Atp Oil & Gas (ATPGQ) 10-K 2010 FY Annual report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-K

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

For the fiscal year ended December 31, 2010

or

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

Commission file number: 001-32647

ATP Oil & Gas Corporation

(Exact name of registrant as specified in its charter)

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

4600 Post Oak Place, Suite 100

Houston, Texas 77027

(Address of principal executive offices) (Zip Code)

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

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

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

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

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

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

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

Indicate by check mark whether the Registrant has submitted electronically and posted on its corporate website, if any, every interactive Data File required to be submitted electronically and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or such shorter period that Registrant was required to post such files).    Yes  ¨    No  ¨

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

Indicate by check mark whether the Registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer	¨	Accelerated filer	x
Non-accelerated filer	¨  (do not check if a smaller reporting company)	Smaller reporting company	¨

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

The aggregate market value of the voting and non-voting common stock held by non-affiliates of the Registrant as of June 30, 2010 (the last business day of the Registrant’s most recently completed second fiscal quarter) was approximately $471.0 million. The number of shares of the Registrant’s common stock outstanding as of March 2, 2011 was 51,392,096.

DOCUMENTS INCORPORATED BY REFERENCE

Selected portions of ATP Oil & Gas Corporation’s definitive Proxy Statement, which will be filed with the Securities and Exchange Commission within 120 days after December 31, 2010, are incorporated by reference in Part III of this Form 10-K.

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

2010 FORM 10-K ANNUAL REPORT

TABLE OF CONTENTS

			Page
PART I
	Item 1.	Business		8
	Item 1A.	Risk Factors		15
	Item 1B.	Unresolved Staff Comments		26
	Item 2.	Properties		26
	Item 3.	Legal Proceedings		31
	Item 4.	(Removed and Reserved.)		31
PART II
	Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		32
	Item 6.	Selected Financial Data		34
	Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		36
	Item 7A.	Quantitative and Qualitative Disclosures about Market Risk		54
	Item 8.	Financial Statements and Supplementary Data		55
	Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		55
	Item 9A.	Controls and Procedures		55
	Item 9B.	Other Information		56
PART III
	Item 10.	Directors, Executive Officers and Corporate Governance		57
	Item 11.	Executive Compensation		58
	Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		58
	Item 13.	Certain Relationships and Related Transactions, and Director Independence		58
	Item 14.	Principal Accounting Fees and Services		58
PART IV
	Item 15.	Exhibits, Financial Statement Schedules		59

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Cautionary Statement About Forward-Looking Statements

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

This annual report includes assumptions, expectations, projections, intentions or beliefs about future events. These statements are intended as “forward-looking statements” under the Private Securities Litigation Reform Act of 1995, Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934 (the “Exchange Act”). Words such as “may,” “could,” “would,” “should,” “believes,” “expects,” “anticipates,” “estimates,” “projects,” “forecasts,” “intends,” “plans,” “targets,” “objectives,” “seek,” “strive,” negatives of these words and similar expressions are intended to identify forward-looking statements. Forward-looking statements are based on management’s beliefs, assumptions and expectations of our future economic performance, taking into account the information currently available to our management. They are expressions based on historical fact, but do not guarantee future performance. Forward-looking statements involve risks, uncertainties and assumptions and certain other factors that may, and often do, cause our actual results, performance or financial condition to differ materially from the expectations of future results, performance or financial condition we express or imply in any forward-looking statements.

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

• projected operating or financial results;

• timing and expectations of financing activities;

• budgeted or projected capital expenditures;

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

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

• expectations regarding oil and natural gas markets in the U.S., U.K. and the Netherlands; and

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

We believe these forward-looking statements are reasonable, but we caution that you should not place undue reliance on these forward-looking statements, because there can be no assurance that actual results will not differ materially from those expressed or implied in such forward looking statements. We do not generally update forward-looking statements, whether written or oral, relating to the matters discussed in this Annual Report on Form 10-K. Some of the key factors which could cause actual results to vary from those expected include:

• the substantial requirements for cash to fund development of our oil and gas properties;

• the volatility in oil and natural gas prices;

• the timing of planned capital expenditures;

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

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

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

• uncertainties and 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;

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

• our inability to generate sufficient funds from our operations and other financing sources;

• interest payment requirements on our debt obligations;

• restrictions imposed by our debt instruments and compliance with our debt covenants;

• delays in the development of or production curtailment at our material properties;

• our price risk management decisions;

• the unavailability or increased cost of drilling rigs, equipment, supplies, personnel and oilfield services;

• insufficient insurance coverage;

• foreign currency fluctuations;

• rapid production declines in our Gulf of Mexico properties;

• substantial impairment write-downs;

• unidentified liabilities associated with properties that we acquire which we have not obtained protection from sellers against;

• competition from our larger competitors in the Gulf of Mexico and the North Sea;

• the loss of members of the management team and other key personnel;

• the ownership by members of our management team of a significant amount of common stock;

• rapid growth may place significant demands on our resources; and

• our ability to use net operating losses to offset future taxable income may be limited.

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

Natural gas is converted into barrels of oil equivalent based on six Mcf of gas to one barrel of crude oil or other liquid hydrocarbons.

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

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

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

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

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

PV-10, a non-GAAP measure, is the pre-tax present value, discounted at 10% per year, of estimated future net cash flows from the production of proved reserves, computed by applying sales prices in effect as of the dates of such estimates and held constant throughout the productive life of the reserves (except for consideration of price changes to the extent provided by contractual arrangements), after deducting the estimated future costs to be incurred in developing, producing and abandoning the proved reserves (computed based on current costs and assuming continuation of existing economic conditions.) We believe PV-10 to be an important measure for evaluating the relative significance of our oil and natural gas properties. PV-10 is computed on the same basis as the standardized measure of discounted future net cash flows but without deducting income taxes. We further believe investors and creditors may utilize our PV-10 as a basis for comparison of the relative size and value of our reserves to other companies. However, PV-10 is not a substitute for the standardized measure.

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

Proved reserves are the estimated quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible – from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations. Reservoirs are considered proved if shown to be economically producible by either actual

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production or conclusive formation tests. See Regulation S-X, Rule 4-10(a)(22)-(26), (Reg. § 210.4-10) available on the Internet at www.sec.gov/divisions/corpfin/ecfrlinks.shtml.

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 or in which the cost of the required equipment is relatively minor compared to the cost of a new well.

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

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

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

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PART I

Item 1.Business.

General

ATP Oil & Gas Corporation was incorporated in Texas in 1991. We are engaged in the acquisition, development and production of oil and natural gas properties in the Gulf of Mexico and the U.K and Dutch sectors of the North Sea (the “North Sea”). We seek to acquire and develop properties with proved undeveloped reserves (“PUD”) that are economically attractive to us but are not strategic to major or large exploration-oriented independent oil and gas companies. Occasionally we will acquire properties that are already producing or where previous drilling has encountered reservoirs that appear to contain commercially productive quantities of oil and gas even though the reservoirs do not meet the SEC definition of proved reserves. We believe that our strategy provides assets for us to develop and produce without the risk, cost or time of traditional exploration. Our management team has extensive engineering, geological, geophysical, technical and operational expertise in developing and operating properties in both our current and planned areas of operation.

At December 31, 2010, we had estimated net proved reserves of 126.4 MMBoe, of which approximately 83.9 MMboe (66%) were in the Gulf of Mexico and 42.5 MMBoe (34%) were in the North Sea. The reserves were comprised of 75.1 MMBbls of oil (59%) and 307.8 Bcf of natural gas (41%). Our proved reserves in the deepwater area of the Gulf of Mexico account for 62% of our total proved reserves and our proved reserves on the Gulf of Mexico Outer Continental Shelf account for 4% of our total proved reserves. Our natural gas reserves are split between the Gulf of Mexico (67%) and the North Sea (33%). Of our total proved reserves, 15.8 MMBoe (13%) were producing, 8.0 MMBoe (6%) were developed and not producing and 102.6 MMBoe (81%) were undeveloped. Our average working interest in our properties at December 31, 2010 was approximately 83%. We operate 97% of our platforms. The estimated PV-10 of our proved reserves at December 31, 2010 was $2.6 billion. See “Item 2. Properties – Oil and Natural Gas Reserves” for a reconciliation to our standardized measure of discounted future net cash flows.

At December 31, 2010, we owned leasehold and other interests in 51 offshore blocks and 88 wells, including 24 subsea wells, in the Gulf of Mexico. We operate 82 (93%) of these wells, including 100% of the subsea wells. We also had interests in 13 blocks and three company-operated subsea wells in the North Sea.

As of the date of this report, we own an interest in 29 platforms including two floating production facilities in the Gulf of Mexico, theATP Innovatorat our Gomez Hub and theATP Titan at our Telemark Hub. These floating production facilities are fundamental to our hub strategy and business plan. The presence of these facilities allows us a competitive advantage for additional acquisitions in a large area surrounding each installation. A third floating production facility called an Octabuoy is under construction in China for initial deployment at our Cheviot Hub in the U.K. North Sea which is expected in 2014. We operate theATP Innovator and theATP Titanand we also expect to operate the Octabuoy when it is placed in service. The floating production facilities have longer useful lives than the underlying reserves and are capable of redeployment to new producing locations upon depletion of the reserves. Accordingly, they are expected eventually to be moved several times over their useful lives.

