------------------------------------------------------------



| |  | net cash proceeds from the sale of assets, debt or equity.
| | - | ----------------------------------------------------------



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



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



Our revenues, profitability and future growth and the carrying value of our properties depend substantially on the prices we realize for our natural gas
and oil production. Because approximately 76% of our estimated proved reserves as of December 31, 2003 were natural gas reserves, our financial results are more sensitive to movements in natural gas prices. Our realized prices also affect the amount
of cash flow available for capital expenditures and our ability to borrow and raise additional capital.



Historically, the markets for natural gas and oil have been volatile, and they are likely to continue to be volatile in the future. For example, natural
gas and oil prices increased significantly in late 2000 and early 2001 and steadily declined in 2001, only to climb again in 2002 and 2003. Among the factors that can cause this volatility are:



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



| |  | the domestic and foreign supply of natural gas and oil;
| | - | -------------------------------------------------------



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



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



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



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



We may incur substantial
impairment writedowns.



If managements estimates of
the recoverable reserves on a property are revised downward or if natural gas and oil prices decline, we may be required to record additional non-cash impairment writedowns in the future, which would result in a negative impact to our financial
position. We review our proved oil and gas properties for impairment on a depletable unit basis when circumstances suggest there is a need for such a review. To determine if a depletable unit is impaired, we compare the carrying value of the
depletable unit to the undiscounted future net cash flows by applying managements estimates of future oil and gas prices to the estimated future production of oil and gas reserves over the economic life of the property. Future net cash flows
are based upon our independent reservoir engineers estimates of proved reserves. In addition, other factors such as probable and possible reserves are taken into consideration when justified by economic conditions. For each property determined
to be impaired, we recognize an impairment loss equal to the difference between the estimated fair value and the carrying value of the property on a depletable unit basis. Fair value is estimated to be the present value of the aforementioned
expected future net cash flows. Any impairment charge incurred is recorded in accumulated depreciation, depletion, impairment and amortization to reduce our recorded basis in the asset. Each part of this calculation is subject to a large degree of
judgment, including the determination of the depletable units estimated reserves, future cash flows and fair value. We recorded impairments of $11.7 million, $6.8 million and $24.9 million for the years ended December 31, 2003, 2002 and 2001,
respectively.



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



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



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



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



| |  | 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 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 impact that future terrorist attacks or regional hostilities (particularly in the Middle East) may have on the energy industry in general, and on us
in particular, is not known at the time. Uncertainty surrounding military strikes or a sustained military campaign may affect our operations in unpredictable ways, including disruptions of fuel supplies and markets, particularly oil, and the
possibility that infrastructure facilities, including pipelines, production facilities, processing plants and refineries, could be direct targets of, or indirect casualties of, an act of terror or war. Moreover, we have incurred additional costs
since the terrorist attacks of September 11, 2001 to safeguard certain of our assets and we may be required to incur significant additional costs in the future.



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



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



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



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



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



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



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



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



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



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



Our success will depend
on our ability to retain and attract experienced geoscientists and other professional staff. As of December 31, 2003, we had 12 engineers, geologist/geophysicists and other technical personnel in our Houston office and four engineers,
geologist/geophysicists and other technical personnel in our London location. We depend to a large extent on the efforts, technical expertise and continued employment of these personnel and members of our management team. If a significant number of
them resign or become unable to continue in their present role and if they are not adequately replaced, our business operations could be adversely affected.



Rapid growth may place significant demands on our resources.



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



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



| |  | 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.



20



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Members of our management team own a significant amount of common stock, giving them influence or
control in corporate transactions and other matters, and the interests of these individuals could differ from those of other shareholders.



Members of our management team beneficially own approximately 51% of our outstanding shares of common stock. As a result, these shareholders are in a
position to significantly influence or control the outcome of matters requiring a shareholder vote, including the election of directors, the adoption of an amendment to our articles of incorporation or bylaws and the approval of mergers and other
significant corporate transactions. Their control of ATP may delay or prevent a change of control of ATP and may adversely affect the voting and other rights of other shareholders.



Employees



At December 31, 2003 we had 41 full-time employees in our Houston office, seven full-time employees in our London office and one full-time employee in our
Netherlands office. None of our employees are covered by a collective bargaining agreement. From time to time, we use the services of independent consultants and contractors to perform various professional services, particularly in the areas of
construction, design, well-site supervision, permitting and environmental assessment. Independent contractors usually perform field and on-site production operation services for us, including gauging, maintenance, dispatching, inspection and well
testing.



Available Information



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



|Item 2. | Properties
|------- | ----------



General



We are engaged in the acquisition, development and production of natural gas and oil properties primarily in the Gulf of Mexico and the North Sea. At December 31, 2003, we had leasehold and other interests in 50
offshore blocks, 26 platforms and 62 wells, including six subsea wells, in the Gulf of Mexico. We operate 50 of these 62 wells, including all of the subsea wells, and 85% of our offshore platforms. We also held interests in eight blocks and one
company-operated subsea well located in the North Sea. Our average working interest in our properties at December 31, 2003 was approximately 82%. As of December 31, 2003, we had leasehold interests located in the Gulf of Mexico and North Sea
covering approximately 264,592 gross and 209,424 net acres.



Gulf of Mexico



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



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



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



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



North Sea



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



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



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



22



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##### Table of Contents

Natural Gas and Oil Reserves



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



|                              |  |                 |  |             |  |        
|----------------------------- |  | --------------- |  | ----------- |  | -------
|                              |  | Proved Reserves
|                              |  | Developed       |  | Undeveloped |  | Total  
|Gulf of Mexico                |  |                 |  |             |  |        
|Natural gas (MMcf)            |  | 30,062          |  | 99,971      |  | 130,033
|Oil and condensate (MBbls)    |  | 1,697           |  | 10,246      |  | 11,943 
|Total proved reserves (MMcfe) |  | 40,244          |  | 161,447     |  | 201,691
|North Sea                     |  |                 |  |             |  |        
|Natural gas (MMcf)            |  | 15,740          |  | 85,292      |  | 101,032
|Oil and condensate (MBbls)    |  |                |  | 2           |  | 2      
|Total proved reserves (MMcfe) |  | 15,740          |  | 85,304      |  | 101,044
|Total                         |  |                 |  |             |  |        
|Natural gas (MMcf)            |  | 45,802          |  | 185,263     |  | 231,065
|Oil and condensate (MBbls)    |  | 1,697           |  | 10,248      |  | 11,945 
|Total proved reserves (MMcfe) |  | 55,984          |  | 246,751     |  | 302,735



The estimates of
proved reserves in the table above do not differ from those we have filed with other federal agencies. The process of estimating natural gas and oil reserves is complex. It requires various assumptions, including assumptions relating to natural gas
and oil prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. We must project production rates and timing of development expenditures. We analyze available geological, geophysical, production and engineering
data, and the extent, quality and reliability of this data can vary. Therefore, estimates of natural gas and oil reserves are inherently imprecise.



Our business strategy is to acquire proved reserves, usually proved undeveloped, and to bring those reserves on production as rapidly as possible. At
December 31, 2003, approximately 80% of our estimated equivalent net proved reserves in the Gulf of Mexico and 84% of our estimated equivalent net proved reserves in North Sea were undeveloped. Recovery of undeveloped reserves generally requires
significant capital expenditures and successful drilling and completion operations. The reserve data assumes that we will make these expenditures. Although the reserves and the costs associated with developing them are estimated in accordance with
industry standards, the estimated costs may be inaccurate, development may not occur as scheduled and results may not be as estimated.



Drilling Activity



The following table shows our drilling and completion activity. In the table, gross refers to the total wells in which we have a working
interest and net refers to gross wells multiplied by our working interest in such wells. We did not drill or complete any exploratory wells in any period presented.



|                         |  |                |  |           |  |      |  |      |  |      |  |     
|------------------------ |  | -------------- |  | --------- |  | ---- |  | ---- |  | ---- |  | ----
|                         |  | Gulf of Mexico |  | North Sea
|                         |  | 2003           |  | 2002      |  | 2001 |  | 2003 |  | 2002 |  | 2001
|Gross Development Wells: |  |                |  |           |  |      |  |      |  |      |  |     
|Productive               |  | 5.0            |  |          |  | 8.0  |  | 1.0  |  |     |  |    
|Nonproductive            |  |               |  |          |  | 1.0  |  |     |  |     |  |    
|                         |  |                |  |           |  |      |  |      |  |      |  |     
|Total                    |  | 5.0            |  |          |  | 9.0  |  | 1.0  |  |     |  |    
|                         |  |                |  |           |  |      |  |      |  |      |  |     
|Net Development Wells:   |  |                |  |           |  |      |  |      |  |      |  |     
|Productive               |  | 4.3            |  |          |  | 6.3  |  | 0.5  |  |     |  |    
|Nonproductive            |  |               |  |          |  | 1.0  |  |     |  |     |  |    
|                         |  |                |  |           |  |      |  |      |  |      |  |     
|Total                    |  | 4.3            |  |          |  | 7.3  |  | 0.5  |  |     |  |    
|                         |  |                |  |           |  |      |  |      |  |      |  |     



At December 31, 2003
we had 2 development wells (1.3 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 natural gas and oil wells in which we owned an interest as of December 31, 2003.



|      |  |               |  |         
|----- |  | ------------- |  | --------
|      |  | Gulf ofMexico |  | NorthSea
|Gross |  |               |  |         
|Gas   |  | 26.0          |  | 1.0     
|Oil   |  | 9.0           |  |        
|      |  |               |  |         
|Total |  | 35.0          |  | 1.0     
|      |  |               |  |         
|Net   |  |               |  |         
|Gas   |  | 21.2          |  | 0.5     
|Oil   |  | 4.4           |  |        
|      |  |               |  |         
|Total |  | 25.6          |  | 0.5     
|      |  |               |  |         



Acreage



The following table summarizes our developed and undeveloped acreage
holdings at December 31, 2003. Acreage in which ownership interest is limited to royalty, overriding royalty and other similar interests is excluded (in acres):



|               |  |               |  |                 |  |         |  |        |  |         |  |        
|-------------- |  | ------------- |  | --------------- |  | ------- |  | ------ |  | ------- |  | -------
|               |  | Developed (1) |  | Undeveloped (2) |  | Total  
|               |  | Gross         |  | Net             |  | Gross   |  | Net    |  | Gross   |  | Net    
|Gulf of Mexico |  | 134,447       |  | 109,642         |  | 60,043  |  | 55,281 |  | 194,490 |  | 164,923
|North Sea.     |  | 12,078        |  | 6,039           |  | 58,024  |  | 38,462 |  | 70,102  |  | 44,501 
|               |  |               |  |                 |  |         |  |        |  |         |  |        
|               |  | 146,525       |  | 115,681         |  | 118,067 |  | 93,743 |  | 264,592 |  | 209,424
|               |  |               |  |                 |  |         |  |        |  |         |  |        

---

|(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 natural gas and
oil, 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
|------- | -----------------



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



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



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



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



|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 2003.



Executive Officers of the Company



Set forth below are the names, ages (as of March 19, 2004) and titles of the
persons currently serving as executive officers of the Company. All executive officers hold office until their successors are elected and qualified.



|                     |  |     |  |                                                  
|-------------------- |  | --- |  | -------------------------------------------------
|Name                 |  | Age |  | Position                                         
|T. Paul Bulmahn      |  | 60  |  | Chairman and President                           
|Gerald W. Schlief    |  | 56  |  | Senior Vice President                            
|Albert L. Reese, Jr. |  | 54  |  | Senior Vice President and Chief Financial Officer
|Leland E. Tate.      |  | 56  |  | Senior Vice President, Operations                
|John E. Tschirhart.  |  | 53  |  | Senior Vice President, General Counsel           



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



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



Albert L. Reese, Jr.has served as our Chief Financial Officer since March 1999 and, in a consulting capacity, as our director of finance from 1991
until March 1999. He was also named Senior Vice President in August 2000. From 1986 to 1991, Mr. Reese was employed with the Harbert Corporation where he established a registered investment bank for the company to conduct project and corporate
financings for energy, co-generation, and small power activities. From 1979 to 1986, Mr. Reese served as chief financial officer of Plumb Oil Company and its successor, Harbert Energy Corporation. Prior to 1979, Mr. Reese served in various
capacities with Capital Bank in Houston, the independent accounting firm of Peat, Marwick & Mitchell, and as a partner in Arnold, Reese & Swenson, a Houston-based accounting firm specializing in energy clients.



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##### Table of Contents

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



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



PART II



|Item 5. | Market for Registrants Common Equity and Related Stockholder Matters
|------- | ---------------------------------------------------------------------



Our authorized capital stock consists of 100,000,000 shares of common stock, par value $0.001 per share, and 10,000,000
shares of preferred stock, par value $0.001 per share. There were 24,523,356 shares of common stock and no shares of preferred stock outstanding as of March 19, 2004. There were 67 holders of record of our common stock as of March 19, 2004. Our
common stock is traded on the Nasdaq National Market under the ticker symbol ATPG.



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



|           |  |      |      |     |   |     
|---------- |  | ---- | ---- | --- | - | ----
|           |  | High |      | Low
|2003:      |  |      |      |     |   |     
|4thQuarter |  | $    | 6.65 |     | $ | 3.92
|3rdQuarter |  |      | 7.05 |     |   | 4.92
|2ndQuarter |  |      | 7.75 |     |   | 3.01
|1stQuarter |  |      | 5.15 |     |   | 3.65
|2002:      |  |      |      |     |   |     
|4thQuarter |  | $    | 4.49 |     | $ | 2.78
|3rdQuarter |  |      | 3.40 |     |   | 2.51
|2ndQuarter |  |      | 4.77 |     |   | 2.50
|1stQuarter |  |      | 5.00 |     |   | 1.47



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



26



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##### Table of Contents

|Item 6. | Selected Financial Data
|------- | -----------------------



(In thousands, except per share data)



The selected historical financial information was derived from, and is qualified by reference to our consolidated financial statements, including the
notes thereto, appearing elsewhere in this report. The following data should be read in conjunction with Item 7.  Managements Discussion and Analysis of Financial Condition and Results of Operations.