Our Business Strategy

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

• significant undeveloped reserves;

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

• existing infrastructure or the ability to install our own infrastructure of oil and natural gas pipelines and production/processing platforms;

• opportunities to aggregate production and create operating efficiencies that capitalize upon our hub concept; and

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

Our focus is on acquiring properties that are noncore or nonstrategic to their current owners for a variety of reasons. For example, larger oil companies from time to time adjust their capital spending or shift their

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focus to exploration prospects they believe offer greater reserve potential. Some projects may provide lower economic returns to a company due to the cost structure and focus of 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. With our cost structure and acquisition strategy, it is not unusual for us to acquire a property at a cost that is less than the development costs incurred by the previous owner. This strategy, coupled with our expertise in our areas of focus and our ability to develop projects, tends to make our oil and gas property acquisitions more financially attractive to us than to the seller. Given our strategy of acquiring properties that contain proved reserves, or where previous drilling by others indicates to us the presence of recoverable hydrocarbons, our operations typically are lower risk than exploration-focused Gulf of Mexico and North Sea operators.

Since we operate a significant number of the properties in which we acquire a working interest, we are able to influence the plans and timing of a project’s development significantly. In addition, practically all of our properties have previously defined and targeted reservoirs, eliminating from our development plan the time necessary in typical exploration efforts to locate and determine the extent of oil and gas reservoirs. Without the exploration time constraint, 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. We may initiate new development projects by simultaneously obtaining the various required components such as the pipeline and the production platform or subsea well completion equipment.

Our Strengths

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

• Significant Infrastructure Investment at our Hubs. With over $1.0 billion already invested in infrastructure at our Gomez and Telemark Hubs and more than $275 million related to our Cheviot Hub development, it is our belief that we have a competitive advantage to expand our interest in those areas over other production companies that do not have such an investment.

• Technical Expertise and Significant Experience. We have assembled a technical staff with an average of over 27 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, 2010, we operated all of our properties under development, all of our subsea wells and 97% of our offshore platforms.

• Employee Ownership. Through employee ownership of company stock, we have assembled a staff whose business decisions are aligned with the interests of our shareholders. As of March 2, 2011, our executive officers and directors own approximately 13% of our common stock.

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

There are also risk factors that could adversely affect our business. Please see Item 1A. Risk Factors.

Marketing and Delivery Commitments

We sell crude oil and natural gas production under price sensitive or market price contracts. Our revenues, profitability and future growth are substantially dependent on prevailing prices for oil and natural gas. The price received by us for such production can fluctuate widely. Changes in the prices of oil and natural gas will affect the economic viability of some of our proved reserves as well as our revenues, profitability and cash flow. Additionally, involuntary curtailment of our oil or natural gas production, market, economic and regulatory factors may in the future materially affect our ability to sell our oil or natural gas production.

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Occasionally, we sell a limited portion of our production utilizing fixed-price forward sales contracts, which require us to deliver a fixed and determinable quantity of oil or gas to a predetermined Gulf of Mexico or North Sea market delivery point. At inception of these contracts we expect to have sufficient production from each local market to satisfy the commitments. Volume information by geographic area at December 31, 2010 regarding our fixed-price forward sales contracts is included in Note 13 to our Consolidated Financial Statements.

Historically, we have sold our oil and natural gas production to a relatively small number of purchasers. Due to the nature of oil and natural gas markets, and because oil and natural gas are commodities and there are numerous purchasers in the areas in which we sell production, we do not believe the loss of a single purchaser, or a few purchasers, would materially affect our ability to sell our production. For the year ended December 31, 2010, revenues from four purchasers accounted for 65%, 12%, 11% and 5%, respectively, of oil and gas production revenues.

Competition

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

Regulation

Gulf of Mexico

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

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

The Outer Continental Shelf Lands Act, also known as “OCSLA,” requires that all pipelines operating on or across the Outer Continental Shelf (“OCS”) provide open-access, nondiscriminatory service. Previously, the FERC enforced this provision pursuant to its authority under both the Natural Gas Act and OCSLA. One of FERC’s principal goals in carrying out OCSLA’s mandate was to increase transparency in the market to provide producers and shippers on the OCS with greater assurance of open access service on pipelines located on the OCS and nondiscriminatory rates and conditions of service on such pipelines. In 2003, the courts determined that the FERC had only limited authority to enforce its open access rules on the OCS and decided, instead, that such authority primarily rested with others, including the U.S. Department of the Interior (“DOI”). The Bureau of Ocean Energy Management, Regulation and Enforcement of the DOI (“BOEM”), successor to the MMS, has jurisdiction under OCSLA to ensure that all shippers seeking service on OCS pipelines transporting oil or gas pursuant to BOEM-granted easements or rights-of-way receive open and nondiscriminatory access to such transportation. In furtherance of this mandate, regulations were issued in

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2008 establishing a process for a shipper transporting oil or gas production from OCS leases to follow if it believes it has been denied open and nondiscriminatory access to OCS pipelines and the remedies that BOEM may impose on a transporter that BOEM determines has denied open or nondiscriminatory access to an OCS shipper.

Additional proposals and proceedings that might affect the natural gas industry are pending before FERC and the courts. The natural gas industry historically has been very volatile, and we expect such price volatility to continue. Any extended decline in oil or gas prices could have a material adverse effect on our financial position, results of operations, cash flows, the quantities of oil and gas reserves that we can economically produce, and may restrict the types, quantities and concentration of various substances that can be released into the environment, and impose substantial liabilities for pollution. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations, and the issuance of injunctive relief. Offshore drilling in some areas has been opposed by environmental groups and, in some areas, has been restricted by governmental entities. Moreover, changes in environmental laws and regulations have increased in recent years. Any laws that are enacted or other governmental actions that are taken to prohibit or restrict offshore drilling or to impose more stringent or costly environmental protection requirements could have a material adverse effect on the oil and natural gas industry in general and our offshore operations in particular.

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

The OPA also requires a responsible party to submit proof of its financial responsibility to cover environmental cleanup and restoration costs that could be incurred in connection with an oil spill. Under this Act, parties responsible for offshore facilities must provide financial assurance of at least $35.0 million ($10.0 million if the offshore facility is located landward of the seaward boundary of a state) to address oil spills and associated damages, with this financial assurance amount increasing up to $150.0 million in certain circumstances depending on the risk represented by the quantity or quality of oil that is handled by the facility. We carry insurance coverage to meet these obligations. The OPA also imposes other requirements, such as the preparation of an oil spill contingency plan. A failure to comply with OPA’s requirements or inadequate cooperation during a spill response action may subject a responsible party to civil or criminal enforcement actions. We are not aware of any action or event that would subject us to liability under OPA, and we believe that compliance with OPA’s existing financial responsibility and other operating requirements do not have a material adverse affect on us.

We are also regulated by the Clean Water Act, which prohibits any discharge of pollutants into waters of the U.S. except in conformance with discharge permits issued by federal or state agencies. Further, the EPA has adopted regulations requiring certain oil and natural gas exploration and production facilities to obtain permits for stormwater discharges. Costs may be associated with the treatment of wastewater or developing and implementing stormwater pollution prevention plans. We are also subject to similar state and local water quality laws and regulations for any production or drilling activities that occur in state coastal waters. Failure to comply with the ongoing requirements of the Clean Water Act or analogous state laws may subject a responsible party to administrative, civil or criminal enforcement actions and impose liability on parties responsible for those discharges for the costs of cleaning up any environmental damage caused by the release and for natural resource damage resulting from the release. We are in material compliance with these requirements.

ATP has in place for its Gulf of Mexico (“GOM”) operations a Regional Oil Spill Response Plan (“Response Plan”) that covers the uncontrolled release of any hazardous material. The Response Plan details

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procedures for the rapid and effective response to and remediation of spill events that may occur as a result of ATP’s operations. The Response Plan is supplemented and updated as needed.

The ATP spill management team consists of an integrated organization of key personnel from ATP and a third-party spill management group, O’Brien’s Oil Pollution Service, Inc. This team utilizes the National Incident Management System (“NIMS”), which is a nationwide template, or organizational structure, which enables federal, state, and local governments, as well as non-governmental organizations, to work together to prepare for, prevent, if necessary respond to, and mitigate the effects of an incident.

Within the NIMS template is the Incident Command System (“ICS”), which establishes the functional organizational structure of the team (“Response Team”). The ICS represents a best-practices emergency response management structure for meeting the demands of any emergency situation. All members of the Response Team, at a minimum, receive training and are tested through annual spill drills. The Response Team is headed by an Incident Commander who has overall responsibility during the incident mitigation.

ATP is a member of Clean Gulf Associates (“CGA”), which is a not-for-profit association of producing and pipeline companies operating in the GOM. CGA, coupled with the Marine Spill Response Corporation, manage the response personnel and equipment, which are on call 24 hours a day, seven days a week. All of these personnel and the associated equipment are managed by the Incident Commander through the ICS.

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

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

The Safe Drinking Water Act (“SDWA”) regulates the underground injection of fluid (such as the reinjection of brine produced and separated from oil and natural gas production) through a well. The SDWA of 1974, as amended establishes a regulatory framework for underground injection, with the main goal being the protection of usable aquifers. The primary objective of injection well operating requirements is to ensure the mechanical integrity of the injection apparatus and to prevent migration of fluids from the injection zone into underground sources of drinking water. Failure to abide by our permits could subject us to civil or criminal enforcement. We believe that we are in compliance in all material respects with the requirements of applicable state underground injection control programs and our permits.