|                                                                                                     |  |                          |         |   |      |   |         |      |  |   |         |   |  |      |         |   |  |   |         |  
|---------------------------------------------------------------------------------------------------- |  | ------------------------ | ------- | - | ---- | - | ------- | ---- |  | - | ------- | - |  | ---- | ------- | - |  | - | ------- | -
|                                                                                                     |  | Years Ended December 31, |        
|                                                                                                     |  | 2003                     |         |   | 2002 |   |         | 2001 |  |   | 2000    |   |  | 1999 |        
|Statement of Operations Data:                                                                        |  |                          |         |   |      |   |         |      |  |   |         |   |  |      |         |   |  |   |         |  
|Revenues:                                                                                            |  |                          |         |   |      |   |         |      |  |   |         |   |  |      |         |   |  |   |         |  
|Oil and gas production                                                                               |  | $                        | 70,151  |   |      | $ | 80,017  |      |  | $ | 87,873  |   |  | $    | 64,256  |   |  | $ | 35,282  |  
|Gain on sale of oil and gas properties                                                               |  |                          |        |   |      |   |        |      |  |   |        |   |  |      | 33      |   |  |   | 287     |  
|                                                                                                     |  |                          |         |   |      |   |         |      |  |   |         |   |  |      |         |   |  |   |         |  
|Total revenues                                                                                       |  |                          | 70,151  |   |      |   | 80,017  |      |  |   | 87,873  |   |  |      | 64,289  |   |  |   | 35,569  |  
|                                                                                                     |  |                          |         |   |      |   |         |      |  |   |         |   |  |      |         |   |  |   |         |  
|Cost and operating expenses:                                                                         |  |                          |         |   |      |   |         |      |  |   |         |   |  |      |         |   |  |   |         |  
|Lease operating expenses                                                                             |  |                          | 17,173  |   |      |   | 16,764  |      |  |   | 14,806  |   |  |      | 11,559  |   |  |   | 5,587   |  
|Geological and geophysical expenses                                                                  |  |                          | 1,358   |   |      |   | 154     |      |  |   | 1,068   |   |  |      |        |   |  |   |        |  
|General and administrative                                                                           |  |                          | 12,209  |   |      |   | 10,037  |      |  |   | 9,806   |   |  |      | 5,409   |   |  |   | 3,541   |  
|Credit facility costs                                                                                |  |                          | 1,990   |   |      |   | 250     |      |  |   | 175     |   |  |      |        |   |  |   |        |  
|Non-cash compensation expense                                                                        |  |                          | (39     | ) |      |   | 595     |      |  |   | 3,364   |   |  |      |        |   |  |   |        |  
|Depreciation, depletion and amortization                                                             |  |                          | 29,378  |   |      |   | 43,390  |      |  |   | 53,428  |   |  |      | 40,569  |   |  |   | 22,521  |  
|Impairment of oil and gas properties                                                                 |  |                          | 11,670  |   |      |   | 6,844   |      |  |   | 24,891  |   |  |      | 10,838  |   |  |   | 7,509   |  
|Loss on abandonment(1)                                                                               |  |                          | 4,973   |   |      |   |        |      |  |   |        |   |  |      |        |   |  |   |        |  
|Accretion expense(2)                                                                                 |  |                          | 2,752   |   |      |   |        |      |  |   |        |   |  |      |        |   |  |   |        |  
|Loss on unsuccessful property acquisition(3)                                                         |  |                          | 8,192   |   |      |   |        |      |  |   | 3,147   |   |  |      |        |   |  |   |        |  
|Other expense                                                                                        |  |                          |        |   |      |   |        |      |  |   |        |   |  |      | 450     |   |  |   |        |  
|                                                                                                     |  |                          |         |   |      |   |         |      |  |   |         |   |  |      |         |   |  |   |         |  
|Total operating expenses                                                                             |  |                          | 89,656  |   |      |   | 78,034  |      |  |   | 110,685 |   |  |      | 68,825  |   |  |   | 39,158  |  
|                                                                                                     |  |                          |         |   |      |   |         |      |  |   |         |   |  |      |         |   |  |   |         |  
|Income (loss) from operations                                                                        |  |                          | (19,505 | ) |      |   | 1,983   |      |  |   | (22,812 | ) |  |      | (4,536  | ) |  |   | (3,589  | )
|Other income (expense):                                                                              |  |                          |         |   |      |   |         |      |  |   |         |   |  |      |         |   |  |   |         |  
|Interest income                                                                                      |  |                          | 52      |   |      |   | 73      |      |  |   | 884     |   |  |      | 451     |   |  |   | 202     |  
|Interest expense                                                                                     |  |                          | (9,678  | ) |      |   | (10,418 | )    |  |   | (10,039 | ) |  |      | (11,907 | ) |  |   | (9,399  | )
|Loss on extinguishment of debt                                                                       |  |                          | (3,352  | ) |      |   |        |      |  |   | (926    | ) |  |      |        |   |  |   |        |  
|Other income                                                                                         |  |                          | 2,244   |   |      |   | 1,081   |      |  |   |        |   |  |      |        |   |  |   |        |  
|                                                                                                     |  |                          |         |   |      |   |         |      |  |   |         |   |  |      |         |   |  |   |         |  
|Loss before income taxes, extraordinary item and cumulative effect of change in accounting principle |  |                          | (30,239 | ) |      |   | (7,281  | )    |  |   | (32,893 | ) |  |      | (15,992 | ) |  |   | (12,786 | )
|Income tax (expense) benefit                                                                         |  |                          | (21,224 | ) |      |   | 2,581   |      |  |   | 11,510  |   |  |      | 5,594   |   |  |   | 1,829   |  
|                                                                                                     |  |                          |         |   |      |   |         |      |  |   |         |   |  |      |         |   |  |   |         |  
|Loss before extraordinary item and cumulative effect of change in accounting principle               |  |                          | (51,463 | ) |      |   | (4,700  | )    |  |   | (21,383 | ) |  |      | (10,398 | ) |  |   | (10,957 | )
|Extraordinary item, net of tax                                                                       |  |                          |        |   |      |   |        |      |  |   |        |   |  |      |        |   |  |   | 29,185  |  
|                                                                                                     |  |                          |         |   |      |   |         |      |  |   |         |   |  |      |         |   |  |   |         |  
|Income (loss) before cumulative effect of change in accounting principle                             |  |                          | (51,463 | ) |      |   | (4,700  | )    |  |   | (21,383 | ) |  |      | (10,398 | ) |  |   | 18,228  |  
|Cumulative effect of change in accounting principle, net of tax(4)                                   |  |                          | 662     |   |      |   |        |      |  |   |        |   |  |      |        |   |  |   |        |  
|                                                                                                     |  |                          |         |   |      |   |         |      |  |   |         |   |  |      |         |   |  |   |         |  
|Net income (loss)                                                                                    |  | $                        | (50,801 | ) |      | $ | (4,700  | )    |  | $ | (21,383 | ) |  | $    | (10,398 | ) |  | $ | 18,228  |  
|                                                                                                     |  |                          |         |   |      |   |         |      |  |   |         |   |  |      |         |   |  |   |         |  
|Weighted average number of common shares outstanding - basic and diluted                             |  |                          | 22,975  |   |      |   | 20,315  |      |  |   | 19,704  |   |  |      | 14,286  |   |  |   | 14,286  |  
|Basic and diluted income (loss) per share:                                                           |  |                          |         |   |      |   |         |      |  |   |         |   |  |      |         |   |  |   |         |  
|Income (loss) before cumulative effect of change in accounting principle                             |  | $                        | (2.24   | ) |      | $ | (0.23   | )    |  | $ | (1.09   | ) |  | $    | (0.73   | ) |  | $ | 1.28    |  
|Net income (loss)                                                                                    |  | $                        | (2.21   | ) |      | $ | (0.23   | )    |  | $ | (1.09   | ) |  | $    | (0.73   | ) |  | $ | 1.28    |  



Table and footnotes
continued on following page



27



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##### Table of Contents

|                               |  |              |         |   |      |   |         |      |  |   |         |   |  |      |         |   |  |   |         |  
|------------------------------ |  | ------------ | ------- | - | ---- | - | ------- | ---- |  | - | ------- | - |  | ---- | ------- | - |  | - | ------- | -
|                               |  | December 31, |        
|                               |  | 2003         |         |   | 2002 |   |         | 2001 |  |   | 2000    |   |  | 1999 |        
|Balance Sheet Data:            |  |              |         |   |      |   |         |      |  |   |         |   |  |      |         |   |  |   |         |  
|Cash and cash equivalents      |  | $            | 4,564   |   |      | $ | 6,944   |      |  | $ | 5,294   |   |  | $    | 18,136  |   |  | $ | 17,779  |  
|Working capital (deficit)      |  |              | (46,423 | ) |      |   | (13,699 | )    |  |   | (29,071 | ) |  |      | (3,835  | ) |  |   | 14,115  |  
|Net oil and gas properties     |  |              | 189,125 |   |      |   | 119,036 |      |  |   | 133,033 |   |  |      | 98,725  |   |  |   | 72,278  |  
|Total assets                   |  |              | 217,685 |   |      |   | 182,055 |      |  |   | 177,564 |   |  |      | 161,993 |   |  |   | 107,054 |  
|Total debt                     |  |              | 115,409 |   |      |   | 86,387  |      |  |   | 100,111 |   |  |      | 116,529 |   |  |   | 91,723  |  
|Total liabilities              |  |              | 213,353 |   |      |   | 143,508 |      |  |   | 132,572 |   |  |      | 175,172 |   |  |   | 109,835 |  
|Shareholders equity (deficit) |  |              | 4,332   |   |      |   | 38,547  |      |  |   | 44,992  |   |  |      | (13,179 | ) |  |   | (2,781  | )

---

|(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) | Pursuant to the requirements of Statement of Financial Accounting Standard (SFAS) SFAS No. 143, Accounting For Asset Retirement
Obligations(SFAS 143) which we adopted on January 1, 2003, we recorded accretion expense totaling $2.8 million associated with our oil and gas asset retirement obligations.
|--- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



|(3) | ATP and Legacy were in a dispute over a contract for the sale of an oil and gas property. ATP paid $3.0 million to Legacy on October 9, 2001 to extend the closing
date of the proposed acquisition to October 31, 2001. While working on the closing of the property with ATP after October 31, 2001, Legacy sold the property to a third party without informing ATP until after the closing. ATP filed a lawsuit alleging
improper sale and seeking the return of its $3.0 million earlier payment. Legacy filed suit seeking $12.3 million plus interest at 16%. The matter was referred to arbitration and in the May 2003 arbitration proceedings Legacy sought a total claim of
over $17.0 million through the end of 2003. On December 19, 2003, ATP was notified by the arbitration panel of its decision to award $8.2 million to Legacy. Interest on that amount accrues from the date of the award by the panel until the date of
payment. ATP paid Legacy an initial payment of $1.0 million on March 29, 2004. Legacy and ATP have agreed that the balance of the award will be paid on or before April 16, 2004.
|--- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



|(4) | 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 natural gas and oil properties in the Gulf of Mexico and the
North Sea. We seek to acquire and develop properties with proved undeveloped reserves (PUD) that are economically attractive to us but are not strategic to major or large exploration-oriented independent oil and gas companies. We believe
that our strategy provides assets for us to develop and produce without the risk, cost or time of exploration.



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



| |  | significant undeveloped reserves;
| | - | ---------------------------------



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



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



| |  | a relatively stable regulatory environment for offshore natural gas and oil development and production.
| | - | -------------------------------------------------------------------------------------------------------



We focus on acquiring properties that contain proved undeveloped reserves that have become non-core or non-strategic to
their original owners for a variety of reasons. For example, larger oil companies from time to time adjust their capital spending or shift their focus to exploration prospects which they believe offer greater reserve potential. Some projects provide
lower economic returns to a larger company due to its cost structure within that company. Also, due to timing or budget constraints, a company may be unwilling or unable to develop a property before the expiration of the lease. Because of our
efficient cost structure, expertise in our areas of focus and ability to develop projects, the properties may be more financially attractive to us than the seller. Given our strategy of acquiring properties that contain proved reserves, our
operations are lower risk than exploration-focused Gulf of Mexico and North Sea operators. As a result of this strategy, we have successfully brought 35 out of 36 (97%) proved undeveloped reserve projects to commercial production since our
inception.



By focusing on properties that are not strategic to
other companies and properties that are primarily proved but as yet undeveloped, we are able to minimize up front acquisition costs and concentrate available capital on the development phase of these properties. Since our inception in 1991 through
December 31, 2003, we have added 483.1 Bcfe of proved natural gas and oil reserves through acquisitions at a total cost of $77.5 million or $0.18 per Mcfe. Development costs for this same period were approximately $366.5 million.



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



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



29



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##### Table of Contents

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



Review of 2003



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



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



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



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



30



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##### Table of Contents

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



2004 Operational and Financial Objectives



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



The income tax expense of $21.2 million in 2003 was primarily
due the Company recording a valuation allowance of $33.6 million against our deferred tax asset as required by SFAS No. 109 Accounting for Income Taxes (SFAS 109). See Note 11 Income Taxes to the Consolidated
Financial Statements. SFAS 109 provides for the weighing of positive and negative evidence in determining whether a deferred tax asset is recoverable. We have incurred net operating losses in 2003 and prior years. Relevant accounting guidance
suggests that cumulative losses in recent years constitute significant negative evidence, and that future expectations about income are overshadowed by such history of losses. Delays in bringing properties on to production and development cost
overruns in 2003 were also significant factors considered in evaluating our deferred tax asset valuation allowance. If we achieve profitable operations in 2004, we may reverse a portion of the valuation allowance in an amount at least sufficient to
eliminate any tax provision in that period. We expect a significant increase in 2004 production over 2003 as a result of the development activities at our Helvellyn, Matia/Cabrito and SS358 developments during 2003 and the first quarter of 2004.
This increased production combined with higher realized prices should result in a substantial increase in our 2004 results of operations.



We have budgeted approximately $50.0 to $60.0 million for 2004 development operations on nine properties with undeveloped reserves in the Gulf of Mexico
and approximately $5.0 to $10.0 million in the North Sea. Of particular note is that eight of the nine 2004 Gulf of Mexico developments are on properties with existing infrastructure (platforms and pipelines) which should significantly decrease the
time from initial capital expenditures to first production. In the first quarter of 2004, we sold 25% of our interest in seven projects containing ten offshore blocks in the Gulf of Mexico for $19.5 million, approximately $1.85/Mcfe for proved
reserves, of which 93.5% are proved undeveloped reserves.



Recent
Developments



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



31



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##### Table of Contents

Results of Operations



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



Oil and
Gas Revenues



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



|                                                    |  |                          |         |   |                          |   |        |                          |  |   |         |   |  |      |    |  |     |   
|--------------------------------------------------- |  | ------------------------ | ------- | - | ------------------------ | - | ------ | ------------------------ |  | - | ------- | - |  | ---- | -- |  | --- | --
|                                                    |  | Years Ended December 31, |         |   | % Changefrom 2002to 2003 |   |        | % Changefrom 2001to 2002 | 
|                                                    |  | 2003                     |         |   | 2002                     |   |        | 2001                     |  |   |        
|Production (1):                                     |  |                          |         |   |                          |   |        |                          |  |   |         |   |  |      |    |  |     |   
|Natural gas (MMcf)                                  |  |                          | 10,842  |   |                          |   | 17,732 |                          |  |   | 20,957  |   |  | (39  | %) |  | (15 | %)
|Oil and condensate (MBbls)                          |  |                          | 1,042   |   |                          |   | 1,454  |                          |  |   | 790     |   |  | (28  | %) |  | 84  | % 
|Total (MMcfe)                                       |  |                          | 17,093  |   |                          |   | 26,457 |                          |  |   | 25,696  |   |  | (35  | %) |  | 3   | % 
|Revenues (in thousands):                            |  |                          |         |   |                          |   |        |                          |  |   |         |   |  |      |    |  |     |   
|Natural gas                                         |  | $                        | 52,199  |   |                          | $ | 56,659 |                          |  | $ | 88,908  |   |  | (8   | %) |  | (36 | %)
|Oil and condensate                                  |  |                          | 29,601  |   |                          |   | 32,756 |                          |  |   | 16,849  |   |  | (10  | %) |  | 94  | % 
|                                                    |  |                          |         |   |                          |   |        |                          |  |   |         |   |  |      |    |  |     |   
|                                                    |  |                          | 81,800  |   |                          |   | 89,415 |                          |  |   | 105,757 |   |  | (9   | %) |  | (15 | %)
|Effects of risk management activities(2)(3)         |  |                          | (16,564 | ) |                          |   | (3,379 | )                        |  |   | (19,751 | ) |  | (390 | %) |  | 83  | % 
|                                                    |  |                          |         |   |                          |   |        |                          |  |   |         |   |  |      |    |  |     |   
|Total                                               |  | $                        | 65,236  |   |                          | $ | 86,036 |                          |  | $ | 86,006  |   |  | (24  | %) |  |    |   
|                                                    |  |                          |         |   |                          |   |        |                          |  |   |         |   |  |      |    |  |     |   
|Average realized sales price per unit:              |  |                          |         |   |                          |   |        |                          |  |   |         |   |  |      |    |  |     |   
|Natural gas (per Mcf)                               |  | $                        | 4.82    |   |                          | $ | 3.20   |                          |  | $ | 4.24    |   |  | 51   | %  |  | (25 | %)
|Effects of risk management activities (per Mcf)(2)  |  |                          | (1.41   | ) |                          |   | (0.16  | )                        |  |   | (0.94   | ) |  | (781 | )% |  | 83  | % 
|                                                    |  |                          |         |   |                          |   |        |                          |  |   |         |   |  |      |    |  |     |   
|Average realized price (per Mcf)                    |  | $                        | 3.41    |   |                          | $ | 3.04   |                          |  | $ | 3.30    |   |  | 12   | %  |  | (8  | %)
|                                                    |  |                          |         |   |                          |   |        |                          |  |   |         |   |  |      |    |  |     |   
|Oil and condensate (per Bbl)                        |  | $                        | 28.42   |   |                          | $ | 22.53  |                          |  | $ | 21.33   |   |  | 26   | %  |  | 6   | % 
|Effects of risk management activities (per Bbl)(2)  |  |                          | (1.21   | ) |                          |   | (0.42  | )                        |  |   |        |   |  | (188 | )% |  |    |   
|                                                    |  |                          |         |   |                          |   |        |                          |  |   |         |   |  |      |    |  |     |   
|Average realized price (per Bbl)                    |  | $                        | 27.21   |   |                          | $ | 22.11  |                          |  | $ | 21.33   |   |  | 23   | %  |  | 4   | % 
|                                                    |  |                          |         |   |                          |   |        |                          |  |   |         |   |  |      |    |  |     |   
|Natural gas, oil and condensate (per Mcfe)          |  | $                        | 4.79    |   |                          | $ | 3.38   |                          |  | $ | 4.12    |   |  | 42   | %  |  | (18 | %)
|Effects of risk management activities (per Mcfe)(2) |  |                          | (0.97   | ) |                          |   | (0.13  | )                        |  |   | (0.77   | ) |  | (646 | )% |  | 83  | % 
|                                                    |  |                          |         |   |                          |   |        |                          |  |   |         |   |  |      |    |  |     |   
|Average realized price (per Mcfe)                   |  | $                        | 3.82    |   |                          | $ | 3.25   |                          |  | $ | 3.35    |   |  | 18   | %  |  | (3  | %)
|                                                    |  |                          |         |   |                          |   |        |                          |  |   |         |   |  |      |    |  |     |   

---

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



|(2) | Includes only the effect of settled swaps and collars and not physical fixed price delivery
contracts.
|--- | ------------------------------------------------------------------------------------------------------



|(3) | Includes effects of natural gas risk management activities of $15,302, $2,764 and $19,751 for
the years ended December 31, 2003, 2002 and 2001, respectively. Includes effects of oil risk management activities of $1,262 and $615 for the years ended December 31, 2003 and 2002, respectively.
|--- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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



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



32



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##### Table of Contents

Lease Operating Expense



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



|                        |  |                          |        |                           |   |        |                           |   |        |  |    |   |  |    |  
|----------------------- |  | ------------------------ | ------ | ------------------------- | - | ------ | ------------------------- | - | ------ |  | -- | - |  | -- | -
|                        |  | Years Ended December 31, |        | % Changefrom 2002 to 2003 |   |        | % Changefrom 2001 to 2002 |  
|                        |  | 2003                     |        | 2002                      |   | 2001   |                           |  
|Lease operating expense |  | $                        | 17,173 |                           | $ | 16,764 |                           | $ | 14,806 |  | 2  | % |  | 13 | %
|Per Mcfe                |  | $                        | 1.00   |                           | $ | 0.63   |                           | $ | 0.58   |  | 59 | % |  | 9  | %



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.



The 13%
increase in expense and 9% increase per Mcfe in 2002 compared to 2001 was primarily the result of an increase in the number of producing wells we own and an increase in their total production volume. We also experienced higher than expected repairs
and maintenance costs on our platforms and costs incurred related to the hurricane and tropical storm in the fourth quarter of 2002.



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, 2003, 2002 and 2001 was as follows ($ in thousands):



|                                   |  |                          |        |                           |   |        |                           |   |       |  |    |   |  |   |  
|---------------------------------- |  | ------------------------ | ------ | ------------------------- | - | ------ | ------------------------- | - | ----- |  | -- | - |  | - | -
|                                   |  | Years Ended December 31, |        | % Changefrom 2002 to 2003 |   |        | % Changefrom 2001 to 2002 |  
|                                   |  | 2003                     |        | 2002                      |   | 2001   |                           |  
|General and administrative expense |  | $                        | 12,209 |                           | $ | 10,037 |                           | $ | 9,806 |  | 22 | % |  | 2 | %
|Per Mcfe                           |  | $                        | 0.71   |                           | $ | 0.38   |                           | $ | 0.38  |  | 87 | % |  |  |  



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. The slight increase in 2002 compared to 2001 was the result of higher compensation related costs in 2002 which
was substantially offset by a bad debt allowance recorded in 2001.



In 2003, we recorded a charge of $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, 2003, 2002 and 2001
was as follows ($ in thousands):



|         |  |                          |        |                          |   |        |                          |   |        |  |     |    |  |     |   
|-------- |  | ------------------------ | ------ | ------------------------ | - | ------ | ------------------------ | - | ------ |  | --- | -- |  | --- | --
|         |  | Years Ended December 31, |        | % Changefrom 2002to 2003 |   |        | % Changefrom 2001to 2002 |  
|         |  | 2003                     |        | 2002                     |   | 2001   |                          |  
|DD&A     |  | $                        | 29,378 |                          | $ | 43,390 |                          | $ | 53,428 |  | (32 | %) |  | (19 | %)
|Per Mcfe |  | $                        | 1.72   |                          | $ | 1.64   |                          | $ | 2.08   |  | 5   | %  |  | (21 | %)



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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.



DD&A decreased 19% in 2002 compared to 2001. The 21% decrease in the rate was attributable to (1) impairments taken in 2001, (2) higher than expected
costs of an abandonment completed in 2001 and (3) a new property brought on line in 2002 with a lower average DD&A rate than those properties producing in 2001.



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 5, 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.



Accretion of Asset
Retirement Obligation



Pursuant to the requirements of
SFAS 143 which we adopted on January 1, 2003, we recorded accretion expense totaling $2.8 million associated with our oil and gas asset retirement obligations.



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



ATP and Legacy were in a dispute over a contract for the sale of an oil and gas property. ATP paid $3.0 million to Legacy on October 9, 2001 to extend the closing date of the proposed acquisition to October 31, 2001.
While working on the closing of the property with ATP after October 31, 2001, Legacy sold the property to a third party without informing ATP until after the closing. ATP filed a lawsuit alleging improper sale and seeking the return of its $3.0
million earlier payment. Legacy filed suit seeking $12.3 million plus interest at 16%. The matter was referred to arbitration and in the May 2003 arbitration proceedings Legacy sought a total claim of over $17.0 million through the end of 2003. On
December 19, 2003, ATP was notified by the arbitration panel of its decision to award $8.2 million to Legacy. Interest on that amount accrues from the date of the award by the panel until the date of payment. ATP paid Legacy an initial payment of
$1.0 million on March 29, 2004. Legacy and ATP have agreed that the balance of the award will be paid on or before April 16, 2004.



Loss on Extinguishment of Debt



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.



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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.



Income Taxes



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 11 Income Taxes to the Consolidated Financial Statements.



Liquidity and Capital Resources



At December 31, 2003, we had a working capital deficit of approximately $46.4 million. In compliance with the definition of working capital in our credit
facility, we had a working capital deficit of approximately $40.2 million at December 31, 2003. This definition excludes current maturities of long-term debt, the current portion of assets and liabilities from derivatives and the current portion of
asset retirement obligations as well as including availability under the borrowing base. In the past, we have reported deficits in working capital at the end of a period. Such working capital deficits have principally been the result of accounts
payable related to ongoing development activities. Settlement of these payables has primarily been funded by cash flow from operations or, if necessary, by availability on our credit facility.



The working capital deficiency was primarily a result of the significant
capital required to develop our Matia/Cabrito and SS358 properties combined with unexpected delays in establishing first production from Helvellyn. There are two initial wells each at the Matia/Cabrito and SS358 developments. The well at Matia had
been completed and was producing at year end and the first well at SS358 started producing in March 2004. Another significant portion of our capital outlay was devoted to our first North Sea development, Helvellyn, originally scheduled to be placed
on production during the early part of 2003 after a successful well test in January 2003. However, due to delays that were beyond our control, expected first production was pushed back to the fall of 2003. At that time a down hole problem was
encountered ultimately requiring a side track of the well from approximately 7,500. The Helvellyn well was successfully completed and placed on production on February 10, 2004 and is currently producing at its original test rates of 30
MMcf/day (net). The remaining costs to be expended through the remainder of 2004 for these three major developments are projected to be approximately $13.5 million.



Further compounding our tight liquidity position was the decrease in production due to natural declines in our Gulf of
Mexico properties. Consequently, natural gas and oil production decreased approximately 35% from 2002 to 17.1 Bcfe. We received an average realized price of $3.82 per Mcfe, $0.97 less than the average sales price, due to our hedging position
throughout the year.



Our working capital position has
significantly improved as a result of the $19.5 million sale in 2004 of 25% of our interest in seven projects containing ten offshore blocks in the Gulf of Mexico, of which $10.5 million was received in February 2004 and $9.0 million will be
received in April 2004. In addition, we received net proceeds of approximately $56.0 million from the closing of our new Term Loan after repayment of borrowings under our prior credit facility. We anticipate that our working capital position
will be further improved by, among other things, increased production from our Matia/Cabrito and SS358 developments in the Gulf of Mexico and the recently completed Helvellyn well in the North Sea.



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However, future cash flows are subject to a number of variables including the level of production from
our properties, natural gas and oil prices and the impact, if any, of commitments and contingencies. Mandatory repayments under our new term loan are subject to variables including our EBITDA (as defined), changes in the prices of natural gas and
oil and changes in our oil and gas reserves. A material required reduction in the amount outstanding under the new credit facility would have a material negative impact on our cash flows and our ability to fund future obligations. No assurance can
be given that operations and other capital resources as described above will provide cash in sufficient amounts to maintain planned levels of operations and capital expenditures.



Cash Flows



|                            |  |                          |         |   |      |   |         |      |  |   |          |  
|--------------------------- |  | ------------------------ | ------- | - | ---- | - | ------- | ---- |  | - | -------- | -
|                            |  | Years Ended December 31, |        
|                            |  | 2003                     |         |   | 2002 |   |         | 2001 | 
|                            |  | (in thousands)           |        
|Cash provided by (used in): |  |                          |         |   |      |   |         |      |  |   |          |  
|Operating activities        |  | $                        | 51,009  |   |      | $ | 51,298  |      |  | $ | 41,356   |  
|Investing activities        |  |                          | (84,043 | ) |      |   | (35,167 | )    |  |   | (110,810 | )
|Financing activities        |  |                          | 30,654  |   |      |   | (14,481 | )    |  |   | 56,612   |  



Operating
activities. Net cash provided by operating activities was $51.0 million for the year ended December 31, 2003 compared to $51.3 million for the year ended December 31, 2002. Income before non-cash income and expenses was $27.1 million in 2003 and
$42.9 million in 2002. Changes in working capital provided $23.9 million in cash flows from operating activities in 2003 and $8.4 million in cash flows from operating activities in 2002. Income before non-cash income and expenses decreased between
years primarily due to the 35% decrease in production. Changes in working capital provided $23.9 million in cash flows in 2003 primarily due to an increase in capital projects late in 2003 as compared to 2002. The remaining changes in working
capital were due to timing of receipts and disbursements in the ordinary course of business.



Investing activities. Cash used in investing activities increased in 2003 to $84.0 million of which $83.8 million was for acquisition and
development activities. We incurred acquisition costs of $1.9 million in the Gulf of Mexico and developmental costs of $57.2 million and $24.7 million in the Gulf of Mexico and North Sea, respectively. In 2002, developmental capital expenditures in
the Gulf of Mexico and the North Sea were approximately $17.5 million and $16.4 million, respectively.



Financing activities. 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 credit facility. Cash used in financing
activities in 2002 represents net principal payments on our credit facility.



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



|                                                  |  |              |         |      |   |       
|------------------------------------------------- |  | ------------ | ------- | ---- | - | ------
|                                                  |  | December 31,
|                                                  |  | 2003         |         | 2002
|Credit facility                                   |  | $            | 115,409 |      | $ | 56,000
|Note payable, net of unamortized discount of $863 |  |              |        |      |   | 30,387
|                                                  |  |              |         |      |   |       
|Total debt                                        |  | $            | 115,409 |      | $ | 86,387
|                                                  |  |              |         |      |   |       



Credit Facility



On August 13, 2003, we entered into a material
modification of our prior credit facility in the form of an amendment, whereby the prior lenders were replaced and the terms were modified. Under the amended agreement, the borrowing base was redetermined and was established at $110.0 million. The
amended facility was secured by all of our U.S. assets in addition to approximately two-thirds of the capital stock of our foreign subsidiaries and was guaranteed by our wholly owned subsidiary, ATP Energy. The borrowing base was



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reviewed monthly and if our outstanding balance exceeded our borrowing base at any time, we were required to repay such excess immediately. The material
modification to the credit facility also extended the term of the facility to mature in August 2007.



On November 17, 2003 the credit facility was amended to modify certain debt covenants and contemplated expanding the borrowing base by up to $15.0
million, subject to terms mutually acceptable to both parties, by pledging the oil and gas properties in the UK Sector of the North Sea. On December 3, 2003, we executed a second amendment to our credit agreement, which implemented the $15.0 million
tranche maturing on February 16, 2004, established a borrowing base coverage test of 150% commencing February 16, 2004, modified several of the financial covenants and added new reporting and compliance covenants and events of default. We incurred
fees of $2.4 million in connection with the execution of the first and second amendments which have been reflected in the financial statements as of December 31, 2003, of which $0.8 million has been capitalized.



Advances under the original tranches of the credit facility bore interest at
the base rate plus a margin of 1.0% to 8.0%, depending on the amount outstanding. The average effective interest rate on these tranches was approximately 9% per annum. Advances under the $15.0 million tranche bore interest at the rate of 15% per
annum. The borrowing base was reviewed monthly and if our outstanding balance exceeded our borrowing base at any time, we were required to repay such excess immediately.



The terms of the agreement at December 31, 2003, including the amendments discussed above, required us to maintain certain
covenants including:



| |  | a current ratio, as defined in the agreement, of 0.35/1.0 through December 31, 2004 and 1.0/1.0 monthly thereafter;
| | - | -------------------------------------------------------------------------------------------------------------------



| |  | a consolidated debt coverage ratio which is not greater than 2.5/1.0 beginning October 31, 2003 with ranges from 1.6/1.0 to 3.0/1.0 monthly through August 31, 2004 and 1.6/1.0
monthly thereafter;
| | - | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  | a domestic debt coverage ratio which is not greater than 2.5/1.0 beginning October 31, 2003 with ranges from 1.9/1.0 to 3.0/1.0 monthly through January 31, 2005 and 1.9/1.0 monthly
thereafter;
| | - | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  | a consolidated and domestic interest coverage ratio which is not less than 3.0/1.0; and
| | - | ---------------------------------------------------------------------------------------



| |  | the requirement to maintain hedges on no less than 40% and no more than 80% of the next twelve months of forecasted production attributable to our proved producing reserves.
| | - | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------



As of December 31, 2003, we were not in
compliance with the minimum ratio of consolidated funded indebtedness to consolidated EBITDA requirement and the minimum consolidated EBITDA requirement. Waivers for non-compliance were obtained from the lender through execution of a third amendment
described below.



On February 23, 2004 we finalized the third
amendment to the credit agreement which was effective as of February 16, 2004. The third amendment extended the maturity of the $15.0 million tranche to January 31, 2005, reduced the borrowing base coverage test from 150% of the amounts outstanding
under our credit facility to 125%, extended the measuring date for such test from February 16, 2004 to April 30, 2004, imposed a new borrowing base reserve of $14.0 million at April 30, 2004 and provided waivers for the aforementioned non-compliance
of certain covenants. As consideration for the execution of the third amendment, we issued warrants to purchase 750,000 shares of our common stock, exercisable at a price of $6.75 per share. The $15.0 million tranche at December 31, 2003 has been
classified as long-term because of our intent and ability to refinance such amount on a long-term basis through the new term loan discussed below. On March 10, 2004 we executed a fourth amendment to extend to March 31, 2004 the time allowed to place
hedges on our North Sea production.



At December 31, 2002, we
had a $100.0 million senior-secured revolving credit facility which was secured by substantially all of our U.S. oil and gas properties, as well as by approximately two-thirds of the capital stock of our foreign subsidiaries and was guaranteed by
our wholly owned subsidiary, ATP Energy, Inc. The amount available for borrowing under the credit facility was limited to the loan value, as determined by the bank, of the oil and gas properties pledged under the facility. On August 13, 2003, this
credit facility was amended to replace the lenders and the outstanding balance was repaid.



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New Term Loan



On March 29, 2004, we entered into a new $185.0 million 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 (Term Loan). 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 and recognized a non-cash loss on extinguishment of debt of approximately $2.6 million in the first quarter of 2004. At closing, we received net proceeds of $56.0 million after repaying our previous credit
facility, the repurchase of 750,000 warrants associated with the previous credit facility and fees associated with the transaction.



The Term Loan was issued at an average interest rate of 10.8% and an original issue discount of 3% which was capitalized and will be amortized over
the life of the Term Loan. The $150.0 million term loan bears 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. Beginning in October 2004, the margin will increase from 8.5% to
9.5%. The $35.0 million term loan bears interest at the base rate plus a margin of 9.0% or LIBOR (with a 2% floor) plus a margin of 10.0% at the election of ATP.



In connection with the issuance of the Term Loan we paid fees and expenses of $8.2 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. We expect to record these fees and the fair market value of the warrants issued as debt financing costs in the first quarter
of 2004. These amounts will be amortized over the life of the Term Loan using the effective interest method.



The terms of Term Loan require us to maintain certain covenants which are tested on a quarterly basis beginning June 30, 2004. 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 EBITAX coverage ratio which is not greater than 3.25/1.0 at June 30, 2004, 3.0/1.0 at September 30, 2004 and December 31, 2004, 2.5/1.0 at each of the
quarters ending in 2005 and 2006 and 2.0/1.0 for each of the quarters ending thereafter;
| | - | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  | Consolidated EBITDAX to Interest Expense which is not less than 2.5/1.0 during 2004 and 3.0/1.0 thereafter;
| | - | -----------------------------------------------------------------------------------------------------------



| |  | PV10 of our Total Proved Developed Producing Oil and Gas Reserves to Net Debt of at least 0.5/1.0;
| | - | --------------------------------------------------------------------------------------------------



| |  | PV10 of our Total Proved Oil and Gas Reserves to Net Debt of at least 2.5/1.0;
| | - | ------------------------------------------------------------------------------



| |  | Net Debt to Proved Developed Oil and Gas Reserves of less than $2.50/Mcfe in 2004, $2.25/Mcfe in 2005 and $2.00 per Mcfe in 2006 and thereafter; and
| | - | ----------------------------------------------------------------------------------------------------------------------------------------------------



| |  | the requirement to maintain hedges on no less than 40% and no more than 80% of the next twelve months of forecasted production attributable to our proved producing reserves.
| | - | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------



We expect that we will be in compliance with the
financial covenants under our new Term Loan for the next twelve months. However, adverse changes in our expected production levels and reserves or material delays or cost overruns in 2004 could have a material adverse affect on our financial
condition and results of operations and result in our non-compliance with these covenants.



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Note Payable



In June 2001, we issued a note payable to a purchaser for a face principal amount of $31.3 million which was to mature in
June 2005 and bore interest at a fixed rate of 11.5% per annum. The note was secured by second priority liens on substantially all of our U.S. oil and gas properties and was subordinated in right of payment to our existing senior indebtedness. We
executed an agreement in connection with the note which contains conditions and restrictive provisions and requires the maintenance of certain financial ratios. The expected repayment premium was amortized to interest expense straight-line, over the
term of the note which approximated the effective interest method. The discount of $1.3 million was amortized to interest expense using the effective interest method. The resulting liability was included in other long-term liabilities on the
consolidated balance sheet at December 31, 2002. On August 14, 2003 and in connection with the execution of our amended credit agreement, we paid $36.1 million to the holder of the note payable to settle all outstanding obligations under the note
agreement. Those obligations included principal, accrued interest and early repayment premiums. Upon repayment of the note payable and replacement of the prior lenders of the credit facility, we recorded a $3.4 million total loss on the
extinguishment in third quarter of 2003, $0.9 million of which was related to non-cash deferred financing costs.