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

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

On December 15, 2009, the EPA officially published its “Endangerment Finding,” an official finding that emissions of carbon dioxide, methane and other greenhouse gases (“GHGs”) present an endangerment to human health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the Earth’s atmosphere and other climatic changes. The Endangerment Finding allows the agency to proceed with the adoption and implementation of regulations that would restrict emissions of GHGs under existing provisions of the CAA. In late September 2009, the EPA had proposed two sets of regulations in anticipation of finalizing its findings that would require a reduction in emissions of GHGs from motor vehicles and that could also lead to the imposition of GHG emission limitations in CAA permits for certain stationary sources. The Light-Duty Vehicle Greenhouse Gas Emission Standards and Corporate Average Fuel Economy Standards were finalized by EPA on May 7, 2010. Starting January 2, 2011, “major sources” of greenhouse gases, as defined by the EPA’s “Tailoring Rule” issued on June 3, 2010, will be required to obtain air quality permits under the Clean Air Act’s Prevention of Significant Deterioration Program. In addition, on September 22, 2009, the EPA issued a final rule requiring the reporting of GHG emissions from specified large GHG emission sources in the U.S. beginning in 2011 for emissions occurring in 2010. On November 30, 2010, the EPA issued a final rule requiring reporting of GHG emissions from the oil and gas industry. The adoption and implementation of any regulations imposing reporting obligations on, or limiting emissions of GHGs from, the Company’s equipment and operations could require the Company to incur costs to reduce emissions of GHGs associated with the Company’s operations or could adversely affect demand for the oil, NGL and gas that the Company produces. Moreover, lawsuits have been filed seeking to require individual companies to reduce GHG emissions from their operations. These and other lawsuits relating to GHG emissions may result in decisions by state and federal courts and agencies that could impact our operations.

Although various climate change legislative measures have been under consideration by the U.S. Congress, it is not possible at this time to predict whether or when Congress may act on climate change legislation. In addition, more than one-third of the states, either individually or through multi-state regional initiatives, already have begun implementing legal measures to reduce emissions of GHGs, primarily through the planned development of emission inventories or regional greenhouse gas cap and trade programs. Finally, other nations have been seeking to reduce emissions of GHGs pursuant to the United Nations Framework Convention on Climate Change, also known as the “Kyoto Protocol,” an international treaty pursuant to which participating countries (not including the U.S.) have agreed to reduce their emissions of GHGs to below 1990 levels by 2012. Depending on the particular jurisdiction in which the Company’s operations are located, it could be required to purchase and surrender allowances for GHG emissions resulting from the Company’s operations.

See also the discussion of drilling permits in Item 7. Risks and Uncertainties.

North Sea

Our proved reserves in the North Sea are located in the U.K. sector. Related government regulations in the U.K. are discussed below.

Regulation of Oil and Natural Gas Production. Pursuant to the Petroleum Act 1998, all oil and natural gas reserves contained in properties located in the U.K. are the property of the U.K. government. The development and production of oil and natural gas 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 Energy and Climate Change (the “Secretary of State”) a consent to commence field development. We would be required to obtain the consent of the Secretary of State prior to transferring an interest in a license. The Petroleum Act 1998 also regulates the abandonment of facilities by licensees.

The terms of U.K. petroleum production licenses are based on model license clauses applicable at the time of issuance of the license. Licenses frequently contain regulatory provisions governing matters such as

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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 is precluded from carrying out development or production activities other than with the consent of the Secretary of State or in accordance with a development plan which the Secretary of State has approved. Breach of these requirements may result in the revocation of the license. In addition, licenses may require payment of fees and royalties on production and also impose certain other duties.

The Petroleum Act 1998 imposes health and safety regulations on our offshore oil and natural gas production activities in the U.K. In addition, the Mineral Workings (Offshore Installations) Act 1971 provides a framework in which the government can impose additional regulations relating to health and safety. Since its enactment, a number of regulations have been promulgated relating to offshore construction and operation of offshore production facilities. Health and safety offshore is further governed by the Health and Safety at Work Act 1974 and applicable regulations.

Environmental Regulations. Our operations are subject to environmental laws and regulations imposed by both the European Union and the U.K. government. The offshore industry in the U.K. is regulated with regard to the environment before and during the conduct of exploration and production activities. The licensing requirements employ a preventive and precautionary approach. This is evident in the consultation that takes place before a U.K. licensing round begins, whereby the Secretary of State, acting through the Department of Energy and Climate Change, 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.

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 oil and natural gas 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 conducted them ourselves.

Pipelines and Transportation. Our operations in the U.K. may entail the construction of offshore pipelines, which are subject to the provisions of the Petroleum Act 1998 and other legislation. The Petroleum Act 1998 requires a license to construct and operate a pipeline in U.K. North Sea, including its continental shelf. Easements to permit the laying of pipelines must be obtained from the Crown Estate Commissioners prior to their construction. We plan to use capacity in existing offshore pipelines in order to transport our gas. However, access to the pipelines of a third party would need to be obtained on a negotiated basis, and there is no assurance that we can obtain such access to existing pipelines, or obtain access on terms that are favorable to us.

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

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

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Employees

At December 31, 2010 we had 55 full-time employees in our Houston office, 7 full-time employees in our U.K. office and 2 full-time employees in our Netherlands office. None of our employees is covered by a collective bargaining agreement. We regularly use the services of independent consultants and contractors to perform various professional services, particularly in the areas of construction, design, well-site supervision, permitting and environmental assessment. Independent contractors usually perform field and on-site production operation services for us, including gauging, maintenance, dispatching, inspection and well testing.

Available Information

Our Internet website iswww.atpog.com and you may access, free of charge, through the Investor Relations section of our website, our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to such reports filed or furnished pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934, as amended, as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC. Information contained on our website is not part of this report. Also, the SEC maintains an internet site (www.sec.gov) that contains reports, proxy and other information about the Company. The Company will provide a copy of the Form 10-K annual report upon the written request of any shareholder. Financial information regarding our operating segments is set forth in Note 14, “Segment Information” of the Notes to Consolidated Financial Statements.

Item 1A.Risk Factors.

You should carefully consider the following risks in addition to the other information included in this report. Each of these risks 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.

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

We have been dependent on debt and equity financing to fund our cash needs that are not funded from operations or the sale of assets. In addition, 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 or to pay interest and principal on our debt obligations. Furthermore, we have incurred losses in the past that may affect our ability to obtain financing. Quantifying or predicting the likelihood of any or all of these occurring is difficult in the current domestic and world economy. For these reasons, financing may not be available to us in the future on acceptable terms or at all. In the event additional capital is required but not available on acceptable terms, we would curtail our acquisition, drilling, development and other activities or could be forced to sell some of our assets on an untimely or unfavorable basis.

Our 2011 development plans in the Gulf of Mexico, as well as our longer term business plan, are dependent on receiving approval for deepwater drilling and other permits submitted to the BOEM. While we believe we can satisfy the permitting requirements for our planned 2011 development wells which will allow us to significantly increase our production from current levels, there is no assurance that they will be received in time to benefit our 2011 results or that permits will be issued in the future. Should the permitting process in the Gulf of Mexico continue to be delayed, we believe we can continue to meet our existing obligations for at least the next twelve months; however, absent alternative funding sources, our ability to do so is dependent on maintaining existing production levels from our currently producing wells and maintaining commodity prices and operating costs near current levels. The size of our operations and our capital expenditures budget limit the number of properties that we can develop in any given year and a substantial portion of our current production is concentrated among relatively few wells located offshore in the Gulf of Mexico and in the North Sea, which are characterized by rapid production declines. As a result, we are particularly vulnerable to a near term severe impact resulting from unanticipated complications in the development of, or production from, any single material well or infrastructure installation, including lack of sufficient capital, delays in receiving necessary drilling and operating permits, increased regulation, reduced access to equipment and services, mechanical or operational failures, and bad weather. Any unanticipated significant disruption to, or decline in, our current production levels or negative changes in current commodity prices or operating cost levels could have a material adverse effect on our financial position, results of operations and cash flows and our ability to meet our commitments as they come due. We have historically obtained various other sources of funding to

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supplement our cash flow from operations and we will continue to pursue them in the future, however, there is no assurance that these alternative sources will be available should these risks and uncertainties materialize. We recently amended our first lien credit facility to provide for an increase to the principal amount from the current $150 million to the lesser or $210 million or 10% of the Company’s Adjusted Consolidated Net Tangible Assets, which we expect will provide an additional $60 million, before transaction costs, of available liquidity.

Our longer term liquidity is also dependent on our ability to bring the next two wells at Telemark on production in the near term and continuing to operate in the Gulf of Mexico, which we expect will generate sufficient cash flows to fund subsequent development projects and service our long-term debt and other obligations. Our longer term liquidity is also dependent on the prevailing prices for oil and natural gas which have historically been very volatile. To mitigate future price volatility, we may continue to hedge the sales price of a portion of our future production.

The U.S. governmental and regulatory response to the Deepwater Horizon drilling rig accident and resulting oil spill could have a prolonged and material adverse impact on our Gulf of Mexico operations.

On April 20, 2010, a semi-submersible drilling rig operating in the deepwater Outer Continental Shelf (“OCS”) in the Gulf of Mexico exploded, burned for two days and sank, resulting in an oil spill in Gulf of Mexico waters. In response to this crisis, the DOI, on May 6, 2010, instructed the MMS to stop issuing drilling permits for OCS wells and to suspend existing OCS drilling permits issued after April 20, 2010, until May 28, 2010, when a report on the accident was expected to be completed. On May 28, 2010, DOI issued a moratorium (“Moratorium I”), originally scheduled to last for six months, that essentially halted all drilling in water depths greater than 500 feet in the Gulf of Mexico. On June 7, 2010, a lawsuit was filed by several suppliers of services to Gulf of Mexico exploration and production companies challenging the legality of Moratorium I. This challenge was successful and on June 22, 2010, a Federal District Court issued a preliminary injunction preventing Moratorium I from taking effect. On July 8, 2010, the United States Court of Appeals for the Fifth Circuit denied the DOI’s motion to stay the preliminary injunction against the enforcement of Moratorium I. On July 12, 2010, in response to the Court’s actions, the DOI issued a second moratorium (“Moratorium II”) originally scheduled to end on November 30, 2010 that (i) specifically superseded Moratorium I, (ii) suspended all existing operations in the Gulf of Mexico and other regions of the OCS utilizing a subsea blowout preventer (“BOP”) or a surface BOP on a floating facility, and (iii) suspended pending and future permits to drill wells involving the use of a subsurface BOP or a surface BOP on a floating facility. Several lawsuits challenging the legality of Moratorium II and, among other things, the BOEM handling of drilling permits and development plans were subsequently filed in different Federal District Courts, all of which have been consolidated into one case in a Federal District Court that is still pending. On October 12, 2010 the DOI lifted Moratorium II as to all deepwater drilling activity.