Recent Accounting Pronouncements



See Note 4, 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, 2003 (in thousands):



|                                |  |                        |         |                 |   |           |  |           |        |              |   |         |  |   |    
|------------------------------- |  | ---------------------- | ------- | --------------- | - | --------- |  | --------- | ------ | ------------ | - | ------- |  | - | ---
|                                |  | Payments Due By Period
|Contractual Obligation (1)      |  | Total                  |         | Less Than1 Year |   | 1-3 Years |  | 3-5 Years |        | After5 Years
|Long-term debt(2)               |  | $                      | 115,409 |                 | $ |          |  | $         | 15,000 |              | $ | 100,409 |  | $ |   
|Non-cancelable operating leases |  |                        | 2,514   |                 |   | 592       |  |           | 660    |              |   | 403     |  |   | 859
|Contractor commitment           |  |                        | 2,965   |                 |   | 2,965     |  |           |       |              |   |        |  |   |   
|                                |  |                        |         |                 |   |           |  |           |        |              |   |         |  |   |    
|Total contractual obligations   |  | $                      | 120,888 |                 | $ | 3,557     |  | $         | 15,660 |              | $ | 100,812 |  | $ | 859
|                                |  |                        |         |                 |   |           |  |           |        |              |   |         |  |   |    

---

|(1) | Does not include any amounts related to contingencies discussed below.
|--- | ----------------------------------------------------------------------



|(2) | Includes interest based on rates and monthly reduction amounts in effect at December 31, 2003.
|--- | ----------------------------------------------------------------------------------------------



Critical Accounting Policies and Estimates



Our consolidated financial statements are prepared in conformity with
accounting principles generally accepted 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.



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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.
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 determining the placement for a future developmental well location. 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 evaluated. Unproved properties are periodically assessed 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.



Oil and Gas Reserves



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



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Impairment Analysis



We perform an impairment analysis whenever events or changes in circumstances indicate that an assets carrying amount
may not be recoverable. An impairment allowance is provided on an unproved property when we determine that the property will not be developed. To determine if a depletable unit is impaired, we compare the carrying value of the depletable unit to the
undiscounted future net cash flows by applying managements estimates of future oil and gas prices to the estimated future production of oil and gas reserves over the economic life of the property. Future net cash flows are based upon our
independent reservoir engineers estimate of proved reserves. In addition, other factors such as probable and possible reserves are taken into consideration when justified by economic conditions and actual or planned drilling or other
development activities. For a property determined to be impaired, an impairment loss equal to the difference between the carrying value and the estimated fair value of the impaired property will be recognized. 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 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 5, 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 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.



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Price Risk Management Activities



We periodically enter into commodity derivative contracts and fixed-price physical contracts to manage our exposure to
natural gas and oil 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 natural gas and oil reference prices of these commodity derivatives contracts are based upon crude natural gas and oil futures, 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 natural
gas and oil 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 natural gas and oil revenues. As of December 31, 2003, we did not have any derivative contracts in place that qualified as a cash flow hedge.



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 No. 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. See Note 11 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.



42



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##### Table of Contents

Other Matters



A reporting issue has risen for companies in the extractive industries, including oil and gas companies regarding the application of certain provisions of
SFAS No. 141, Business Combinations (SFAS 141) and SFAS No. 142, Goodwill and Other Intangible Assets (SFAS 142). The issue is whether SFAS 142 requires registrants to classify the costs of
mineral rights associated with extracting oil and gas as intangible assets in the balance sheet, apart from other capitalized oil and gas property costs, and provide specific footnote disclosures. Historically, we have included the costs of mineral
rights associated with extracting oil and gas as a component of oil and gas properties. If it is ultimately determined that SFAS 142 requires oil and gas companies to classify costs of mineral rights associated with extracting oil and gas as a
separate intangible assets line item on the balance sheet, we would be required to reclassify approximately $4.4 million and $2.5 million at December 31, 2003 and 2002, respectively, out of oil and gas properties and into a separate intangible
assets line item. Our cash flows and results of operations would not be affected since such intangible assets would continue to be depleted and assessed for impairment in accordance with successful efforts accounting rules, as allowed by SFAS 142.
Further, we do not believe the classification of the costs of mineral rights associated with extracting oil and gas as intangible assets would have any impact on our compliance with covenants under our debt agreements.



We will continue to classify our oil and gas leasehold costs as tangible oil
and gas properties until further guidance is provided. We anticipate there will be no effect on our results of operations or cash flows.



|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 credit facility. 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 natural gas and oil. 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 bank credit facility is subject to periodic re-determination based in part on changing expectations of future prices.
Lower prices may also reduce the amount of natural gas and oil that we can economically produce. We currently sell a portion of our natural gas and oil 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 natural gas and oil production through a variety of financial and physical arrangements intended to support natural gas and oil 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 13 to the
Consolidated Financial Statements for additional information. We do not hold or issue derivative instruments for trading purposes.



43



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##### Table of Contents

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 natural gas and oil 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 2003, we hedged approximately 75% of our natural gas and oil 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
|------- | ------------------------------------------------------------------------------------



None.



|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, 2003. Based on such evaluation, such officers have concluded that, as of December 31, 2003, 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, 2003 that has
materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.



44



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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 1, 2004 (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
|-------- | --------------------------------------------------------------



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.



45



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##### Table of Contents

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



| | *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 Agreement
| | ---- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------



| | 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)
| | ---- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | 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)
| | ---- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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##### Table of Contents

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



| | *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
| | ------ | -----------------------------------------------------------------------------------------------------------------------------------------------------



| | *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.
| | ------ | -------------------------------------------------------------------------------------------------------------------------------------------------------



| | *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
| | ------ | -------------------------------------------------------------------------------------------------------------------------------------------------------------



| | 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 KPMG LLP
| | ----- | -------------------



| | *23.2 | Consent of Ryder Scott Company
| | ----- | ------------------------------



| | *23.3 | Consent of Troy-Ikoda Limited
| | ----- | -----------------------------



| | *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
|--- | -------------------



On November 21, 2003, the Company furnished Form 8-K, pursuant to Item 12, Results of Operations, under Item 9, Regulation FD Disclosure (in accordance
with the interim filing guidance for these items), a press release announcing its earnings results for the third quarter of 2003.



On February 27, 2004, the Company furnished Form 8-K, pursuant to Item 5, Other Events, under Item 9, Regulation FD Disclosure (in accordance with the
interim filing guidance for these items), announcing the terms of an amendment to its credit facility.



47



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##### Table of Contents

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. Senior Vice President and 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 29, 2004.



|                                                |  |                                                                                                                 
|----------------------------------------------- |  | ----------------------------------------------------------------------------------------------------------------
|Signature                                       |  | Title                                                                                                           
|                                                | 
|/s/    T. PAUL
BULMAHNT. Paul
Bulmahn           |  | Chairman, President and Director (Principal Executive Officer)                                                  
|                                                | 
|/s/    ALBERT L. REESE,
JR.Albert L. Reese,
Jr. |  | Senior Vice President and Chief Financial Officer (Principal Financial Officer and 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                                                                                                        



48



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##### Table of Contents

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS



|                                                                                                     |  |     
|---------------------------------------------------------------------------------------------------- |  | ----
|                                                                                                     |  | Page
|                                                                                                     | 
|ATP OIL & GAS CORPORATION AND SUBSIDIARIES                                                           |  |     
|                                                                                                     | 
|Independent Auditors Report                                                                         |  | F-2 
|                                                                                                     | 
|Consolidated Balance Sheets as of December 31, 2003 and 2002                                         |  | F-3 
|                                                                                                     | 
|Consolidated Statements of Operations for the years ended December 31, 2003, 2002 and 2001           |  | F-4 
|                                                                                                     | 
|Consolidated Statements of Comprehensive Loss for the years ended December 31, 2003, 2002 and 2001   |  | F-5 
|                                                                                                     | 
|Consolidated Statements of Cash Flows for the years ended December 31, 2003, 2002 and 2001           |  | F-6 
|                                                                                                     | 
|Consolidated Statements of Shareholders Equity for the years ended December 31, 2003, 2002 and 2001 |  | F-7 
|                                                                                                     | 
|Notes to Consolidated Financial Statements                                                           |  | F-8 



F-1



---

##### Table of Contents

INDEPENDENT AUDITORS REPORT



The Board of
Directors

ATP Oil & Gas Corporation:



We have audited the accompanying consolidated balance sheets of ATP Oil & Gas Corporation and subsidiaries as of December 31, 2003 and 2002, and the
related consolidated statements of operations, shareholders equity, comprehensive loss and cash flows for each of the years in the three-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 auditing standards generally accepted in the United States of America. Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An
audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.



In our opinion, 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 2002, and the results of their operations and their cash flows for each of the years in the
three-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, and effective January 1, 2001, the Company changed its method of accounting for derivative financial instruments.



KPMG LLP



Houston, Texas

March 29, 2004



F-2



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##### Table of Contents

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(In Thousands, Except Share Amounts)



|                                                                                |  |              |          |   |      |   |          |  
|------------------------------------------------------------------------------- |  | ------------ | -------- | - | ---- | - | -------- | -
|                                                                                |  | December 31, |         
|                                                                                |  | 2003         |          |   | 2002 |  
|Assets                                                                          |  |              |          |   |      |   |          |  
|Current assets:                                                                 |  |              |          |   |      |   |          |  
|Cash and cash equivalents                                                       |  | $            | 4,564    |   |      | $ | 6,944    |  
|Restricted cash                                                                 |  |              |         |   |      |   | 414      |  
|Accounts receivable (net of allowance of $1,266)                                |  |              | 15,874   |   |      |   | 24,998   |  
|Deferred tax asset                                                              |  |              |         |   |      |   | 1,628    |  
|Other current assets                                                            |  |              | 2,461    |   |      |   | 3,245    |  
|                                                                                |  |              |          |   |      |   |          |  
|Total current assets                                                            |  |              | 22,899   |   |      |   | 37,229   |  
|                                                                                |  |              |          |   |      |   |          |  
|Oil and gas properties (using the successful efforts method of accounting)      |  |              | 450,858  |   |      |   | 355,088  |  
|Less: Accumulated depletion, impairment and amortization                        |  |              | (261,733 | ) |      |   | (236,052 | )
|                                                                                |  |              |          |   |      |   |          |  
|Oil and gas properties, net                                                     |  |              | 189,125  |   |      |   | 119,036  |  
|                                                                                |  |              |          |   |      |   |          |  
|Furniture and fixtures (net of accumulated depreciation)                        |  |              | 666      |   |      |   | 810      |  
|Deferred tax asset (net of valuation allowance of $33,646 at December 31, 2003) |  |              |         |   |      |   | 21,580   |  
|Other assets, net                                                               |  |              | 4,995    |   |      |   | 3,400    |  
|                                                                                |  |              |          |   |      |   |          |  
|Total assets                                                                    |  | $            | 217,685  |   |      | $ | 182,055  |  
|                                                                                |  |              |          |   |      |   |          |  
|Liabilities and Shareholders Equity                                            |  |              |          |   |      |   |          |  
|Current liabilities:                                                            |  |              |          |   |      |   |          |  
|Accounts payable and accruals                                                   |  | $            | 63,054   |   |      | $ | 35,336   |  
|Current maturities of long-term debt                                            |  |              |         |   |      |   | 6,000    |  
|Asset retirement obligation                                                     |  |              | 6,102    |   |      |   |         |  
|Derivative liability                                                            |  |              | 166      |   |      |   | 9,592    |  
|                                                                                |  |              |          |   |      |   |          |  
|Total current liabilities                                                       |  |              | 69,322   |   |      |   | 50,928   |  
|Long-term debt                                                                  |  |              | 115,409  |   |      |   | 80,387   |  
|Asset retirement obligation                                                     |  |              | 15,005   |   |      |   |         |  
|Deferred revenue                                                                |  |              | 926      |   |      |   | 1,111    |  
|Other long-term liabilities and deferred obligations                            |  |              | 12,691   |   |      |   | 11,082   |  
|                                                                                |  |              |          |   |      |   |          |  
|Total liabilities                                                               |  |              | 213,353  |   |      |   | 143,508  |  
|                                                                                |  |              |          |   |      |   |          |  
|Commitments and Contingencies                                                   |  |              |          |   |      |   |          |  
|Shareholders equity:                                                           |  |              |          |   |      |   |          |  
|Preferred stock: $0.001 par value, 10,000,000 shares authorized; none issued    |  |              |         |   |      |   |         |  
|Common stock: $0.001 par value, 100,000,000 shares authorized                   |  |              | 25       |   |      |   | 20       |  
|Additional paid in capital                                                      |  |              | 92,277   |   |      |   | 81,087   |  
|Accumulated deficit                                                             |  |              | (90,115  | ) |      |   | (39,314  | )
|Accumulated other comprehensive income (loss)                                   |  |              | 3,056    |   |      |   | (2,335   | )
|Treasury stock, at cost                                                         |  |              | (911     | ) |      |   | (911     | )
|                                                                                |  |              |          |   |      |   |          |  
|Total shareholders equity                                                      |  |              | 4,332    |   |      |   | 38,547   |  
|                                                                                |  |              |          |   |      |   |          |  
|Total liabilities and shareholders equity                                      |  | $            | 217,685  |   |      | $ | 182,055  |  
|                                                                                |  |              |          |   |      |   |          |  



See accompanying notes
to the consolidated financial statements.



F-3



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##### Table of Contents

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(In Thousands, Except Per Share Amounts)



|                                                                                 |  |                          |         |   |      |   |         |      |  |   |         |  
|-------------------------------------------------------------------------------- |  | ------------------------ | ------- | - | ---- | - | ------- | ---- |  | - | ------- | -
|                                                                                 |  | Years Ended December 31, |        
|                                                                                 |  | 2003                     |         |   | 2002 |   |         | 2001 | 
|Revenues:                                                                        |  |                          |         |   |      |   |         |      |  |   |         |  
|Oil and gas production                                                           |  | $                        | 70,151  |   |      | $ | 80,017  |      |  | $ | 87,873  |  
|                                                                                 |  |                          |         |   |      |   |         |      |  |   |         |  
|Costs and operating expenses:                                                    |  |                          |         |   |      |   |         |      |  |   |         |  
|Lease operating expenses                                                         |  |                          | 17,173  |   |      |   | 16,764  |      |  |   | 14,806  |  
|Geological and geophysical expenses                                              |  |                          | 1,358   |   |      |   | 154     |      |  |   | 1,068   |  
|General and administrative expenses                                              |  |                          | 12,209  |   |      |   | 10,037  |      |  |   | 9,806   |  
|Credit facility expenses                                                         |  |                          | 1,990   |   |      |   | 250     |      |  |   | 175     |  
|Non-cash compensation expense (general and administrative)                       |  |                          | (39     | ) |      |   | 595     |      |  |   | 3,364   |  
|Depreciation, depletion and amortization                                         |  |                          | 29,378  |   |      |   | 43,390  |      |  |   | 53,428  |  
|Impairment of oil and gas properties                                             |  |                          | 11,670  |   |      |   | 6,844   |      |  |   | 24,891  |  
|Accretion expense                                                                |  |                          | 2,752   |   |      |   |        |      |  |   |        |  
|Loss on abandonment                                                              |  |                          | 4,973   |   |      |   |        |      |  |   |        |  
|Loss on unsuccessful property acquisition                                        |  |                          | 8,192   |   |      |   |        |      |  |   | 3,147   |  
|                                                                                 |  |                          |         |   |      |   |         |      |  |   |         |  
|                                                                                 |  |                          | 89,656  |   |      |   | 78,034  |      |  |   | 110,685 |  
|                                                                                 |  |                          |         |   |      |   |         |      |  |   |         |  
|Income (loss) from operations                                                    |  |                          | (19,505 | ) |      |   | 1,983   |      |  |   | (22,812 | )
|                                                                                 |  |                          |         |   |      |   |         |      |  |   |         |  
|Other income (expense):                                                          |  |                          |         |   |      |   |         |      |  |   |         |  
|Interest income                                                                  |  |                          | 52      |   |      |   | 73      |      |  |   | 884     |  
|Interest expense                                                                 |  |                          | (9,678  | ) |      |   | (10,418 | )    |  |   | (10,039 | )
|Loss on extinguishment of debt                                                   |  |                          | (3,352  | ) |      |   |        |      |  |   | (926    | )
|Other                                                                            |  |                          | 2,244   |   |      |   | 1,081   |      |  |   |        |  
|                                                                                 |  |                          |         |   |      |   |         |      |  |   |         |  
|                                                                                 |  |                          | (10,734 | ) |      |   | (9,264  | )    |  |   | (10,081 | )
|                                                                                 |  |                          |         |   |      |   |         |      |  |   |         |  
|Loss before income taxes and cumulative effect of change in accounting principle |  |                          | (30,239 | ) |      |   | (7,281  | )    |  |   | (32,893 | )
|Income tax (expense) benefit                                                     |  |                          | (21,224 | ) |      |   | 2,581   |      |  |   | 11,510  |  
|                                                                                 |  |                          |         |   |      |   |         |      |  |   |         |  
|Loss before cumulative effect of change in accounting principle                  |  |                          | (51,463 | ) |      |   | (4,700  | )    |  |   | (21,383 | )
|Cumulative effect of change in accounting principle, net of tax                  |  |                          | 662     |   |      |   |        |      |  |   |        |  
|                                                                                 |  |                          |         |   |      |   |         |      |  |   |         |  
|Net loss                                                                         |  | $                        | (50,801 | ) |      | $ | (4,700  | )    |  | $ | (21,383 | )
|                                                                                 |  |                          |         |   |      |   |         |      |  |   |         |  
|Basic and diluted loss per common share:                                         |  |                          |         |   |      |   |         |      |  |   |         |  
|Loss before cumulative effect of change in accounting principle                  |  | $                        | (2.24   | ) |      | $ | (0.23   | )    |  | $ | (1.09   | )
|Cumulative effect of change in accounting principle, net of tax                  |  |                          | 0.03    |   |      |   |        |      |  |   |        |  
|                                                                                 |  |                          |         |   |      |   |         |      |  |   |         |  
|Net loss per common share                                                        |  | $                        | (2.21   | ) |      | $ | (0.23   | )    |  | $ | (1.09   | )
|                                                                                 |  |                          |         |   |      |   |         |      |  |   |         |  
|Weighted average number of common shares:                                        |  |                          |         |   |      |   |         |      |  |   |         |  
|Basic and diluted                                                                |  |                          | 22,975  |   |      |   | 20,315  |      |  |   | 19,704  |  
|                                                                                 |  |                          |         |   |      |   |         |      |  |   |         |  



See accompanying notes
to the consolidated financial statements.