The lifting of Moratorium II, however, did not remove all restrictions on offshore drilling. According to DOI’s order lifting Moratorium II, prior to receiving new permits to drill wells, OCS lessees and operators must first comply with an earlier notice to lessees and operators issued by the BOEM that requires additional testing, third-party verification, training for rig personnel, and governmental approvals to enhance well bore integrity and the operation of BOPs and other well control equipment used in OCS wells, (“NTL 2010-No.5”). NTL 2010-No.5 was set aside by the Federal District Court on October 19, 2010, as having been improperly issued by BOEM. The DOI’s order lifting Moratorium II, however, also requires OCS lessees and operators to comply with BOEM’s Interim Final Rule entitled “Increased Safety Measures for Energy Development on the Outer Continental Shelf (the “Safety Interim Final Rule”) issued in September 2010, before recommencing deepwater operations. In general, the Safety Interim Final Rule incorporates the terms of NTL 2010-No.5 and establishes new safety requirements relating to the design of wells and testing of the integrity of well bores, the use of drilling fluids, and the functionality and testing of BOPs. Longer term, OCS lessees and operators will be required to comply with the BOEM’s new Final Workplace Safety Rule, also issued by BOEM in September 2010. The Final Workplace Safety Rule requires all OCS operators to implement all of the formerly voluntary practices in the American Petroleum Institute’s Recommended Practice 75, which includes the development and maintenance of a Safety and Environmental Management System, within one year after the date of the rule. In addition to these two rules, before a permit will be issued, each operator must

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demonstrate that it has enforceable obligations that ensure that containment resources are available promptly in the event of a deepwater blowout. Although Moratorium II has been lifted, we cannot predict with certainty when permits will be granted under the new requirements.

We cannot predict how federal and state authorities will further respond to the incident in the Gulf of Mexico or whether additional changes in laws and regulations governing oil and gas operations in the Gulf of Mexico will result. New regulations already issued will, and potential future regulations or additional statutory limitations, if enacted or issued, could, require a change in the way we conduct our business, increase our costs of doing business or ultimately prohibit us from drilling for or producing hydrocarbons in the Gulf of Mexico. We cannot predict if or how the governments of other countries in which we operate will respond to the accident in the Gulf of Mexico.

We have planned drilling operations in the deepwater Gulf of Mexico, some of which were permitted prior to April 20, 2010, and some of which are not yet permitted. Moratorium II has caused us to delay the third and fourth wells scheduled at our Telemark Hub and, even though Moratorium II has been lifted, any delays in the resumption of the permitting process may result in delays in our drilling operations scheduled in 2011 at our Gomez Hub as well. During 2010, a side-track well operation in 7,000 feet of water was interrupted when Moratorium I was imposed and work on that project stopped, resulting in the early termination of a drilling contract. In the course of obtaining a full release from our obligations under the contract, we incurred net costs of $8.7 million reflected as drilling interruption costs on our Consolidated Statements of Operations. Additionally, because the necessary deepwater drilling permits were not issued, drilling interruption costs also include $14.9 million of stand-by costs related to drilling operations at our Telemark and Gomez Hubs.

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

The size of our operations and our capital expenditures budget limits the number of properties that we can develop in any given year. Complications in the development of any single major well or infrastructure installation may result in a material adverse effect on our financial condition and results of operations. For example, during 2010 our operations have been curtailed due to the imposition of the deepwater drilling moratoriums and permitting slowdown discussed above. We cannot predict with certainty if or when the BOEM will issue to us the necessary deepwater drilling permits to us. During 2009, delays obtaining workover permits for an operation at our Gomez Hub pushed completion of the workover from the fourth quarter of 2009 to late January 2010. During 2008, we experienced production delays and increased costs at our High Island A-589 project in the Gulf of Mexico. Also, see the above discussion of the U.S. regulatory response to the Deepwater Horizon drilling rig accident.

In addition, relatively few wells contribute a substantial portion of our production. If we were to experience operational problems or adverse commodity prices resulting in the curtailment of production in any of these wells, our total production levels would be adversely affected, which would have a material adverse effect on our financial condition and results of operations. For example, during September 2008, Hurricane Ike caused wide-spread damage to many pipelines in the Gulf of Mexico. While our facilities suffered only minimal damage, production curtailments resulting from damages to third-party infrastructure, especially downstream of the Gomez Hub, significantly impacted our cash flows for several months.

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

Estimates of our oil and natural gas reserves and the costs and timing associated with developing these reserves may not be accurate. Additionally, at December 31, 2010, approximately 81% of our total proved reserves are classified as undeveloped. Development of these reserves may not yield the expected results, or the development may be delayed or the development costs may exceed our estimates, any of which may materially affect our financial position and results of operations. Development activity may result in downward adjustments of reserves or higher than estimated costs.

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

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

We have significant debt, trade payables, other long-term obligations.

Our trade payables, other long-term obligations and related interest payment requirements and scheduled debt maturities may have important negative consequences. For instance, they could:

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

• require us to dedicate a substantial portion of any cash flow from operations to the payment of overriding royalties or 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 financial obligations and commitments 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 inability to meet our financial obligations and commitments will impede the successful execution of our business strategy and the maintenance of our economic viability.

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

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

Historically, the markets for oil and natural gas have been volatile, and they are likely to continue to be volatile. For example, oil and natural gas prices increased significantly in late 2000 and early 2001 and then steadily declined in 2001. This phenomenon occurred again beginning in 2004 when oil prices began to climb and reached an all-time high in mid 2008. By the end of 2008, oil had lost nearly two-thirds of its value, dropping from a high of $146 per barrel in July 2008 to a close of $45 per barrel in December 2008. In February 2009, oil closed at its lowest price for the year of $33.98 per barrel. In 2010, oil has climbed to over $90 per barrel toward the end of the year. Among the factors that have caused and may continue to cause this volatility are:

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

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

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• volatility in the value of the U.S. dollar relative to other currencies;

• governmental regulations or lack of regulations around the world;

• the continuation of Moratorium II after October 12, 2010 and the uncertainty of when the BOEM will issue permits for deepwater drilling;

• political conditions in oil or natural gas producing regions;

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

• speculative trading in crude oil and natural gas derivative contracts;

• weather conditions; and

• price and availability of alternative fuels.

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

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, managing and retaining skilled personnel necessary to support our rapid growth;

• 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.

Our success depends on dedicated and skillful management and staff, whose departure 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, 2010, we had 27 engineers, geologist/geophysicists and other technical personnel in our Houston office, 3 engineers, geologist/geophysicists and other technical personnel in our U.K. location and 1 engineer in our Netherlands office. We depend to a large extent on the efforts, technical expertise and continued employment of these personnel and members of our management team. If a significant number of them resign or become unable to continue in their present role and if they are not adequately replaced, our business operations could be adversely affected.

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

We maintain insurance to protect the Company and its subsidiaries against losses arising out of our oil and gas operations. Our insurance includes coverage for physical damage to our offshore properties, general (third party) liability, workers compensation and employers liability, seepage and pollution and other risks. Our insurance includes various limits and deductibles or retentions, which must be met prior to or in conjunction with recovery. Additionally, our insurance is subject to the terms, conditions and exclusions of such policies. For losses emanating from offshore operations, ATP has up to an aggregate of $2.1 billion of various insurance coverages with individual policy limits ranging from $1.0 million to over $500 million each. While we maintain insurance levels, deductibles and retentions that we believe are prudent and responsible, there is no assurance that such coverage will adequately protect us against liability from all potential consequences and damages.

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In general, our current insurance policies cover physical damage to our oil and gas assets. The coverage is designed to repair or replace assets damaged by insurable events.

Our excess liability policies generally provide coverage (dependent on the asset) for bodily injury and property damage, including coverage for negative environmental effects such as seepage and pollution. This liability coverage would cover claims for bodily injury or death brought against the company by or on behalf of individuals who are not employees of the company. The liability limits scale to either our operating interest or the total insured interest including nonoperating partners.

Our energy insurance package includes coverage for operator’s extra expense, which provides coverage for control of well, re-drill and pollution arising from a covered event. We maintain a $150 million Oil Spill Financial Responsibility policy in order to provide a Certificate of Financial Responsibility to the BOEM under the requirements of the Oil Pollution Act of 1990. Additionally, as noted above, our excess liability policies provide coverage (dependent on the asset) for bodily injury and property damage, including coverage for negative environmental effects such as seepage and pollution. Legislation has been proposed to increase the limit of the Oil Spill Financial Responsibility policy required for the certificate and there is no assurance that we will be able to obtain this insurance should that happen.

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

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

We utilize derivative instruments and fixed-price forward sales contracts with respect to a portion of our expected production, in order to manage our exposure to oil and natural gas price volatility. These instruments expose us to risk of financial loss if:

• production is less than expected for forward sales contracts;

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

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

Our results of operations may be negatively impacted in the future by our derivative instruments and fixed-price forward sales contracts as these instruments may limit any benefit we would receive from increases in the prices for oil and natural gas.