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ATP OIL & GAS CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS

(In Thousands)



|                                                                |  |                          |         |   |      |   |        |      |  |   |         |  
|--------------------------------------------------------------- |  | ------------------------ | ------- | - | ---- | - | ------ | ---- |  | - | ------- | -
|                                                                |  | Years Ended December 31, |        
|                                                                |  | 2003                     |         |   | 2002 |   |        | 2001 | 
|Net loss                                                        |  | $                        | (50,801 | ) |      | $ | (4,700 | )    |  | $ | (21,383 | )
|                                                                |  |                          |         |   |      |   |        |      |  |   |         |  
|Other comprehensive income (loss):                              |  |                          |         |   |      |   |        |      |  |   |         |  
|Cumulative effect of change in accounting principle, net of tax |  |                          |        |   |      |   |       |      |  |   | (34,252 | )
|Reclassification adjustment for settled contracts, net of tax   |  |                          | (627    | ) |      |   | 627    |      |  |   | 34,252  |  
|Change in fair value of outstanding hedge positions, net of tax |  |                          | 3,651   |   |      |   | (3,651 | )    |  |   |        |  
|Foreign currency translation adjustment                         |  |                          | 2,367   |   |      |   | 670    |      |  |   | 19      |  
|                                                                |  |                          |         |   |      |   |        |      |  |   |         |  
|Other comprehensive income (loss)                               |  |                          | 5,391   |   |      |   | (2,354 | )    |  |   | 19      |  
|                                                                |  |                          |         |   |      |   |        |      |  |   |         |  
|Comprehensive loss                                              |  | $                        | (45,410 | ) |      | $ | (7,054 | )    |  | $ | (21,364 | )
|                                                                |  |                          |         |   |      |   |        |      |  |   |         |  



See accompanying notes
to the consolidated financial statements.



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ATP OIL & GAS CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In Thousands)



|                                                                                 |  |                          |          |   |      |   |         |      |  |   |          |  
|-------------------------------------------------------------------------------- |  | ------------------------ | -------- | - | ---- | - | ------- | ---- |  | - | -------- | -
|                                                                                 |  | Years Ended December 31, |         
|                                                                                 |  | 2003                     |          |   | 2002 |   |         | 2001 | 
|Cash flows from operating activities:                                            |  |                          |          |   |      |   |         |      |  |   |          |  
|Net loss                                                                         |  | $                        | (50,801  | ) |      | $ | (4,700  | )    |  | $ | (21,383  | )
|Adjustments to reconcile net loss to net cash provided by operating activities  |  |                          |          |   |      |   |         |      |  |   |          |  
|Depreciation, depletion and amortization                                         |  |                          | 29,378   |   |      |   | 43,390  |      |  |   | 53,428   |  
|Impairment of oil and gas properties                                             |  |                          | 11,670   |   |      |   | 6,844   |      |  |   | 24,891   |  
|Accretion of asset retirement obligation                                         |  |                          | 2,752    |   |      |   |        |      |  |   |         |  
|Amortization of deferred financing costs                                         |  |                          | 1,395    |   |      |   | 1,429   |      |  |   | 797      |  
|Changes in other comprehensive income (loss) related to derivative activities    |  |                          | 3,024    |   |      |   | (3,024  | )    |  |   |         |  
|Loss on extinguishment of debt                                                   |  |                          | 883      |   |      |   |        |      |  |   | 926      |  
|Deferred tax assets                                                              |  |                          | 21,224   |   |      |   | (2,352  | )    |  |   | (11,576  | )
|Non-cash compensation expense (general and administrative)                       |  |                          | (39      | ) |      |   | 595     |      |  |   | 3,364    |  
|Cumulative effect of change in accounting principle                              |  |                          | (662     | ) |      |   |        |      |  |   |         |  
|Foreign currency translation adjustment                                          |  |                          | 2,367    |   |      |   | 670     |      |  |   | 19       |  
|Accrued interest and credit facility expenses                                    |  |                          | 5,567    |   |      |   |        |      |  |   |         |  
|Other non-cash items                                                             |  |                          | 345      |   |      |   | 76      |      |  |   | 177      |  
|Changes in assets and liabilities                                               |  |                          |          |   |      |   |         |      |  |   |          |  
|Accounts receivable and other                                                    |  |                          | 9,775    |   |      |   | (14,659 | )    |  |   | 23,014   |  
|Restricted cash                                                                  |  |                          | 414      |   |      |   | (414    | )    |  |   |         |  
|Net (assets) liabilities from risk management activities                         |  |                          | (7,798   | ) |      |   | 9,229   |      |  |   | (8,513   | )
|Accounts payable and accruals                                                    |  |                          | 20,091   |   |      |   | 8,910   |      |  |   | (23,436  | )
|Other long-term assets                                                           |  |                          |         |   |      |   | (1,525  | )    |  |   | (4,183   | )
|Other long-term liabilities and deferred credits                                 |  |                          | 1,424    |   |      |   | 6,829   |      |  |   | 3,831    |  
|                                                                                 |  |                          |          |   |      |   |         |      |  |   |          |  
|Net cash provided by operating activities                                        |  |                          | 51,009   |   |      |   | 51,298  |      |  |   | 41,356   |  
|                                                                                 |  |                          |          |   |      |   |         |      |  |   |          |  
|Cash flows from investing activities:                                            |  |                          |          |   |      |   |         |      |  |   |          |  
|Additions and acquisitions of oil and gas properties                             |  |                          | (83,803  | ) |      |   | (34,873 | )    |  |   | (110,264 | )
|Additions to furniture and fixtures                                              |  |                          | (240     | ) |      |   | (294    | )    |  |   | (546     | )
|                                                                                 |  |                          |          |   |      |   |         |      |  |   |          |  
|Net cash used in investing activities                                            |  |                          | (84,043  | ) |      |   | (35,167 | )    |  |   | (110,810 | )
|                                                                                 |  |                          |          |   |      |   |         |      |  |   |          |  
|Cash flows from financing activities:                                            |  |                          |          |   |      |   |         |      |  |   |          |  
|Proceeds from initial public offering, net of offering costs                     |  |                          |         |   |      |   |        |      |  |   | 77,437   |  
|Net proceeds from secondary offering                                             |  |                          | 10,879   |   |      |   |        |      |  |   |         |  
|Proceeds from long-term debt                                                     |  |                          | 127,168  |   |      |   | 1,000   |      |  |   | 119,000  |  
|Payments of long-term debt                                                       |  |                          | (103,921 | ) |      |   | (15,000 | )    |  |   | (46,750  | )
|Proceeds from non-recourse borrowings                                            |  |                          |         |   |      |   |        |      |  |   | 3,359    |  
|Payments of non-recourse borrowings                                              |  |                          |         |   |      |   |        |      |  |   | (92,138  | )
|Deferred financing costs                                                         |  |                          | (3,827   | ) |      |   | (495    | )    |  |   | (3,586   | )
|Treasury stock purchases                                                         |  |                          |         |   |      |   |        |      |  |   | (911     | )
|Other                                                                            |  |                          | 355      |   |      |   | 14      |      |  |   | 201      |  
|                                                                                 |  |                          |          |   |      |   |         |      |  |   |          |  
|Net cash provided by (used in) financing activities                              |  |                          | 30,654   |   |      |   | (14,481 | )    |  |   | 56,612   |  
|                                                                                 |  |                          |          |   |      |   |         |      |  |   |          |  
|Increase (decrease) in cash and cash equivalents                                 |  |                          | (2,380   | ) |      |   | 1,650   |      |  |   | (12,842  | )
|Cash and cash equivalents, beginning of period                                   |  |                          | 6,944    |   |      |   | 5,294   |      |  |   | 18,136   |  
|                                                                                 |  |                          |          |   |      |   |         |      |  |   |          |  
|Cash and cash equivalents, end of period                                         |  | $                        | 4,564    |   |      | $ | 6,944   |      |  | $ | 5,294    |  
|                                                                                 |  |                          |          |   |      |   |         |      |  |   |          |  
|Supplemental disclosures of cash flow information:                               |  |                          |          |   |      |   |         |      |  |   |          |  
|Cash paid during the year for interest                                           |  | $                        | 3,187    |   |      | $ | 7,361   |      |  | $ | 4,177    |  
|                                                                                 |  |                          |          |   |      |   |         |      |  |   |          |  



See accompanying notes
to the consolidated financial statements.



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ATP OIL & GAS CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF SHAREHOLDERS EQUITY

(In Thousands)



|                                  |  |        |  |        |         |   |        |        |        |   |         |        |  |        |        |  |   |         |  
|--------------------------------- |  | ------ |  | ------ | ------- | - | ------ | ------ | ------ | - | ------- | ------ |  | ------ | ------ |  | - | ------- | -
|                                  |  | 2003   |  |        | 2002    |   |        | 2001   |       
|                                  |  | Shares |  | Amount |         |   | Shares |        | Amount |   |         | Shares |  |        | Amount | 
|Common Stock                      |  |        |  |        |         |   |        |        |        |   |         |        |  |        |        |  |   |         |  
|Balance, beginning of year        |  | 20,322 |  | $      | 20      |   |        | 20,313 |        | $ | 20      |        |  | 14,286 |        |  | $ | 14      |  
|Issuances of common stock         |  |        |  |        |         |   |        |        |        |   |         |        |  |        |        |  |   |         |  
|Initial public offering           |  |       |  |        |        |   |        |       |        |   |        |        |  | 6,000  |        |  |   | 6       |  
|Secondary offering                |  | 4,000  |  |        | 4       |   |        |       |        |   |        |        |  |       |        |  |   |        |  
|Exercise of stock options         |  | 198    |  |        | 1       |   |        | 9      |        |   |        |        |  | 103    |        |  |   |        |  
|Purchase of treasury stock        |  |       |  |        |        |   |        |       |        |   |        |        |  | (76    | )      |  |   |        |  
|                                  |  |        |  |        |         |   |        |        |        |   |         |        |  |        |        |  |   |         |  
|Balance, end of year              |  | 24,520 |  | $      | 25      |   |        | 20,322 |        | $ | 20      |        |  | 20,313 |        |  | $ | 20      |  
|                                  |  |        |  |        |         |   |        |        |        |   |         |        |  |        |        |  |   |         |  
|Paid-in Capital                   |  |        |  |        |         |   |        |        |        |   |         |        |  |        |        |  |   |         |  
|Balance, beginning of year        |  |        |  | $      | 81,087  |   |        |        |        | $ | 80,478  |        |  |        |        |  | $ | 38      |  
|Issuances of common stock         |  |        |  |        |         |   |        |        |        |   |         |        |  |        |        |  |   |         |  
|Initial public offering           |  |        |  |        |        |   |        |        |        |   |        |        |  |        |        |  |   | 76,809  |  
|Secondary offering                |  |        |  |        | 10,875  |   |        |        |        |   |        |        |  |        |        |  |   |        |  
|Exercise of stock options         |  |        |  |        | 354     |   |        |        |        |   | 14      |        |  |        |        |  |   | 267     |  
|Non-cash compensation expense     |  |        |  |        | (39     | ) |        |        |        |   | 595     |        |  |        |        |  |   | 3,364   |  
|                                  |  |        |  |        |         |   |        |        |        |   |         |        |  |        |        |  |   |         |  
|Balance, end of year              |  |        |  | $      | 92,277  |   |        |        |        | $ | 81,087  |        |  |        |        |  | $ | 80,478  |  
|                                  |  |        |  |        |         |   |        |        |        |   |         |        |  |        |        |  |   |         |  
|Accumulated Deficit               |  |        |  |        |         |   |        |        |        |   |         |        |  |        |        |  |   |         |  
|Balance, beginning of year        |  |        |  | $      | (39,314 | ) |        |        |        | $ | (34,614 | )      |  |        |        |  | $ | (13,231 | )
|Net loss                          |  |        |  |        | (50,801 | ) |        |        |        |   | (4,700  | )      |  |        |        |  |   | (21,383 | )
|                                  |  |        |  |        |         |   |        |        |        |   |         |        |  |        |        |  |   |         |  
|Balance, end of year              |  |        |  | $      | (90,115 | ) |        |        |        | $ | (39,314 | )      |  |        |        |  | $ | (34,614 | )
|                                  |  |        |  |        |         |   |        |        |        |   |         |        |  |        |        |  |   |         |  
|Accumulated Other                 |  |        |  |        |         |   |        |        |        |   |         |        |  |        |        |  |   |         |  
|Comprehensive Income (Loss)       |  |        |  |        |         |   |        |        |        |   |         |        |  |        |        |  |   |         |  
|Balance, beginning of year        |  |        |  | $      | (2,335  | ) |        |        |        | $ | 19      |        |  |        |        |  | $ |        |  
|Other comprehensive income (loss) |  |        |  |        | 5,391   |   |        |        |        |   | (2,354  | )      |  |        |        |  |   | 19      |  
|                                  |  |        |  |        |         |   |        |        |        |   |         |        |  |        |        |  |   |         |  
|Balance, end of year              |  |        |  | $      | 3,056   |   |        |        |        | $ | (2,335  | )      |  |        |        |  | $ | 19      |  
|                                  |  |        |  |        |         |   |        |        |        |   |         |        |  |        |        |  |   |         |  
|Treasury Stock                    |  |        |  |        |         |   |        |        |        |   |         |        |  |        |        |  |   |         |  
|Balance, beginning of year        |  | 76     |  | $      | (911    | ) |        | 76     |        | $ | (911    | )      |  |       |        |  | $ |        |  
|Purchase of treasury stock        |  |       |  |        |        |   |        |       |        |   |        |        |  | 76     |        |  |   | (911    | )
|                                  |  |        |  |        |         |   |        |        |        |   |         |        |  |        |        |  |   |         |  
|Balance, end of year              |  | 76     |  | $      | (911    | ) |        | 76     |        | $ | (911    | )      |  | 76     |        |  | $ | (911    | )
|                                  |  |        |  |        |         |   |        |        |        |   |         |        |  |        |        |  |   |         |  
|Total Shareholders Equity        |  |        |  | $      | 4,332   |   |        |        |        | $ | 38,547  |        |  |        |        |  | $ | 44,992  |  
|                                  |  |        |  |        |         |   |        |        |        |   |         |        |  |        |        |  |   |         |  



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 natural gas and oil 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 natural gas and oil properties with proved undeveloped reserves that are economically attractive to us but are not strategic to major or exploration-oriented independent oil and gas companies.



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 significant 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  Liquidity



At December 31, 2003,
we had a working capital deficit of approximately $46.4 million. In compliance with the definition of working capital in our credit facility, we had a working capital deficit of approximately $40.2 million at December 31, 2003. This definition
excludes current maturities of long-term debt, the current portion of assets and liabilities from derivatives and the current portion of asset retirement obligations as well as including availability under the borrowing base. In the past, we have
reported deficits in working capital at the end of a period. Such working capital deficits have principally been the result of accounts payable related to ongoing development activities. Settlement of these payables has primarily been funded by cash
flow from operations or, if necessary, by availability on our credit facility.



Our working capital position has significantly improved as a result of the $19.5 million sale of 25% of our interest in seven projects containing ten offshore blocks in the Gulf of Mexico, of which $10.5 million was
received in February 2004 and $9.0 million will be received in April 2004. In addition, we received net proceeds of approximately $56.0 million from the closing of our new Term Loan. We anticipate that our working capital position will be further
improved by, among other things, increased production from our Matia/Cabrito and SS358 developments in the Gulf of Mexico and the recently completed Helvellyn well in the North Sea.



However, future cash flows are subject to a number of variables including the level of production from our properties,
natural gas and oil prices and the impact, if any, of commitments and contingencies. Mandatory repayments under our new term loan are subject to variables including our EBITDAX (as defined), changes in the prices of natural gas and oil and changes
in our oil and gas reserves. A material required reduction in the amount outstanding under the new credit facility would have a material negative impact on our cash flows and our ability to fund future obligations. No assurance can be given that
operations and other capital resources as described above will provide cash in sufficient amounts to maintain planned levels of operations and capital expenditures.



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ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS



Note 3  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.



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 data are generally charged to expense unless the costs can be specifically attributed to determining the placement for a future developmental well location. Expenditures for repairs and maintenance are charged to expense as incurred;
renewals and betterments are capitalized. The costs and related accumulated depreciation, depletion, and amortization of properties sold or otherwise retired are eliminated from the accounts, and gains or losses on disposition are reflected in the
statements of operations.



We perform a review for impairment
of proved oil and gas properties on a depletable unit basis when circumstances suggest there is a need for such a review 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 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 impairments during the years ended December 31, 2003, 2002 and 2001 of $11.7 million, $6.8 million and $24.9 million, respectively, primarily due to either depressed natural gas and oil prices,
unfavorable operating performance or downward revisions of recoverable reserves or a combination of all.