Potential regulations under the Dodd-Frank Act regarding derivatives could adversely impact our ability to engage in commodity price risk management activities.

Periodically we enter into commodity derivative contracts as an economic hedge on a portion of our oil and natural gas sales. On July 21, 2010, Congress enacted the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”), which imposes a comprehensive regulatory scheme significantly impacting companies engaged in over-the-counter (“OTC”) swap transactions. The Dodd-Frank Act generally applies to “swaps” entered into by “major swap participants” and/or “swap dealers,” each as defined in the Dodd-Frank Act. A swap is very broadly defined in the Dodd-Frank Act and includes an energy commodity swap. A swap dealer includes an entity that regularly enters into swaps with counterparties as an “ordinary course of business for its own account.” Furthermore, a person may qualify as a major swap participant if it maintains a “substantial position” in outstanding swaps, other than swaps used for “hedging or mitigating commercial risk” or whose positions create substantial exposure to its counterparties or the U.S. financial system. The Dodd-Frank Act subjects swap dealers and major swap participants to substantial supervision and

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regulation by the U.S. Commodity Futures Trading Commission (“CFTC”), including capital standards, margin requirements, business conduct standards, and recordkeeping and reporting requirements. It also requires most regulated swaps to be cleared through a derivatives clearing organization (“DCO”) registered with the CFTC. By clearing through a DCO, each party to a swap will be required to provide collateral to the DCO to settle, on a daily basis, any credit exposure resulting from fluctuations in market prices. The CFTC also has the authority to impose position limits on companies trading in OTC derivatives markets. Although the Dodd-Frank Act provides a framework for regulating OTC swap transactions, the substance of the Act will be set forth in numerous rules subsequently promulgated by the CFTC and other agencies. Because the CFTC has not yet clearly articulated the scope of key definitions in the Dodd-Frank Act, such as “swap,” “swap dealer” and “major swap participant,” and because the parameters of Dodd-Frank Act requirements are still shifting, it is impossible to know exactly how the Dodd-Frank Act will impact our business. However, the issuance of any rules or regulations relating to the Dodd-Frank Act that subject us to additional business conduct standards, position limits and/or reporting, capital, margin or clearing requirements with respect to our energy commodity swap risk management positions could have an adverse effect on our ability to hedge risks associated with our business or on the cost of our hedging activities. If we are required to post collateral as a result of new rules, we would have to do so by utilizing cash or letters of credit, to the extent allowed by our credit agreements, which would reduce our liquidity position and increase costs. These changes could materially reduce our hedging opportunities and increase the costs associated with our hedging programs, both of which could negatively affect our cash flow.

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

Shortages or increases in the 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. Changes in the level of drilling activity in the Gulf of Mexico and the North Sea affects the availability of offshore rigs and associated equipment. In periods of increased drilling activity in the Gulf of Mexico and the North Sea, we may experience increases in associated costs, including those related to drilling rigs, equipment, supplies and personnel and the services and products of other vendors to the industry. These costs may increase further and necessary equipment and services may not be available to us at economical prices. For the years ended December 31, 2010, 2009 and 2008, we recorded losses on abandonment of $4.8 million, $2.9 million and $13.3 million, respectively, primarily as a result of unanticipated increases in service costs in the Gulf of Mexico.

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

The net assets, net earnings and cash flows from our wholly owned subsidiaries in the U.K. and the Netherlands are based on the U.S. dollar equivalent of such amounts measured in the applicable local currency. These foreign operations have the potential to impact our financial position due to fluctuations in exchange rates. Any increase in the value of the U.S. dollar in relation to the value of the local currency will adversely affect our revenues from our foreign operations when translated into U.S. dollars. Similarly, any decrease in the value of the U.S. dollar in relation to the value of the local currency will increase our development costs in our foreign operations, to the extent such costs are payable in foreign currency, when translated into U.S. dollars. We currently have no derivatives or other financial instruments in place to hedge the risk associated with the movement in foreign currency exchange rates.

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

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

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

• fires;

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• explosions;

• blow-outs and surface cratering;

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

• pipe, cement, subsea well or pipeline failures;

• casing collapses;

• embedded oil field drilling and service tools;

• abnormally pressured formations;

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

• hurricanes and other natural disasters.

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

• injury or loss of life;

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

• pollution and other environmental damage;

• clean-up responsibilities;

• regulatory investigation and penalties;

• suspension of our operations; and

• repairs to resume operations.

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

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

Reservoirs in the Gulf of Mexico are typically prolific producers due to their high permeability and efficient completions. Reserves can therefore be produced rapidly. As of December 31, 2010, we project normalized annual decline rates of 22% for oil and 10% for gas in our Gulf of Mexico deepwater fields. While this results in recovery of a relatively higher percentage of reserves from Gulf of Mexico properties during the initial years of production, we must incur significant capital expenditures to replace declining production.

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

We may incur substantial impairment write-downs.

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

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If management’s estimates of the recoverable reserves on a property are revised downward, if development costs exceed previous estimates or if oil and natural gas prices decline, we may be required to record additional noncash impairment write-downs in the future, which would result in a negative impact to our financial position and earnings. We review our proved oil and gas properties for impairment on a depletable unit basis whenever events or changes in circumstances indicate that an asset’s carrying amount may not be recoverable. To determine if a depletable unit is impaired, we compare the carrying value of the depletable unit to the undiscounted future net cash flows by applying management’s estimates of future oil and gas prices to the estimated future production of oil and gas reserves over the economic life of the property and deducting estimated future operating and development costs. Future net cash flows are based upon reservoir engineers’ estimates of proved reserves. In addition, other factors such as probable and possible reserves are taken into consideration when justified by economic conditions and actual or planned drilling or other development activities. For a property determined to be impaired, an impairment loss equal to the excess of the carrying value over 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 impairments of proved properties are aggregated in accumulated depletion, depreciation, amortization and impairment, and reduce our basis in the asset. Each part of this calculation is subject to a large degree of judgment, including the determination of the depletable units’ estimated reserves, future net cash flows and fair value. We recorded impairments during the years ended December 31, 2010, 2009 and 2008 totaling $42.4 million, $44.6 million and $124.7 million, respectively, on certain proved properties in the Gulf of Mexico. We also recorded impairments totaling $14.9 million during 2010, on certain proved properties in the North Sea.

Impairments of unproved properties were $6.0 million, $1.2 million and $0.4 million in 2010, 2009 and 2008, respectively, primarily related to surrendered leases in the Gulf of Mexico.

Management’s assumptions in calculating oil and gas reserves or estimating the future cash flows or fair value of our properties are subject to change at any time as economic conditions change. Changes in reserve volumes or commodity price forecasts will directly impact our estimates of future cash flows and property fair values. Adverse changes in these variables could result in the recognition of impairment expense, which would reduce our net income (or increase a net loss) and reduce our basis in the related asset.

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

Acquiring oil and gas properties requires us to assess reservoir and infrastructure characteristics, 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 created prior to our purchase of the property. We may be required to assume the risk of the physical condition of the properties in addition to the risk that the properties may not perform in accordance with our expectations.

Competition in our industry is intense, and we are smaller than some of our competitors in the Gulf of Mexico and in the North Sea.

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

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

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Members of our management team beneficially own approximately 13% of our outstanding shares of common stock at March 2, 2011. As a result, these shareholders are in a position to significantly influence the outcome of matters requiring a shareholder vote, including the election of directors, the adoption of an amendment to our articles of incorporation and the approval of mergers and other significant corporate transactions. Their influence may delay or prevent a change of control and may adversely affect the voting and other rights of other shareholders.

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

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

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

As discussed above, development, production and sale of oil and natural gas in the Gulf of Mexico and in the North Sea are subject to extensive laws and regulations, including environmental laws and regulations. We may be required to make large expenditures to comply with environmental and other governmental regulations.

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.

Legislation and regulations pertaining to climate change and greenhouse gas emissions have the potential to materially adversely impact our business, financial condition, results of operations and cash flows, including costs of compliance and permitting delays. The extent and magnitude of these adverse impacts cannot be reliably or accurately estimated at this time because specific regulatory and legislative requirements have not been finalized and uncertainty exists with respect to the measures being considered, the costs and the time frames for compliance, and our ability to pass compliance costs on to our customers.

Certain federal income tax deductions currently available with respect to oil and gas exploration and development may be eliminated as a result of future legislation.

Periodically, legislation is introduced to eliminate certain key U.S. federal income tax preferences currently available to oil and gas exploration and production companies. Such changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and gas properties; (ii) the elimination of current deductions for intangible drilling and development costs; (iii) the elimination of the deduction for certain U.S. production activities; and (iv) an extension of the amortization period for certain geological and geophysical expenditures. These changes were included in the White House budget proposals, released on February 26, 2009, February 1, 2010 and February 14, 2011 and may be raised again in the future. Additionally, since the first White House proposal multiple bills have been proposed in Congress to implement many of these changes. It is unclear, however, whether any of these changes will be enacted or how soon they could be effective.

Our ability to use our net operating losses to offset our future taxable income may be severely limited under Section 382 of the Internal Revenue Code.

Section 382 of the Internal Revenue Code of 1986, as amended (the “I.R.C.”), generally limits the ability of a corporation that undergoes an “ownership change” to utilize its net operating loss carryforwards (“NOLs”) and certain other tax attributes against future taxable income in periods after the ownership change. The amount of taxable income in each tax year after the ownership change that may be offset by pre-change NOLs and certain other pre-change tax attributes is generally equal to the product of (a) the fair market value of the corporation’s outstanding stock immediately prior to the ownership change and (b) the long-term tax exempt

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rate (i.e., a rate of interest established by the Internal Revenue Service that fluctuates from month to month.) In general, an “ownership change” occurs whenever the percentage of the stock of a corporation owned, directly or indirectly, by “5-percent stockholders” (within the meaning of Section 382 of the I.R.C.) increases by more than 50 percentage points over the lowest percentage of the stock of such corporation owned, directly or indirectly, by such “5-percent stockholders” at any time over the preceding three years.