Unproved oil and gas properties are periodically assessed 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, 2003, no impairments have been recorded on unproved properties.



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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 2001.



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, |      
|                                |  | 2003         |       |   | 2002 |  
|Debt financing costs            |  | $            | 3,827 |   |      | $ | 3,767  |  
|Spare parts inventory           |  |              | 1,762 |   |      |   | 1,000  |  
|Long-term portion of receivable |  |              |      |   |      |   | 629    |  
|Other                           |  |              | 10    |   |      |   | 10     |  
|                                |  |              |       |   |      |   |        |  
|                                |  |              | 5,599 |   |      |   | 5,406  |  
|Accumulated amortization        |  |              | (604  | ) |      |   | (2,006 | )
|                                |  |              |       |   |      |   |        |  
|                                |  | $            | 4,995 |   |      | $ | 3,400  |  
|                                |  |              |       |   |      |   |        |  



Costs incurred in
connection with the issuance of long-term debt are capitalized and amortized to interest expense over the term of the related agreement, using the effective interest or straight-line method (which approximates the effective interest method).



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



Revenue Recognition. We use the sales method of accounting for natural gas and oil 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.



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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, 2003, revenues from four purchasers accounted for 36%, 35%, 15% and 11%, respectively, for 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. For the year ended December 31, 2001, revenues from three purchasers accounted for 53%, 17% and 10% each 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 are included in income.



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 Loss.Comprehensive loss is net loss, plus certain other items that are recorded directly to shareholders equity. In 2003, 2002
and 2001, comprehensive loss was $45.4 million, $7.1 million and $21.4 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.



In December 2002, the Financial Accounting Standards Board (FASB) issued SFAS No. 148, Accounting for Stock-Based Compensation-Transition and Disclosure (SFAS 148) which
amended the transition and disclosure provisions of SFAS 123. Among other items, SFAS 148 allows companies adopting the fair value of the standards to utilize one of three alternative transition methods. To date, we have not adopted the fair value
provisions of the standard utilizing any of the transition methods of SFAS 148. The FASB currently is working on a project to develop a new standard for accounting for stock-based compensation. Tentative decisions by the FASB indicate that expensing
of stock options will be required beginning January 1, 2005. The FASB expects to issue an exposure draft, which will be subject to public comment, in first half of 2004 and issue its final standard in the second half of 2004. See Note 9 for further
information on our stock-based compensation plans.



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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, |        
|                                                                                                                                  |  | 2003                     |         |   | 2002 |   |        | 2001 | 
|Net loss before cumulative effect of change in accounting principle, as reported                                                  |  | $                        | (51,463 | ) |      | $ | (4,700 | )    |  | $ | (21,383 | )
|Add: Stock based employee compensation expense included in reported net loss, determined under APB 25, net of related tax
effects |  |                          | (26     | ) |      |   | 387    |      |  |   | 2,187   |  
|Deduct: Total stock based employee compensation Expense determined under fair value for all awards, net of related tax effects    |  |                          | (1,013  | ) |      |   | (2,673 | )    |  |   | (3,517  | )
|                                                                                                                                  |  |                          |         |   |      |   |        |      |  |   |         |  
|Pro forma net loss before cumulative effect of change in accounting principle                                                     |  | $                        | (52,502 | ) |      | $ | (6,986 | )    |  | $ | (22,713 | )
|                                                                                                                                  |  |                          |         |   |      |   |        |      |  |   |         |  
|Earnings per share:                                                                                                               |  |                          |         |   |      |   |        |      |  |   |         |  
|Basic and diluted  as reported                                                                                                   |  | $                        | (2.24   | ) |      | $ | (0.23  | )    |  | $ | (1.09   | )
|Basic and diluted  pro forma                                                                                                     |  | $                        | (2.29   | ) |      | $ | (0.34  | )    |  | $ | (1.15   | )



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.



The following table provides information on our debt (in thousands):



|             |  |                 |         |            |   |                 |  |            |        |  |   |       
|------------ |  | --------------- | ------- | ---------- | - | --------------- |  | ---------- | ------ |  | - | ------
|             |  | December 31,   
|             |  | 2003            |         | 2002      
|             |  | Carrying Amount |         | Fair Value |   | Carrying Amount |  | Fair Value
|Bank debt    |  | $               | 115,409 |            | $ | 115,409         |  | $          | 56,000 |  | $ | 56,000
|Note payable |  |                 |        |            |   |                |  |            | 30,387 |  |   | 34,376
|             |  |                 |         |            |   |                 |  |            |        |  |   |       
|Total        |  | $               | 115,409 |            | $ | 115,409         |  | $          | 86,387 |  | $ | 90,376
|             |  |                 |         |            |   |                 |  |            |        |  |   |       



Bank debt is variable
rate debt and as such, approximates fair values, as interest rates are variable based on prevailing market rates. Our note payable was a fixed rate note and the fair value was determined by discounting the future payments using our incremental
borrowing rate, based on the differential between the fixed interest rate and interest rates of long-term treasury securities at the date of the borrowing and the balance sheet date.



Derivative instruments.From time to time, we utilize options, swaps and collars to manage our commodity price risk.
On January 1, 2001, we adopted SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities (SFAS 133), which established new accounting and reporting requirements 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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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS



Note 4 Recently Issued Accounting Pronouncements



In April 2002, the FASB issued SFAS No. 145, Rescission of FASB
Statements No. 4, No. 44, and No. 64, Amendment of FASB Statement No. 13, and Technical Corrections (SFAS 145). Among other things, SFAS 145 requires gains and losses from early extinguishment of debt to be included in income
from continuing operations instead of being classified as extraordinary items as previously required by generally accepted accounting principles. SFAS 145 is effective for fiscal years beginning after May 15, 2002 and we adopted the statement on
January 1, 2003. Any gain or loss on early extinguishment of debt that was classified as an extraordinary item in periods prior to adoption has been reclassified into income from continuing operations. The adoption of SFAS 145 required the $0.6
million (net of tax) of extraordinary loss for the year ended December 31, 2001 to be reclassified to other income (expense) and income tax benefit.



In June 2002, the FASB issued SFAS No. 146, Accounting for Costs Associated with Exit or Disposal Activities (SFAS 146).
SFAS 146 addresses financial accounting and reporting for costs associated with exit or disposal activities and nullified Emerging Issues Task Force Issue No. 94-3, Liability Recognition for Certain Employee Termination Benefits and Other
Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring. SFAS 146 requires that a liability for a cost associated with an exit or disposal activity be recognized when the liability is incurred. SFAS 146 also
establishes that fair value is the objective for initial measurement of the liability. The provisions of this statement are effective for exit or disposal activities that are initiated after December 31, 2002. We adopted the provisions of SFAS 146
on January 1, 2003 and the adoption did not have an effect on our financial position or results of operations.



In November 2002, the FASB issued FASB Interpretation No. 45 Guarantors Accounting and Disclosure Requirements for Guarantees, Including
Indirect Guarantee of Indebtedness of Others (FIN 45). FIN 45 requires that upon issuance of a guarantee, the guarantor must recognize a liability for the fair value of the obligation it assumes under that guarantee. FIN
45s provisions for initial recognition and measurement should be applied on a prospective basis to guarantees issued or modified after December 31, 2002. The disclosure provisions apply to financial statements for periods ending after December
15, 2002. We do not currently have guarantees that require disclosure. Adoption of this statement did not have a material effect on our financial position or results of operations.



In January 2003, the FASB issued FASB Interpretation No. 46, Consolidation of Variable Interest Entities
(FIN 46). FIN 46 requires a company to consolidate a variable interest entity if it is designated as the primary beneficiary of that entity even if the company does not have a majority of voting interest. A variable interest entity is
generally defined as an entity where its equity is unable to finance its activities or where the owners of the entity lack the risk and rewards of ownership. The provisions of FIN 46 apply immediately to variable interest entities created after
January 31, 2003 and to variable interest entities in which an enterprise obtains an interest after that date. The adoption of FIN 46 did not have an effect on our financial position or results of operations.



In April 2003, the FASB issued SFAS No. 149, Amendment of Statement
133 on Derivative Instruments and Hedging Activities (SFAS 149). SFAS 149 amends and clarifies accounting for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging
activities under SFAS 133. SFAS 149 clarifies under what circumstances a contract with an initial net investment meets the characteristic of a derivative and when a derivative contains a financing component that warrants special reporting in the
statement of cash flows. This statement is generally effective for contracts entered into or modified after June 30, 2003 and upon adoption, did not have an impact on our financial position or results of operations.



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In May 2003, the FASB issued SFAS No. 150, Accounting for Certain Financial Instruments with
Characteristics of both Liabilities and Equity (SFAS 150). This statement establishes standards for how an issuer classifies and measures in its statement of financial position certain financial instruments with characteristics
of both liabilities and equity. In accordance with the standard, financial instruments that embody obligations for the issuer are required to be classified as liabilities. This statement was effective for financial instruments entered into or
modified after May 31, 2003, and was adopted on July 1, 2003. As we have no such instruments, the adoption of this statement did not have an impact on our statement of financial position or results of operations.



Emerging Issues Task Force (EITF) Issue No. 02-03,
Recognition and Reporting of Gains and Losses on Energy Trading Contracts under EITF Issues No. 98-10, Accounting for Contracts Involved in Energy Trading and Risk Management Activities was issued in June 2002. EITF Issue No.
02-03 addresses certain issues related to energy trading activities, including (a) gross versus net presentation in the income statement, (b) whether the initial fair value of an energy trading contract can be other than the price at which it was
exchanged, and (c) accounting for inventory utilized in energy trading activities. We have presented the activities of ATP Energy in the statement of operations for all periods on a net rather than a gross basis as a component of oil and gas
revenues. The remaining provisions effective January 1, 2003 had no impact on our financial position or results of operations. For more information regarding the ATP Energy transaction, see Note 14.



A reporting issue has risen for companies in the extractive industries,
including oil and gas companies regarding the application of certain provisions of SFAS No. 141, Business Combinations (SFAS 141) and SFAS No. 142, Goodwill and Other Intangible Assets (SFAS
142). The issue is whether SFAS 142 requires registrants to classify the costs of mineral rights associated with extracting oil and gas as intangible assets in the balance sheet, apart from other capitalized oil and gas property costs, and
provide specific footnote disclosures. Historically, we have included the costs of mineral rights associated with extracting oil and gas as a component of oil and gas properties. If it is ultimately determined that SFAS 142 requires oil and gas
companies to classify costs of mineral rights associated with extracting oil and gas as a separate intangible assets line item on the balance sheet, we would be required to reclassify approximately $4.4 million and $2.5 million at December 31, 2003
and 2002, respectively, out of oil and gas properties and into a separate intangible assets line item. Our cash flows and results of operations would not be affected since such intangible assets would continue to be depleted and assessed for
impairment in accordance with successful efforts accounting rules, as allowed by SFAS 142. Further, we do not believe the classification of the costs of mineral rights associated with extracting oil and gas as intangible assets would have any impact
on our compliance with covenants under our debt agreements.



We
will continue to classify our oil and gas leasehold costs as tangible oil and gas properties until further guidance is provided. We anticipate there will be no effect on our results of operations or cash flows.



Note 5  Asset Retirement Obligations



In June 2001 the FASB issued SFAS 143. 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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The following summarizes asset retirement obligation at December 31, 2003 (in thousands):



|                                                         |  |   |         |  
|-------------------------------------------------------- |  | - | ------- | -
|Liabilities upon adoption of SFAS 143 on January 1, 2003 |  | $ | 23,135  |  
|Liabilities incurred                                     |  |   | 1,392   |  
|Liabilities settled                                      |  |   | (12,170 | )
|Accretion expense                                        |  |   | 2,752   |  
|Loss on abandonment                                      |  |   | 4,973   |  
|Change in estimate                                       |  |   | 1,025   |  
|                                                         |  |   |         |  
|Asset retirement obligation, as of December 31, 2003     |  | $ | 21,107  |  
|                                                         |  |   |         |  



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.



Of the $11.7 million impairment expense for 2003, approximately $1.0 million
relates to SFAS 143 changes in estimates. Specifically, the settlement dates of the asset retirement obligations were shortened on four properties which had no future net revenues as of December 31, 2003. Since there is no production on these
properties, the prescribed addition to the asset retirement cost could not be depleted and was thereby recorded directly to impairment expense.



The following pro forma information has been prepared to give effect to the adoption of SFAS 143 as if it had been adopted on January 1, 2002 and January
1, 2001 (in thousands, except per share amounts):



|                                       |  |                         |        |   |      |   |         |  
|-------------------------------------- |  | ----------------------- | ------ | - | ---- | - | ------- | -
|                                       |  | Year Ended December 31, |       
|                                       |  | 2002                    |        |   | 2001 |  
|Net loss                               |  | $                       | (4,435 | ) |      | $ | (18,632 | )
|Net loss per share  basic and diluted |  | $                       | (0.22  | ) |      | $ | (0.95   | )



The pro-forma asset
retirement obligation, if the adoption of this statement had occurred on January 1, 2002, would have been $17.5 million at January 1, 2002 and $20.1 million at December 31, 2002.



Note 6  Acquisitions



Gulf of Mexico



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



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



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U.K. SectorNorth Sea



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



Dutch SectorNorth Sea



In February 2003, we acquired a 50% working interest in a block located in the Dutch SectorNorth Sea. The remaining 50% interest is owned by a Dutch
company who participates on behalf of the Dutch state. In April 2003, we received $8.1 million from the 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, 2003, this obligation is reflected as a long-term liability in the financial statements.



Note 7  Debt



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



|                                                        |  |              |         |      |   |        |  
|------------------------------------------------------- |  | ------------ | ------- | ---- | - | ------ | -
|                                                        |  | December 31, |        
|                                                        |  | 2003         |         | 2002 |  
|Credit facility, bearing interest at 9%                 |  | $            | 115,409 |      | $ |       |  
|Credit facility, bearing interest at 5.25%              |  |              |        |      |   | 56,000 |  
|11.5% Note payable, net of unamortized discount of $863 |  |              |        |      |   | 30,387 |  
|                                                        |  |              |         |      |   |        |  
|Total debt                                              |  |              | 115,409 |      |   | 86,387 |  
|Less current maturities                                 |  |              |        |      |   | (6,000 | )
|                                                        |  |              |         |      |   |        |  
|Total long-term debt                                    |  | $            | 115,409 |      | $ | 80,387 |  
|                                                        |  |              |         |      |   |        |  



Credit Facility



On August 13, 2003, we entered into a material
modification of our prior credit facility in the form of an amendment, whereby the prior lenders were replaced and the terms were modified. Under the amended agreement, the borrowing base was redetermined and was established at $110.0 million. The
amended facility was secured by all of our U.S. assets in addition to approximately two-thirds of the capital stock of our foreign subsidiaries and was guaranteed by our wholly owned subsidiary, ATP Energy. The borrowing base was reviewed monthly
and if our outstanding balance exceeded our borrowing base at any time, we were required to repay such excess immediately. The material modification to the credit facility also extended the term of the facility to mature in August 2007.



On November 17, 2003 the credit facility was amended to modify certain
debt covenants and contemplated expanding the borrowing base by up to $15.0 million, subject to terms mutually acceptable to both parties, by pledging the oil and gas properties in the UK Sector of the North Sea. On December 3, 2003, we executed a
second amendment to our credit agreement, which implemented the $15.0 million tranche maturing on February 16, 2004, established a borrowing base coverage test of 150% commencing February 16, 2004, modified several of the financial covenants and
added new reporting and compliance covenants and events of default. We incurred fees of $2.4 million in connection with the execution of the first and second amendments which have been reflected in the financial statements as of December 31, 2003,
of which $0.8 million has been capitalized.



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Advances under the original tranches of the credit facility bore interest at the base rate plus a
margin of 1.0% to 8.0%, depending on the amount outstanding. The average effective interest rate on these tranches was approximately 9% per annum. Advances under the $15.0 million tranche bore interest at the rate of 15% per annum. The borrowing
base was reviewed monthly and if our outstanding balance exceeded our borrowing base at any time, we were required to repay such excess immediately.



The terms of the agreement at December 31, 2003, including the amendments discussed above, required us to maintain certain covenants including:



| |  | a current ratio, as defined in the agreement, of 0.35/1.0 through December 31, 2004 and 1.0/1.0 monthly thereafter;
| | - | -------------------------------------------------------------------------------------------------------------------



| |  | a consolidated debt coverage ratio which is not greater than 2.5/1.0 beginning October 31, 2003 with ranges from 1.6/1.0 to 3.0/1.0 monthly through August 31, 2004 and 1.6/1.0
monthly thereafter;
| | - | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  | a domestic debt coverage ratio which is not greater than 2.5/1.0 beginning October 31, 2003 with ranges from 1.9/1.0 to 3.0/1.0 monthly through January 31, 2005 and 1.9/1.0 monthly
thereafter;
| | - | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  | a consolidated and domestic interest coverage ratio which is not less than 3.0/1.0; and
| | - | ---------------------------------------------------------------------------------------



| |  | the requirement to maintain hedges on no less than 40% and no more than 80% of the next twelve months of forecasted production attributable to our proved producing reserves.
| | - | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------



As of December 31, 2003, we were not in
compliance with the minimum ratio of consolidated funded indebtedness to consolidated EBITDA requirement and the minimum consolidated EBITDA requirement. Waivers for non-compliance were obtained from the lender through execution of a third amendment
described below.