Our NOLs and certain other tax attributes are subject to an annual limitation as a result of an ownership change we experienced in November 2007. Additional ownership changes could further reduce our annual NOL limitation if our equity value at the time of the ownership changes is significantly below our equity value as of the date of the November 2007 ownership change. Issuances of our stock, sales or other dispositions of our stock by certain significant stockholders, certain acquisitions of our stock and issuances, sales or other dispositions or acquisitions of interests in certain significant stockholders could trigger additional ownership changes. We have little or no control over any such events. If additional ownership changes occur, any further limitation on our use of NOLs and certain other tax attributes to offset our taxable income could result in a significant increase in our future income tax payments, and could negatively affect our financial condition, results of operation and our ability to make payments on our outstanding indebtedness.

Item 1B.Unresolved Staff Comments.

None

Item 2.Properties.

General

We are engaged in the acquisition, development and production of oil and natural gas properties in the Gulf of Mexico and the North Sea. At December 31, 2010, we owned leasehold and other interests in 51 offshore blocks and 88 wells, including 24 subsea wells, in the Gulf of Mexico. We operate 82 (93%) of these wells, including 100% of the subsea wells. We also had interests in 13 blocks and three company-operated subsea wells in the North Sea. Our average working interest in our properties at December 31, 2010 was approximately 83%. As of December 31, 2010, we had leasehold interests located in the Gulf of Mexico and North Sea covering approximately 321,600 gross and 249,254 net acres, respectively, of which 182,283 gross acres (128,165 net acres) were developed.

As of the date of this report, we own an interest in 29 platforms, including two floating production facilities in the Gulf of Mexico, theATP Titan at our Telemark Hub and theATP Innovatorat our Gomez Hub. These floating production facilities are fundamental to our hub strategy and business plan. The presence of these facilities allows us a competitive advantage for additional acquisitions in a large area surrounding each installation. A third floating production facility called an Octabuoy is under construction in China for initial deployment at our Cheviot Hub in the U.K. North Sea. We operate theATP Innovator and theATP Titanand also expect to operate the Octabuoy when it is placed in service. The floating production facilities have longer useful lives than the underlying reserves and are capable of redeployment to new producing locations upon depletion of the reserves. Accordingly they are expected eventually to be moved several times over their useful lives.

Gulf of Mexico

Acquisitions and Dispositions– During May and June 2010, the BOEM awarded us leases for 100% of the working interests in the Garden Banks Block 782 (“Entrada”) and the Ship Shoal (“SS”) Block 361, respectively. SS Block 361 is in close proximity to our SS Block 358 Hub. Entrada is in the vicinity of existing infrastructure owned by others. We paid $0.4 million for these leases.

During January 2010, we consummated a nonmonetary exchange of our 10% nonoperated working interest in Mississippi Canyon (“MC”) Block 800, for an incremental 50% working interest in MC Block 754, both proved undeveloped properties. Our consolidated financial statements reflect the incremental interest acquired in MC Block 754 at fair value and removal of the carrying costs of MC Block 800, resulting in recognition of a $12.0 million gain.

During January 2010, we acquired a 100% working interest in MC Block 710, an exploratory prospect adjacent to our Gomez Hub in MC Block 711 and surrounding blocks, in exchange for the conveyance of an overriding royalty interest in this block.

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During July 2010, we sold to a third party our 67% working interest in the deep operating rights of one of our Gulf of Mexico properties resulting in a $15.0 million gain.

Development – In 2010, we completed construction of theATP Titan – a floating production platform - allowing us to begin production from one well at Atwater Valley Block 63 in April 2010 and one well at Mirage (MC Block 941) in October 2010, both part of our Telemark Hub in the deepwater Gulf of Mexico. Two additional wells planned for development in 2010 at our Telemark Hub were delayed due to the events in the Gulf of Mexico. (See the drilling permit discussion in Item 7. Risks and Uncertainties.) The initial drilling of these two additional wells was performed in 2008. The remaining drilling and completion of the two additional wells will be performed from theATP Titanwhich will serve as the production platform for them as well. We have a 100% working interest in the Telemark Hub.

North Sea - Development

In the U.K. North Sea, we completed and began producing one exploratory well at Garrow. We operate Garrow with a 17% working interest.

Oil and Natural Gas Reserves

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

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

The following table presents our estimated net proved oil and natural gas reserves (all from traditional resources) at December 31, 2010 based on reserve reports prepared by independent petroleum engineers Collarini Associates and Ryder Scott Company, L.P. for our Gulf of Mexico reserves and Collarini Associates for our U.K. reserves. The technical personnel responsible for preparing the reserve estimates at both Collarini Associates and Ryder Scott Company, L.P. meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. Both are independent firms of petroleum engineers, geologists, geophysicists, and petrophysicists; they do not own an interest in our properties and are not employed on a contingent fee basis.

	Proved Reserves
	Developed		Undeveloped		Total
Gulf of Mexico
Oil and condensate (MBbls)		13,626		35,882		49,508
Natural gas (MMcf)		52,656		153,675		206,331
Total proved reserves (MBoe)		22,402		61,494		83,896
North Sea
Oil and condensate (MBbls)		4		25,617		25,621
Natural gas (MMcf)		8,323		93,118		101,441
Total proved reserves (MBoe)		1,391		41,137		42,528
Total
Oil and condensate (MBbls)		13,630		61,499		75,129
Natural gas (MMcf)		60,979		246,793		307,772
Total proved reserves (MBoe)		23,793		102,631		126,424

Our corporate reservoir engineering group has oversight and compliance responsibility for the internal reserve estimation process and provides data to the independent third-party engineers who estimate our reserves. The management of this group, which includes the Chief Operating Officer, consists of a degreed petroleum engineer with 28 years of industry experience, including 12 years of experience managing ATP’s reserves. Annually, this petroleum engineer attends continuing technical education courses. He is a 26-year member of the Society of Petroleum Engineers.

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 oil and natural gas reserves is complex. It requires various

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assumptions, including assumptions relating to oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. We must project production rates and timing of development expenditures. We analyze available geological, geophysical, production and engineering data, and the extent, quality and reliability of this data can vary. Recovery of undeveloped reserves generally requires significant capital expenditures and successful drilling and completion operations. Although the reserves and the costs associated with developing them are estimated in accordance with SEC standards, the estimated costs may be inaccurate, development may not occur as scheduled and results may not be as estimated. Therefore, estimates of oil and natural gas reserves are inherently imprecise. Estimates of reserves may increase or decrease as a result of future operations.

Proved Undeveloped Reserves (“PUDs”)

As of December 31, 2010, our PUDs totaled 61.5 MMBbls of crude oil and 246.8 Bcf of natural gas, for a total of 102.6 MMBoe. As of December 31, 2009, our PUDs totaled 70.1 MMBbls of crude oil and 286.0 Bcf of natural gas for a total of 117.8 MMBoe. The 15.2 MMBoe decrease in PUDs in 2010 is primarily due to conversion of 13.5 MMBoe of PUDs into proved developed reserves at our Telemark Hub and 3.6 MMBoe of divestitures and revisions of estimates partially offset by the acquisition of 1.9 MMBoe of PUDs at Entrada. Costs incurred relating to the development of PUDs in 2010 were approximately $626 million, excluding capitalized interest. Approximately 48% of our PUDs at December 31, 2010 were associated with our major development hubs at Telemark and Gomez in the Gulf of Mexico. We had planned to convert additional reserves to proved developed during 2010 at these two hubs, however due to delays in obtaining drilling permits, those expected conversions are delayed into 2011 and beyond. An additional 38% of PUDs at December 31, 2010 were associated with an active development project at the Cheviot field in the U.K. sector of the North Sea discussed further below.

At December 31, 2010, the reserves at our Cheviot field which were first booked in 2005 have been classified as undeveloped for more than five years. This field is in the northern part of the North Sea in a water depth of over 500 feet. Our original development plan for the field included the use of a concrete structure platform; however due to environmental regulations in the European Union imposed after acquisition of Cheviot this type of structure was subsequently disallowed in the North Sea and our development plan had to be modified to utilize a floating production platform. With the knowledge of the U.K. DECC, the development of the field was delayed while we modified our development plan to engineer and incorporate the floating structure into our plans. In late 2008, we contracted with a shipyard in China and commenced construction of the floating production platform. The hull of the platform is now approximately 70% complete and the ship yard has begun construction of the topsides. The remaining construction of the platform, installation of the pipelines and drilling of the wells will require the next three years to complete, allowing expected first production to take place in 2014. During 2010, ATP incurred costs of approximately $132 million related to this project bringing the total in excess of $275 million through December 31, 2010 and we remain committed to this development.

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Standardized Measure of Cash Flows

At December 31, 2010 our standardized measure of discounted future net cash flows was $2.3 billion. The present value of future net pre-tax cash flows attributable to estimated net proved reserves, discounted at 10% per annum, (“PV-10”) is a computation of the standardized measure of discounted future net cash flows on a pre-tax basis. The table below provides a reconciliation of PV-10 to the standardized measure of discounted future net cash flows at December 31, 2010. PV-10 may be considered a non-GAAP financial measure under the SEC’s regulations. We believe PV-10 to be an important measure for evaluating the relative significance of our oil and natural gas properties. PV-10 is computed on the same basis as the standardized measure of discounted future net cash flows but without deducting income taxes. We further believe investors and creditors may utilize our PV-10 as a basis for comparison of the relative size and value of our reserves to other companies. However, PV-10 is not a substitute for the standardized measure. Our PV-10 measure and the standardized measure of discounted future net cash flows (shown below in thousands) do not purport to present the fair value of our oil and natural gas reserves.

Net present value of future net cash flows, before income taxes	$	2,600,256
Future income taxes, discounted at 10%		(251,496	)
Standardized measure of discounted future net cash flows	$	2,348,760

Significant Properties

The following table sets forth reserve information on our more significant properties as of December 31, 2010 and related net production for the years indicated:

Field	Development Location		Net Total Proved Reserves MBoe		Net Total Proved Undeveloped Reserves MBoe		2010 Net Production MBoe		2009 Net Production MBoe		2008 Net Production MBoe
Telemark Hub (1)		GOM		46,429		34,433		1,356		—		—
Gomez Hub (1)		GOM		21,375		15,254		3,132		2,709		4,601
Cheviot (2)		N. Sea		38,929		38,929		—		—		—
				106,733		88,616		4,488		2,709		4,601
Total Company				126,424		102,631		7,663		5,873		9,578

(1) Contains shut-in reserves and/or undeveloped reserves that are scheduled to be produced in 2011 subject to the timely receipt of permits from the BOEM (See Risks and Uncertainties under Item 7.)

(2) First production is expected in 2014.

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Drilling Activity

The following table shows our drilling and well completion activity for the three years ended December 31, 2010. In the table, “gross” refers to the total wells in which we have a working interest and “net” refers to gross wells multiplied by our working interest in such wells.

	Gulf of Mexico						North Sea
	2010		2009		2008		2010		2009		2008
Gross Development Wells:
Productive		2.0		2.0		6.0				2.0		—
Nonproductive		—		—		—		—		—		—
Total		2.0		2.0		6.0				2.0		—
Net Development Wells:
Productive		2.0		1.6		5.5		—		0.4		—
Nonproductive		—		—		—		—		—		—
Total		2.0		1.6		5.5				0.4		—
Gross Exploratory Wells (1):
Productive		—		—		2.0		1.0		—		—
Nonproductive		—		—		—		—		—		—
Total		—		—		2.0		1.0		—		—
Net Exploratory Wells (1):
Productive		—		—		0.4		0.2		—		—
Nonproductive		—		—		—		—		—		—
Total		—		—		0.4		0.2		—		—
Total Gross Wells:
Productive		2.0		2.0		8.0		1.0		2.0		—
Nonproductive		—		—		—		—		—		—
Total		2.0		2.0		8.0		1.0		2.0		—
Total Net Wells:
Productive		2.0		1.6		5.9		0.2		0.4		—
Nonproductive		—		—		—		—		—		—
Total		2.0		1.6		5.9		0.2		0.4		—

(1) During 2010, we drilled 2.0 gross exploratory wells (0.3 net wells) in the North Sea which are still being evaluated.

At December 31, 2010, 3.0 gross development wells (2.5 net wells) were partially drilled but not completed in the Gulf of Mexico.

Productive Wells

The following table presents the number of productive oil and natural gas wells in which we owned an interest as of December 31, 2010:

	Gulf of Mexico		North Sea		Total
Gross
Natural gas		18.0		9.0		27.0
Oil		17.0		—		17.0
Total		35.0		9.0		44.0
Net
Natural gas		15.7		2.0		17.7
Oil		12.0		—		12.0
Total		27.7		2.0		29.7

At December 31, 2010, we had one gross natural gas well with multiple completions.

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Acreage

The following table summarizes our developed and undeveloped acreage holdings at December 31, 2010. 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		139,897		117,425		97,160		93,146		237,057		210,571
North Sea		42,386		10,740		42,157		27,943		84,543		38,683
Total		182,283		128,165		139,317		121,089		321,600		249,254

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

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

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

Year Ending December 31,:	Gulf of Mexico				North Sea				Total
	Gross		Net		Gross		Net		Gross		Net
2011		11,520		11,520		11,703		11,703		23,223		23,223
2012		17,280		15,840		8,644		5,335		25,924		21,175
2013		5,760		5,760		21,810		10,905		27,570		16,665
2014 & beyond		62,600		60,026		—		—		62,600		60,026
Total		97,160		93,146		42,157		27,943		139,317		121,089

The North Sea leases expiring in 2011 include 11,703 acres related to proved reserves which are actively being developed and as such the lease term will be extended beyond the stated expiration.

Production and Pricing Data

See additional information on production and pricing contained in Item 7. – “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations”.

Item 3.Legal Proceedings.

On January 29, 2010, Bison Capital Corporation (“Bison”) filed suit against ATP in the United States District Court for the Southern district of New York alleging ATP owed fees totaling $102 million to Bison under a February 2004 agreement. The case was tried in January 2011. On March 8, 2011 the Court entered a judgment in favor of Bison for $1.65 million plus prejudgment interest and Bison’s reasonable attorney’s fees. Either party may file a notice of appeal within 30 days of the judgment. ATP has provided for this judgment in the financial statements as of December 31, 2010.

Item 4.(Removed and Reserved.)

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PART II

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

Our authorized capital stock consists of 100,000,000 shares of common stock, par value $0.001 per share, and 10,000,000 shares of preferred stock, par value $0.001 per share. There were 51,392,096 shares of common stock and 1,400,000 shares of 8% convertible perpetual preferred stock outstanding as of March 2, 2011. Our common stock is traded on the NASDAQ Global Select Market under the ticker symbol ATPG. The number of holders of our common stock and 8% convertible perpetual preferred stock as of March 2, 2011 is 13,544 and 42, respectively. The following table sets forth the range of high and low sales prices for the common stock as reported on the NASDAQ Global Select Market for the periods indicated below. Such over-the-counter market quotations reflect inter-dealer prices, without retail mark-up, mark-down or commission and may not necessarily represent actual transactions.

	High		Low
2009
1stQuarter	$	7.92	$	2.75
2nd Quarter		10.20		4.81
3rd Quarter		22.99		5.22
4th Quarter		21.87		14.40
2010
1stQuarter	$	20.57	$	12.72
2nd Quarter		23.97		8.16
3rd Quarter		14.73		8.85
4th Quarter		17.44		13.05

We have never declared or paid cash dividends on our common stock. We currently intend to retain future earnings and other cash resources, if any, for the operation and development of our business and do not anticipate paying cash dividends on our common stock in the foreseeable future. Payment of any future dividends will be at the discretion of our board of directors after taking into account many factors, including our financial condition, operating results, current and anticipated cash needs and plans for expansion. In addition, our current long-term debt limits the amount we can pay for cash dividends on our common stock. Further discussion of these restrictions is set forth in “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources – Long-term Debt” and in Note 6. “Long-term Debt” of the Notes to Consolidated Financial Statements. Any future dividends may also be restricted by any loan agreements which we may enter into from time to time. We pay quarterly dividends on outstanding shares of our convertible preferred stock at the annual rate of 8% of liquidation value.

Shareholder Return Performance Presentation

The information set forth in the graph and table below compares the value of our Common Stock to the NASDAQ Market Index, an “Old Peer Group Index” and a “New Peer Group Index,” each of which is comprised of independent oil and gas exploration and production companies with operations and assets focused in the Gulf of Mexico region. We have updated our peer group index this year to reflect market changes and have included only companies of similar size, geographic and strategic focus that would possess similar prospects for favorable stock price performance.

The Old Peer Group Index is comprised of the following companies: Callon Petroleum Company, Energy Partners, Ltd., Forest Oil Corporation (since June 2007), Helix Energy Solutions Group (since January 2006), Houston Exploration Company (through June 2007), Newfield Exploration Company, Noble Energy Inc., Plains Exploration & Production (since November 2007), Pogo Producing Company (through November 2007), Remington Oil and Gas Corporation (through December 2005) and Stone Energy Corporation.

The New Peer Group Index is comprised of the following companies: Callon Petroleum Company, Energy Partners, Ltd., Forest Oil Corporation (since June 2007), Helix Energy Solutions Group (since January 2006),

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Newfield Exploration Company, Plains Exploration & Production (since November 2007) and Stone Energy Corporation.

Each of the total cumulative returns presented assumes a $100 investment beginning December 31, 2005 and ending December 31, 2010. The performance of the indices is shown on a total return (dividend reinvestment) basis; however, we paid no dividends on our Common Stock during the period shown. The graph lines merely connect the beginning and end of the measuring periods and do not reflect fluctuations between those dates.

Total Return Analysis	12/31/05		12/31/06		12/31/07		12/31/08		12/31/09		12/31/10
ATP Oil & Gas Corporation	$	100.00	$	106.92	$	136.56	$	15.81	$	49.39	$	45.23
NASDAQ Composite Index		100.00		111.74		124.67		73.77		107.12		125.93
Old Peer Group Index		100.00		105.04		144.65		64.25		101.22		133.86
New Peer Group Index		100.00		97.67		121.12		39.41		66.80		93.86

The foregoing graph and related description shall not be deemed incorporated by reference into any filing under the Securities Act of 1933, as amended, or under the Exchange Act, except to the extent that we specifically incorporate this information by reference. In addition, the foregoing graph and the related description shall not be deemed “soliciting material” or to be “filed” with the SEC or subject to Regulation 14A or 14C under the Exchange Act.

Information relating to compensation plans under which our equity securities are authorized for issuance is set forth in Part III, Item 12 of this Annual Report on Form 10-K.

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Item 6.Selected Financial Data.