On February 23, 2004 we finalized the third
amendment to the credit agreement which was effective as of February 16, 2004. The third amendment extended the maturity of the $15.0 million tranche to January 31, 2005, reduced the borrowing base coverage test from 150% of the amounts outstanding
under our credit facility to 125%, extended the measuring date for such test from February 16, 2004 to April 30, 2004, imposed a new borrowing base reserve of $14.0 million at April 30, 2004 and provided waivers for the aforementioned non-compliance
of certain covenants. As consideration for the execution of the third amendment, we issued warrants to purchase 750,000 shares of our common stock, exercisable at a price of $6.75 per share. The $15.0 million tranche at December 31, 2003 has been
classified as long-term because of our intent and ability to refinance such amount on a long-term basis through the new term loan discussed below. On March 10, 2004, we executed a fourth amendment to extend to March 31, 2004 the time allowed
to place hedges on our North Sea production.



At
December 31, 2002, we had a $100.0 million senior-secured revolving credit facility which was secured by substantially all of our U.S. oil and gas properties, as well as by approximately two-thirds of the capital stock of our foreign subsidiaries
and was guaranteed by our wholly owned subsidiary, ATP Energy, Inc. The amount available for borrowing under the credit facility was limited to the loan value, as determined by the bank, of the oil and gas properties pledged under the facility. On
August 13, 2003, this credit facility was amended to replace the lenders and the outstanding balance was repaid.



New Term Loan



On March 29, 2004, we entered into a new $185.0 million 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 (Term Loan). 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.



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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS



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 and fees associated with the transaction.



The Term Loan was issued at an average interest rate of 10.8% and an original issue discount of 3% which was capitalized and will be amortized over the life of the Term Loan. The $150.0 million term loan bears 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. Beginning in October 2004, the margin will increase from 8.5% to 9.5%. The $35.0 million term loan bears interest at the base rate plus a margin of
9.0% or LIBOR (with a 2% floor) plus a margin of 10.0% at the election of ATP.



In connection with the issuance of the Term Loan we paid fees and expenses of $8.2 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. We expect to record these fees and the fair market value of the warrants issued as debt financing costs in the first quarter of 2004.



The terms of Term Loan require us to maintain certain covenants which are tested on a quarterly basis beginning June 30,
2004. 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 EBITAX coverage ratio which is not greater than 3.25/1.0 at June 30, 2004, 3.0/1.0 at September 30, 2004 and December 31, 2004, 2.5/1.0 at each of the
quarters ending in 2005 and 2006 and 2.0/1.0 for each of the quarters ending thereafter;
| | - | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  | Consolidated EBITDAX to Interest Expense which is not less than 2.5/1.0 during 2004 and 3.0/1.0 thereafter;
| | - | -----------------------------------------------------------------------------------------------------------



| |  | PV10 of our Total Proved Developed Producing Oil and Gas Reserves to Net Debt of at least 0.5/1.0;
| | - | --------------------------------------------------------------------------------------------------



| |  | PV10 of our Total Proved Oil and Gas Reserves to Net Debt of at least 2.5/1.0;
| | - | ------------------------------------------------------------------------------



| |  | Net Debt to Proved Developed Oil and Gas Reserves of less than $2.50/Mcfe in 2004, $2.25/Mcfe in 2005 and $2.00 per Mcfe in 2006 and thereafter; and
| | - | ----------------------------------------------------------------------------------------------------------------------------------------------------



| |  | the requirement to maintain hedges on no less than 40% and no more than 80% of the next twelve months of forecasted production attributable to our proved producing reserves.
| | - | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------



We expect that we will be in compliance with the
financial covenants under our new Term Loan for the next twelve months. However, adverse changes in our expected production levels and reserves or material delays or cost overruns in 2004 could have a material adverse affect on our financial
condition and results of operations and result in our non-compliance with these covenants.



Note Payable



In June
2001, we issued a note payable to a purchaser for a face principal amount of $31.3 million which was to mature in June 2005 and bore interest at a fixed rate of 11.5% per annum. The note was secured by second priority liens on substantially all of
our U.S. oil and gas properties and was subordinated in right of payment to our existing senior indebtedness. We executed an agreement in connection with the note which contains conditions and restrictive provisions and requires the maintenance of
certain financial ratios. The expected repayment premium was amortized to interest expense straight-line, over the term of the note which approximated the effective interest method. The discount of $1.3 million was amortized to interest expense
using the effective interest method. The resulting liability was included in other long-term liabilities on the consolidated balance sheet at December 31, 2002. On August 14, 2003 and in connection with the execution of



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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS



our amended credit agreement, we paid $36.1 million to the holder of the note payable to settle all outstanding obligations under the note agreement. Those
obligations included principal, accrued interest and early repayment premiums. Upon repayment of the note payable and replacement of the prior lenders of the credit facility, we recorded a $3.4 million total loss on the extinguishment in third
quarter of 2003, $0.9 million of which was related to non-cash deferred financing costs.



Note 8  Equity



Common Stock



On May 14, 2003, we completed a
private placement of four million shares of common stock to accredited investors for a total consideration of $11.8 million. We paid a fee of 6.0% of the gross proceeds from the sale of the stock to our placement agent and incurred other expenses of
approximately $0.2 million in the transaction, resulting in net proceeds of approximately $10.9 million. On June 11, 2003, our registration statement on Form S-3 relating to the resale of these shares became effective.



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. At December 31, 2002, we had 100,000,000 shares authorized, 20,398,007 shares issued, 20,322,167 shares outstanding and 75,840 shares in treasury.



Note 9  Stock Option 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:



|                                                               |  |        |           |      |                              |      |        |  |   |                              |   |        |   |      |                              |   |           |   |  |   |      
|-------------------------------------------------------------- |  | ------ | --------- | ---- | ---------------------------- | ---- | ------ |  | - | ---------------------------- | - | ------ | - | ---- | ---------------------------- | - | --------- | - |  | - | -----
|                                                               |  | 2003   |           | 2002 |                              | 2001
|                                                               |  | Shares |           |      | WeightedAverageExercisePrice |      | Shares |  |   | WeightedAverageExercisePrice |   | Shares |   |      | WeightedAverageExercisePrice
|Outstanding at beginning of year                               |  |        | 1,685,147 |      |                              | $    | 8.29   |  |   | 1,637,809                    |   |        | $ | 8.52 |                              |   | 646,608   |   |  | $ | 2.71 
|Granted                                                        |  |        | 50,929    |      |                              |      | 4.53   |  |   | 86,500                       |   |        |   | 3.43 |                              |   | 1,117,000 |   |  |   | 11.20
|Exercised                                                      |  |        | (198,189  | )    |                              |      | 1.79   |  |   | (9,519                       | ) |        |   | 1.43 |                              |   | (102,774  | ) |  |   | 1.96 
|Forfeited                                                      |  |        | (112,643  | )    |                              |      | 9.63   |  |   | (29,643                      | ) |        |   | 9.09 |                              |   | (23,025   | ) |  |   | 4.00 
|                                                               |  |        |           |      |                              |      |        |  |   |                              |   |        |   |      |                              |   |           |   |  |   |      
|Outstanding at end of year                                     |  |        | 1,425,244 |      |                              | $    | 8.96   |  |   | 1,685,147                    |   |        | $ | 8.29 |                              |   | 1,637,809 |   |  | $ | 8.52 
|                                                               |  |        |           |      |                              |      |        |  |   |                              |   |        |   |      |                              |   |           |   |  |   |      
|Exercisable at end of year                                     |  |        | 805,244   |      |                              | $    | 8.05   |  |   | 563,344                      |   |        | $ | 6.76 |                              |   | 112,760   |   |  | $ | 3.37 
|                                                               |  |        |           |      |                              |      |        |  |   |                              |   |        |   |      |                              |   |           |   |  |   |      
|Weighted average fair value of options granted during the year |  | $      | 2.63      |      |                              |      |        |  | $ | 1.74                         |   |        |   |      |                              | $ | 4.65      |   |  |   |      



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ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS



The following table summarizes information about all stock options outstanding at December 31, 2003:



|                         |  |                     |  |                     |  |                                       |       |                                  |         |                              |   |      
|------------------------ |  | ------------------- |  | ------------------- |  | ------------------------------------- | ----- | -------------------------------- | ------- | ---------------------------- | - | -----
|                         |  | Options Outstanding |  | Options Exercisable
|Range of Exercise Prices |  | NumberOutstanding   |  | ContractualLife     |  | WeightedAverageRemainingExercisePrice |       | WeightedAverageNumberExercisable |         | WeightedAverageExercisePrice
|$ 1.40 - $ 3.85          |  | 427,244             |  | 2.5 Years           |  | $                                     | 3.49  |                                  | 343,244 |                              | $ | 3.49 
|$ 5.73 - $ 6.30          |  | 24,000              |  | 4.9 Years           |  |                                       | 6.24  |                                  |        |                              |   |     
|$11.24 - $11.40          |  | 954,000             |  | 2.4 Years           |  |                                       | 11.37 |                                  | 452,000 |                              |   | 11.37
|$14.00 - $14.00          |  | 20,000              |  | 2.1 Years           |  |                                       | 14.00 |                                  | 10,000  |                              |   | 14.00
|                         |  |                     |  |                     |  |                                       |       |                                  |         |                              |   |      
|$ 1.40 - $14.00          |  | 1,425,244           |  | 2.4 Years           |  | $                                     | 8.96  |                                  | 805,244 |                              | $ | 8.05 
|                         |  |                     |  |                     |  |                                       |       |                                  |         |                              |   |      



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. Since options granted under the
1998 Plan did not vest nor were exercisable until 60 days after the date of our IPO, under the provisions of SFAS No. 123 Accounting for Stock Based Compensation (SFAS 123), our pro forma net loss and per share amounts
would have been unchanged for the year ended December 31, 2000. The pro forma effect on net income and earnings per share in 2003, 2002 and 2001, 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 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 2003 and 2002: stock price volatility of 83.9% and 92.8%, respectively; risk free interest rate of 1.9% and 2.8%,
respectively; zero dividend yield; and an expected life 2.5 years.



The fair value of options granted prior to 2002 was estimated on the latter of the date of grant or date of our IPO using a Black-Scholes option-pricing model with the following weighted-average assumptions: zero dividend yield; risk-free
interest rate of 4.5% and volatility of 80.2% and an expected life of 2.4 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. In 2001, we recorded a non-cash compensation expense of
$2.9 million for the above options and an additional non-cash compensation expense of $0.5 million related to certain options granted prior to September 1999 and exercised during 2001. The additional expense was recorded as a result of the manner in
which those shares were exercised.



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 discretionary and is currently 50% of each participants contributions
up to 6% of the participants compensation. Our matching contributions to the plan were approximately $106,000, $97,000 and $70,000, for the years ended December 31, 2003, 2002 and 2001, respectively.



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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS



We also have a defined contribution plan for our U.K. employees. We currently contribute 3% 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, 2003, 2002 and 2001, we contributed approximately $21,300, $15,500 and $14,000, respectively.



Note 10  Earnings Per Share



Basic earnings per share is computed by dividing net 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.



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



|                                              |  |                          |         |   |      |   |        |      |  |   |         |  
|--------------------------------------------- |  | ------------------------ | ------- | - | ---- | - | ------ | ---- |  | - | ------- | -
|                                              |  | Years Ended December 31, |        
|                                              |  | 2003                     |         |   | 2002 |   |        | 2001 | 
|Net loss available to common shareholders     |  | $                        | (50,801 | ) |      | $ | (4,700 | )    |  | $ | (21,383 | )
|                                              |  |                          |         |   |      |   |        |      |  |   |         |  
|Weighted average shares  basic and diluted   |  |                          | 22,975  |   |      |   | 20,315 |      |  |   | 19,704  |  
|                                              |  |                          |         |   |      |   |        |      |  |   |         |  
|Net loss per common share  basic and diluted |  | $                        | (2.21   | ) |      | $ | (0.23  | )    |  | $ | (1.09   | )
|                                              |  |                          |         |   |      |   |        |      |  |   |         |  



Note 11  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,
|                                                                                              |  | 2003                     |         |   | 2002 |   | 2001 
|Current:                                                                                      |  |                          |         |   |      |   |       |  |   |       
|State                                                                                         |  | $                        |        |   |      | $ |      |  | $ |      
|Federal                                                                                       |  |                          |        |   |      |   | 229   |  |   |      
|Foreign                                                                                       |  |                          |        |   |      |   |      |  |   |      
|                                                                                              |  |                          |         |   |      |   |       |  |   |       
|                                                                                              |  |                          |        |   |      |   | 229   |  |   |      
|                                                                                              |  |                          |         |   |      |   |       |  |   |       
|Deferred:                                                                                     |  |                          |         |   |      |   |       |  |   |       
|State                                                                                         |  |                          |        |   |      |   |      |  |   |      
|Federal                                                                                       |  |                          | 10,584  |   |      |   | 2,352 |  |   | 11,510
|Foreign                                                                                       |  |                          | 1,838   |   |      |   |      |  |   |      
|                                                                                              |  |                          |         |   |      |   |       |  |   |       
|                                                                                              |  |                          | 12,422  |   |      |   | 2,352 |  |   | 11,510
|                                                                                              |  |                          |         |   |      |   |       |  |   |       
|Valuation allowance                                                                           |  |                          | (33,646 | ) |      |   |      |  |   |      
|                                                                                              |  |                          |         |   |      |   |       |  |   |       
|(Expense) benefit for income taxes before cumulative effect of change in accounting principle |  | $                        | (21,224 | ) |      | $ | 2,581 |  | $ | 11,510
|                                                                                              |  |                          |         |   |      |   |       |  |   |       



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ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS



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



|         |  |                          |         |   |      |   |        |      |  |   |         |  
|-------- |  | ------------------------ | ------- | - | ---- | - | ------ | ---- |  | - | ------- | -
|         |  | Years Ended December 31, |        
|         |  | 2003                     |         |   | 2002 |   |        | 2001 | 
|Domestic |  | $                        | (26,320 | ) |      | $ | (4,889 | )    |  | $ | (30,041 | )
|Foreign  |  |                          | (3,919  | ) |      |   | (2,392 | )    |  |   | (2,852  | )
|         |  |                          |         |   |      |   |        |      |  |   |         |  
|         |  | $                        | (30,239 | ) |      | $ | (7,281 | )    |  | $ | (32,893 | )
|         |  |                          |         |   |      |   |        |      |  |   |         |  



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, |   
|                                  |  | 2003                     |    |  | 2002   |    |  | 2001   |   
|Statutory federal income tax rate |  | (35.00                   | )% |  | (35.00 | )% |  | (35.00 | )%
|Nondeductible and other           |  | 0.02                     |    |  | (0.39  | )  |  | 0.01   |   
|Foreign operations                |  | (6.08                    | )  |  |       |    |  |       |   
|Valuation allowance               |  | 111.27                   |    |  |       |    |  |       |   
|                                  |  |                          |    |  |        |    |  |        |   
|                                  |  | 70.21                    | %  |  | (35.39 | )% |  | (34.99 | )%
|                                  |  |                          |    |  |        |    |  |        |   



Significant components
of our deferred tax assets (liabilities) as of December 31, 2003 and 2002 are as follows (in thousands):



|                                   |  |              |         |   |      |   |        |  
|---------------------------------- |  | ------------ | ------- | - | ---- | - | ------ | -
|                                   |  | December 31, |        
|                                   |  | 2003         |         |   | 2002 |  
|Deferred tax assets (liabilities): |  |              |         |   |      |   |        |  
|Net operating loss carryforwards   |  | $            | 30,564  |   |      | $ | 19,550 |  
|Fixed asset basis differences      |  |              | (2,812  | ) |      |   | (5,427 | )
|State taxes                        |  |              |        |   |      |   | 17     |  
|Unrealized book losses             |  |              | 2,468   |   |      |   | 2,415  |  
|Stock based compensation expense   |  |              | 1,121   |   |      |   | 1,107  |  
|Litigation                         |  |              |        |   |      |   | 1,101  |  
|Foreign equity in subsidiary       |  |              | 3,493   |   |      |   | 1,989  |  
|Foreign operations                 |  |              | 1,838   |   |      |   |       |  
|Asset retirement obligations       |  |              | (3,857  | ) |      |   |       |  
|Deferred taxes related to SFAS 133 |  |              |        |   |      |   | 1,628  |  
|Other                              |  |              | 831     |   |      |   | 828    |  
|Valuation allowance                |  |              | (33,646 | ) |      |   |       |  
|                                   |  |              |         |   |      |   |        |  
|Net deferred tax assets            |  | $            |        |   |      | $ | 23,208 |  
|                                   |  |              |         |   |      |   |        |  



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 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 No. 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.



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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS



SFAS 109 provides for the weighing of positive and negative evidence in determining whether a
deferred tax asset is recoverable. We have incurred net operating losses for the three year period ending December 31, 2003. 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. Relevant accounting guidance suggests that cumulative losses in recent years constitute significant negative evidence, and that future expectations about income are diminished as a
result of the situation. Accordingly, we established a valuation allowance of $33.6 million as of December 31, 2003.



At December 31, 2003, 2002 and 2001, we had net operating loss carryforwards (NOLs) for federal income tax purposes of approximately $87.3
million, $55.9 million, and $10.7 million respectively, which are available to offset future federal taxable income through 2023.



A tax benefit related to the exercise of employee stock options of approximately $0.1 million was allocated directly to additional paid-in capital in
2001.



Note 12  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, 2003, 2002 and 2001 was approximately $0.6 million, $0.5 million and $0.3 million respectively. At December 31, 2003, the future minimum rental payments due under the lease are as follows (in
thousands amounts):



|            |  |   |      
|----------- |  | - | -----
|2004        |  | $ | 592  
|2005        |  |   | 367  
|2006        |  |   | 293  
|2007        |  |   | 240  
|2008        |  |   | 164  
|Later Years |  |   | 859  
|            |  |   |      
|Total       |  | $ | 2,515
|            |  |   |      



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. First commercial production from the Helvellyn property occurred in February 2004. Accordingly, contingent consideration
related to Helvellyn has been accrued for payment and capitalized as acquisition costs. Future development is planned on the other two properties.



Litigation



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



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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS



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



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



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



Note 13  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 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 (OCI) and are recognized in the statement of operations when the hedged item affects earnings. Ineffective portions of changes in the fair value of
cash flow hedges are recognized in 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. This presentation is a reclassification of prior period disclosures that segregated the mark-to-market value changes on instruments that did not qualify for hedge accounting treatment as income (loss) on derivative
instruments on the statement of operations.



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.



For the year ended December 31, 2003, a $4.6 million loss ($3.0 million after
tax) was realized and transferred out of accumulated other comprehensive income (loss) to earnings. At December 31, 2003, we had no derivatives in place that were designated as cash flow hedges.



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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS



In addition to these derivative instruments, we also manage our exposure to oil and gas price risks
by periodically entering into fixed-price delivery contracts. These physical contracts qualify for the normal purchase and sale exemption under SFAS 133, as amended. As of December 31, 2003, we had fixed-price contracts in place for the following
natural gas and oil volumes:



|                     |  |           |  |                       |      
|-------------------- |  | --------- |  | --------------------- | -----
|Period               |  | Volumes   |  | AverageFixedPrice (1)
|Natural gas (MMBtu): |  |           |  |                       |      
|2004                 |  | 7,586,966 |  | $                     | 4.81 
|Oil (Bbl):           |  |           |  |                       |      
|2004                 |  | 160,000   |  |                       | 29.64

---

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



From time to time we enter into natural gas and oil derivative arrangements
that we do not designate as hedges under SFAS 133. These financial instruments are recorded at fair value at the balance sheet date. At December 31, 2003, we had the following derivative instruments in place that we did not designate as hedges under
SFAS 133:



|       |  |                |  |         |  |               |  |                               |      |  
|------ |  | -------------- |  | ------- |  | ------------- |  | ----------------------------- | ---- | -
|Period |  | InstrumentType |  | Volumes |  | Average Price |  | Net FairValueAsset(Liability) |     
|       |  |                |  | (MMBtu) |  | ($ per MMBtu) |  | (Millions)                    |     
|2004   |  | 2-way collar   |  | 300,000 |  | 4.40  5.80   |  | $                             | (0.2 | )
|2004   |  | Swap           |  | 242,000 |  | 6.13          |  |                               |     |  



A two-way collar is a
combination of options, a sold call and purchased put. The purchased put establishes a minimum price (floor) and the sold call establishes a maximum price (ceiling) we will receive for the volumes under contract.



Thus far, in 2004 we have entered into the following fixed-price contracts:



|                     |  |           |  |                       |      
|-------------------- |  | --------- |  | --------------------- | -----
|Period               |  | Volumes   |  | AverageFixedPrice (1)
|Natural gas (MMBtu): |  |           |  |                       |      
|2004                 |  | 1,760,000 |  | $                     | 5.53 
|2005                 |  | 3,775,000 |  |                       | 5.30 
|Oil (Bbl):           |  |           |  |                       |      
|2004                 |  | 61,250    |  |                       | 33.48

---

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



Additionally in 2004, we entered into a crude oil swap on a total notional
volume of 7,250 barrels for the month of February 2004 at an average price of $34.45.



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ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS



Note 14  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, 2003 and 2002 was $19.8 million and $22.9 million, respectively. At December 31, 2003 and 2002, the present value of the remaining premium payments to be made by ATP Energy, using a discount rate of 6%, was
$19.5 million and $22.7 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, 2003 the remaining premium to be paid was $22.6 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 entered into a contract with El Paso Energy Marketing in December 1998 to sell an identical quantity of
natural gas at the Gas Daily Henry Hub index price less $0.015 until December 2001 and has been renewed on a month-to-month basis since then.



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, 2003 and 2002, the deferred revenue
amount was $0.9 million and $1.1 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.



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ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS



Note 15  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 2003, 2002 and 2001 is as
follows (in thousands):



|                                         |  |               |         |   |           |   |        |       |  |   |         |  
|---------------------------------------- |  | ------------- | ------- | - | --------- | - | ------ | ----- |  | - | ------- | -
|                                         |  | Gulf ofMexico |         |   | North Sea |   |        | Total | 
|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  |  
|Operating loss                           |  |               | (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   |  
|Operating income (loss)                  |  |               | 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 |  
|2001                                     |  |               |         |   |           |   |        |       |  |   |         |  
|Revenues                                 |  | $             | 87,873  |   |           | $ |       |       |  | $ | 87,873  |  
|Depreciation, depletion and amortization |  |               | 53,376  |   |           |   | 52     |       |  |   | 53,428  |  
|Impairment of oil and gas properties     |  |               | 24,891  |   |           |   |       |       |  |   | 24,891  |  
|Operating loss                           |  |               | (19,908 | ) |           |   | (2,904 | )     |  |   | (22,812 | )
|Additions to oil and gas properties      |  |               | 106,433 |   |           |   | 3,831  |       |  |   | 110,264 |  
|Total assets                             |  |               | 172,300 |   |           |   | 5,264  |       |  |   | 177,564 |  



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##### Table of Contents

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS



Note 16  Summarized Quarterly Financial Data (Unaudited)



(In Thousands, Except Per Share Amounts)



|                                    |  |              |        |   |               |   |              |  |   |               |   |  |   |         |    
|----------------------------------- |  | ------------ | ------ | - | ------------- | - | ------------ |  | - | ------------- | - |  | - | ------- | ---
|                                    |  | FirstQuarter |        |   | SecondQuarter |   | ThirdQuarter |  |   | FourthQuarter |  
|2003                                |  |              |        |   |               |   |              |  |   |               |   |  |   |         |    
|Revenues                            |  | $            | 20,441 |   |               | $ | 18,540       |  | $ | 17,179        |   |  | $ | 13,991  |    
|Costs and expenses                  |  |              | 15,445 |   |               |   | 16,667       |  |   | 27,775        |   |  |   | 29,769  | (1)
|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(3)                |  | $            | 0.12   |   |               | $ | 0.02         |  | $ | (0.61         | ) |  | $ | (1.58   | )  
|2002                                |  |              |        |   |               |   |              |  |   |               |   |  |   |         |    
|Revenues                            |  | $            | 11,214 |   |               | $ | 26,908       |  | $ | 23,207        |   |  | $ | 18,688  |    
|Costs and expenses                  |  |              | 18,353 |   |               |   | 19,426       |  |   | 17,985        |   |  |   | 22,270  | (2)
|Income (loss) from operations       |  |              | (7,139 | ) |               |   | 7,482        |  |   | 5,222         |   |  |   | (3,582  | )  
|Net income (loss)                   |  |              | (6,363 | ) |               |   | 3,171        |  |   | 1,665         |   |  |   | (3,173  | )  
|Net income (loss) per common share: |  |              |        |   |               |   |              |  |   |               |   |  |   |         |    
|Basic and diluted(3)                |  | $            | (0.31  | ) |               | $ | 0.16         |  | $ | 0.08          |   |  | $ | (0.16   | )  

---

|(1) | 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 5).
|--- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------



|(2) | Includes impairment charges of $6.8 million during the fourth quarter for two properties.
|--- | -----------------------------------------------------------------------------------------



|(3) | 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.
|--- | -------------------------------------------------------------------------------------------------------------------------------------------



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##### Table of Contents

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 summarizes costs incurred in natural gas and oil
property acquisition and development activities are summarized below (in thousands):



|                            |  |               |         |           |   |        |  |   |        
|--------------------------- |  | ------------- | ------- | --------- | - | ------ |  | - | -------
|                            |  | Gulf ofMexico |         | North Sea |   | Total 
|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    
|Proved                      |  |               |        |           |   |       |  |   |       
|Development costs           |  |               | 17,561  |           |   | 16,353 |  |   | 33,914 
|                            |  |               |         |           |   |        |  |   |        
|                            |  | $             | 18,520  |           | $ | 16,353 |  | $ | 34,873 
|                            |  |               |         |           |   |        |  |   |        
|2001                        |  |               |         |           |   |        |  |   |        
|Property acquisition costs: |  |               |         |           |   |        |  |   |        
|Proved                      |  | $             | 28,344  |           | $ | 3,112  |  | $ | 31,456 
|Development costs           |  |               | 77,783  |           |   | 719    |  |   | 78,502 
|                            |  |               |         |           |   |        |  |   |        
|                            |  | $             | 106,127 |           | $ | 3,831  |  | $ | 109,958
|                            |  |               |         |           |   |        |  |   |        

---

|(1) | This amount includes $15.4 million of asset retirement costs as a result of implementation of SFAS 143.
|--- | -------------------------------------------------------------------------------------------------------



Natural Gas and Oil Reserves



Proved reserves are estimated quantities of natural gas and oil 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 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 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, 2000, 2001, 2002
and 2003 and the changes in net proved oil and gas reserves for the years ended December 31, 2001, 2002 and 2003:



|                                |  |                    |   |  |                                                |   |  |         |   |  |               |   |  |           |  |        |  
|------------------------------- |  | ------------------ | - |  | ---------------------------------------------- | - |  | ------- | - |  | ------------- | - |  | --------- |  | ------ | -
|                                |  | Natural Gas (MMcf) |   |  | Oil, Condensate andNatural Gas Liquids (MBbls) |  
|                                |  | Gulf ofMexico      |   |  | North Sea                                      |   |  | Total   |   |  | Gulf ofMexico |   |  | North Sea |  | Total  |  
|Proved Reserves at              |  |                    |   |  |                                                |   |  |         |   |  |               |   |  |           |  |        |  
|December 31, 2000               |  | 101,570            |   |  |                                               |   |  | 101,570 |   |  | 3,977         |   |  |          |  | 3,977  |  
|Revisions of previous estimates |  | (6,793             | ) |  |                                               |   |  | (6,793  | ) |  | 134           |   |  |          |  | 134    |  
|Purchase of properties          |  | 40,060             |   |  | 80,629                                         |   |  | 120,689 |   |  | 3,432         |   |  |          |  | 3,432  |  
|Production                      |  | (20,957            | ) |  |                                               |   |  | (20,957 | ) |  | (790          | ) |  |          |  | (790   | )
|                                |  |                    |   |  |                                                |   |  |         |   |  |               |   |  |           |  |        |  
|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 |  
|                                |  |                    |   |  |                                                |   |  |         |   |  |               |   |  |           |  |        |  
|                                |  |                   
|                                |  | Natural Gas (MMcf) |   |  | Oil and Condensate (MBbls)                     |  
|                                |  | Gulf ofMexico      |   |  | North Sea                                      |   |  | Total   |   |  | Gulf ofMexico |   |  | North Sea |  | Total  |  
|Proved Developed Reserves at    |  |                    |   |  |                                                |   |  |         |   |  |               |   |  |           |  |        |  
|December 31, 2000               |  | 42,502             |   |  |                                               |   |  | 42,502  |   |  | 851           |   |  |          |  | 851    |  
|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  |  



Standardized
Measure



The standardized measure of discounted future net
cash flows relating to proved natural gas and oil reserves as of year-end is shown below (in thousands):



|                                                         |  |               |           |   |           |   |          |       |  |   |           |  
|-------------------------------------------------------- |  | ------------- | --------- | - | --------- | - | -------- | ----- |  | - | --------- | -
|                                                         |  | Gulf ofMexico |           |   | 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   |  
|                                                         |  |               |           |   |           |   |          |       |  |   |           |  



Table continued on
following page



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ATP OIL & GAS CORPORATION

SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES



|                                                         |  |               |          |   |           |   |          |       |  |   |          |  
|-------------------------------------------------------- |  | ------------- | -------- | - | --------- | - | -------- | ----- |  | - | -------- | -
|                                                         |  | Gulf ofMexico |          |   | North Sea |   |          | Total | 
|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  |  
|                                                         |  |               |          |   |           |   |          |       |  |   |          |  
|                                                         |  |               |         
|2001                                                     |  |               |          |   |           |   |          |       |  |   |          |  
|Future cash inflows                                      |  | $             | 423,273  |   |           | $ | 302,894  |       |  | $ | 726,167  |  
|Future operating expenses                                |  |               | (59,722  | ) |           |   | (100,330 | )     |  |   | (160,052 | )
|Future development costs                                 |  |               | (100,919 | ) |           |   | (111,044 | )     |  |   | (211,963 | )
|                                                         |  |               |          |   |           |   |          |       |  |   |          |  
|Future net cash flows                                    |  |               | 262,632  |   |           |   | 91,520   |       |  |   | 354,152  |  
|Future income taxes                                      |  |               | (35,469  | ) |           |   | (26,188  | )     |  |   | (61,657  | )
|                                                         |  |               |          |   |           |   |          |       |  |   |          |  
|Future net cash flows, after income taxes                |  |               | 227,163  |   |           |   | 65,332   |       |  |   | 292,495  |  
|10% annual discount per annum                            |  |               | (54,247  | ) |           |   | (25,584  | )     |  |   | (79,831  | )
|                                                         |  |               |          |   |           |   |          |       |  |   |          |  
|Standardized measure of discounted future net cash flows |  | $             | 172,916  |   |           | $ | 39,748   |       |  | $ | 212,664  |  
|                                                         |  |               |          |   |           |   |          |       |  |   |          |  



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 natural gas and oil 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 ofMexico |       | U.K.SectorNorth Sea |   | DutchSectorNorth Sea |  | Gulf ofMexico |       | U.K.SectorNorth Sea |   | DutchSectorNorth Sea
|December 31, 2001 |  | $             | 2.650 |                     | $ | 3.880                |  | $             |      |                     | $ | 19.78                |  | $ |  |  | $ |     
|December 31, 2002 |  |               | 4.740 |                     |   | 2.200                |  |               |      |                     |   | 31.23                |  |   |  |  |   |     
|December 31, 2003 |  |               | 5.965 |                     |   | 5.160                |  |               | 4.160 |                     |   | 32.55                |  |   |  |  |   | 30.00



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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 natural gas and oil reserves are summarized
below (in thousands):



|                                              |  |               |          |   |           |   |         |       |  |   |          |  
|--------------------------------------------- |  | ------------- | -------- | - | --------- | - | ------- | ----- |  | - | -------- | -
|                                              |  | Gulf ofMexico |          |   | North Sea |   |         | Total | 
|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  |  
|                                              |  |               |          |   |           |   |         |       |  |   |          |  
|2001                                          |  |               |          |   |           |   |         |       |  |   |          |  
|Beginning of year                             |  | $             | 524,481  |   |           | $ |        |       |  | $ | 524,481  |  
|                                              |  |               |          |   |           |   |         |       |  |   |          |  
|Sales of oil and gas, net of production costs |  |               | (90,951  | ) |           |   |        |       |  |   | (90,951  | )
|Net changes in income taxes                   |  |               | 193,247  |   |           |   | (24,517 | )     |  |   | 168,730  |  
|Net changes in price and production costs     |  |               | (593,914 | ) |           |   |        |       |  |   | (593,914 | )
|Revisions of quantity estimates               |  |               | (11,220  | ) |           |   |        |       |  |   | (11,220  | )
|Accretion of discount                         |  |               | 74,483   |   |           |   |        |       |  |   | 74,483   |  
|Development costs incurred                    |  |               | 57,119   |   |           |   |        |       |  |   | 57,119   |  
|Changes in estimated future development costs |  |               | 22,413   |   |           |   |        |       |  |   | 22,413   |  
|Purchases of minerals-in-place                |  |               | 64,322   |   |           |   | 64,265  |       |  |   | 128,587  |  
|Changes in production rates, timing and other |  |               | (67,064  | ) |           |   |        |       |  |   | (67,064  | )
|                                              |  |               |          |   |           |   |         |       |  |   |          |  
|                                              |  |               | (351,565 | ) |           |   | 39,748  |       |  |   | (311,817 | )
|                                              |  |               |          |   |           |   |         |       |  |   |          |  
|End of year                                   |  | $             | 172,916  |   |           | $ | 39,748  |       |  | $ | 212,664  |  
|                                              |  |               |          |   |           |   |         |       |  |   |          |  



F-32



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##### Table of Contents

ATP OIL & GAS CORPORATION

SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES



Sales of natural gas and oil, net of natural gas and oil operating expenses, are based on historical
pre-tax results. Sales of natural gas and oil 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 ofMexico |          |   | North Sea |   | Total  | 
|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  |  
|                                                   |  |               |          |   |           |   |        |  |   |          |  
|2002                                               |  |               |          |   |           |   |        |  |   |          |  
|Oil and gas properties:                            |  |               |          |   |           |   |        |  |   |          |  
|Unproved                                           |  | $             | 959      |   |           | $ |       |  | $ | 959      |  
|Proved                                             |  |               | 333,082  |   |           |   | 21,047 |  |   | 354,129  |  
|Accumulated depletion, impairment and amortization |  |               | (236,052 | ) |           |   |       |  |   | (236,052 | )
|                                                   |  |               |          |   |           |   |        |  |   |          |  
|                                                   |  | $             | 97,989   |   |           | $ | 21,047 |  | $ | 119,036  |  
|                                                   |  |               |          |   |           |   |        |  |   |          |  



F-33