(In thousands, except per share data)

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

	Year Ended December 31,
	2010			2009			2008			2007			2006
Statement of Operations Data:
Revenues:
Oil and gas production	$	437,997		$	298,490		$	584,823		$	599,324		$	414,182
Other (1)		—			13,664			33,206			8,611			5,639
		437,997			312,154			618,029			607,935			419,821
Cost, operating expenses and other:
Lease operating		132,544			84,956			91,196			91,693			72,446
Exploration		1,174			264			48			13,756			2,231
General and administrative		44,894			44,211			41,653			32,018			32,976
Depreciation, depletion and amortization		220,657			152,780			246,434			247,378			169,704
Impairment of oil and gas properties		63,267			45,799			125,059			34,342			19,520
Accretion of asset retirement obligation		13,827			11,676			15,566			12,117			8,076
Drilling interruption costs (2)		23,647			—			—			—			—
Loss on abandonment		4,829			2,872			13,289			18,649			9,603
Gain on exchange/disposal of properties (3)		(26,720	)		(12,433	)		(119,233	)		—			—
Other, net		(946	)		(742	)		(99	)		(3,706	)		(7	)
		477,173			329,383			413,913			446,247			314,549
Income (loss) from operations		(39,176	)		(17,229	)		204,116			161,688			105,272
Other income (expense):
Interest income		696			710			3,476			7,603			4,532
Interest expense, net		(222,104	)		(40,884	)		(100,729	)		(121,302	)		(58,018	)
Derivative income (expense)		(22,419	)		(712	)		89,035			—			—
Loss on debt extinguishment		(75,316	)		—			(24,220	)		—			(28,115	)
		(319,143	)		(40,886	)		(32,438	)		(113,699	)		(81,601	)
Income (loss) before income taxes		(358,319	)		(58,115	)		171,678			47,989			23,671
Income tax (expense) benefit		36,273			22,534			(49,973	)		631			(16,794	)
Net income (loss)		(322,046	)		(35,581	)		121,705			48,620			6,877
Less income attributable to the redeemable noncontrolling interest (4)		(15,503	)		(13,380	)		—			—			—
Less convertible preferred stock dividends		(11,248	)		(2,856	)		—			—			(46,225	)
Net income (loss) attributable to common shareholders	$	(348,797	)	$	(51,817	)	$	121,705		$	48,620		$	(39,348	)
Net income (loss) per share attributable to common shareholders:
Basic	$	(6.88	)	$	(1.24	)	$	3.43		$	1.58		$	(1.33	)
Diluted	$	(6.88	)	$	(1.24	)	$	3.39		$	1.55		$	(1.33	)
Preferred stock cash dividends per share:	$	8.05		$	2.04		$	—		$	—		$	—
Weighted average number of common shares:
Basic		50,715			41,853			35,457			30,793			29,693
Diluted		50,715			41,853			35,868			31,301			29,693

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	December 31,
	2010			2009			2008		2007		2006
Balance Sheet Data:
Cash and cash equivalents	$	154,695		$	108,961		$	214,993	$	199,449	$	182,592
Working capital (deficit)		(106,139	)		(26,394	)		36,459		96,888		77,504
Oil and gas properties, net		2,904,636			2,485,772			1,872,203		1,830,580		1,095,645
Total assets		3,290,102			2,803,147			2,275,610		2,307,133		1,447,058
Long-term debt, including current maturities		1,879,409			1,216,685			1,366,630		1,404,011		1,071,441
Other long-term obligations		472,500			274,942			2,582		—		—
Capital lease, including current maturities		—			—			—		—		23,699
Total liabilities		2,897,265			2,067,618			1,959,261		1,997,267		1,411,140
Temporary equity (3)		140,851			139,598			—		—		—
Shareholders’ equity		251,986			595,931			316,349		309,866		35,918

(1) Other revenues are comprised of amounts realized under our loss of production income insurance policy as a result of disruptions caused by the 2008 and 2005 hurricanes.

(2) Drilling interruption costs reflect the costs we have incurred as a result of the deepwater drilling moratoriums and subsequent drilling permit delays caused by the April 2010 Macondo incident in the Gulf of Mexico.

(3) Gain on disposition of properties consists of a Gulf of Mexico property exchange in 2010, sales of the deep rights on Gulf of Mexico properties in 2010 and 2009, and our sale of 80% of our working interest in Tors and Wenlock in the U.K. North Sea in 2008.

(4) Represents the 49% redeemable noncontrolling interest in our consolidated limited partnership that holds theATP Innovator floating production facility.

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

Executive Overview

Review of 2010

During 2010, we incurred $694.4 million in capital expenditures. With these expenditures we accomplished the following:

• In March 2010, theATP Titan, our new deepwater production facility that sailed out of dry dock in late 2009, was installed at the Telemark Hub;

• Completed and achieved initial production from two wells at the Telemark Hub and one well at Tors in the North Sea;

• Expanded our presence in the Gulf of Mexico deepwater by acquiring Ship Shoal (“SS”) Block 361 and the Garden Banks Block 782 (“Entrada”);

• Increased total production by 30% to 7.7 MMBoe.

The Telemark Hub was placed on production during March 2010 with the first well at AT 63. In October 2010, production began from the Mississippi (“MC”) 941 #3 well, our second Telemark Hub development well. The third and fourth wells at our Telemark Hub, originally scheduled to be completed during the fourth quarter of 2010, were delayed by the DOI drilling moratoriums and will be completed after additional permits for these wells are issued. These two development wells are drilled to approximately 12,000 feet and require additional drilling to reach the target depth of approximately 20,000 feet. Our proved reserves in the deepwater Gulf of Mexico account for 62% of our total proved reserves as of December 31, 2010. Our proved reserves on the Gulf of Mexico Outer Continental Shelf account for 4% of our total proved reserves with the remaining 34% in the North Sea.

On April 20, 2010, a semi-submersible drilling rig operating in the deepwater Outer Continental Shelf (“OCS”) in the Gulf of Mexico exploded, burned for two days and sank, resulting in an oil spill in Gulf of Mexico waters. In response to this crisis, the DOI, on May 6, 2010, instructed the MMS to stop issuing drilling permits for OCS wells and to suspend existing OCS drilling permits issued after April 20, 2010, until May 28, 2010, when a report on the accident was expected to be completed. On May 28, 2010, DOI issued a moratorium (“Moratorium I”), originally scheduled to last for six months, that essentially halted all drilling in water depths greater than 500 feet in the Gulf of Mexico. On June 7, 2010, a lawsuit was filed by several suppliers of services to Gulf of Mexico exploration and production companies challenging the legality of Moratorium I. This challenge was successful and on June 22, 2010, a Federal District Court issued a preliminary injunction preventing Moratorium I from taking effect. On July 8, 2010, the United States Court of Appeals for the Fifth Circuit denied the DOI’s motion to stay the preliminary injunction against the enforcement of Moratorium I. On July 12, 2010, in response to the Court’s actions, the DOI issued a second moratorium (“Moratorium II”) originally scheduled to end on November 30, 2010 that (i) specifically superseded Moratorium I, (ii) suspended all existing operations in the Gulf of Mexico and other regions of the OCS utilizing a subsea blowout preventer (“BOP”) or a surface BOP on a floating facility, and (iii) suspended pending and future permits to drill wells involving the use of a subsurface BOP or a surface BOP on a floating facility. Several lawsuits challenging the legality of Moratorium II and, among other things, the BOEM handling of drilling permits and development plans were subsequently filed in different Federal District Courts, all of which have been consolidated into one case in a Federal District Court that is still pending. On October 12, 2010 the DOI lifted Moratorium II as to all deepwater drilling activity.

The lifting of Moratorium II, however, did not remove all restrictions on offshore drilling. According to DOI’s order lifting Moratorium II, prior to receiving new permits to drill wells, OCS lessees and operators must first comply with an earlier notice to lessees and operators issued by the BOEM, successor to the MMS, that requires additional testing, third-party verification, training for rig personnel, and governmental approvals to enhance well bore integrity and the operation of BOPs and other well control equipment used in OCS wells, (“NTL 2010-No.5”). NTL 2010-No.5 was set aside by the Federal District Court on October 19, 2010, as having been improperly issued by BOEM. The DOI’s order lifting Moratorium II, however, also requires OCS lessees and operators to comply with BOEM’s Interim Final Rule entitled “Increased Safety Measures for

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Energy Development on the Outer Continental Shelf (the “Safety Interim Final Rule”) issued in September 2010, before recommencing deepwater operations. In general, the Safety Interim Final Rule incorporates the terms of NTL 2010-No.5 and establishes new safety requirements relating to the design of wells and testing of the integrity of well bores, the use of drilling fluids, and the functionality and testing of BOPs. Longer term, OCS lessees and operators will be required to comply with the BOEM’s new Final Workplace Safety Rule, also issued by BOEM in September 2010. The Final Workplace Safety Rule requires all OCS operators to implement all of the formerly voluntary practices in the American Petroleum Institute’s Recommended Practice 75, which includes the development and maintenance of a Safety and Environmental Management System, within one year after the date of the rule. In addition to these two rules, before a permit will be issued, each operator must demonstrate that it has enforceable obligations that ensure that containment resources are available promptly in the event of a deepwater blowout. Although Moratorium II has been lifted, we cannot predict with certainty when permits will be granted under the new requirements.

While we had no ownership in the Macondo well and no direct costs associated with the Macondo well, we do focus on the deeper water of the Gulf of Mexico and have been and continue to be negatively impacted by the drilling moratoriums and related regulatory uncertainties. See further discussion below under “Risks and Uncertainties.”

We have incurred substantial costs caused by the deepwater drilling moratoriums and subsequent drilling permit delays. For example, during 2010 a side-track well operation in 7,000 feet of water was interrupted when Moratorium I was imposed and work on that project stopped, resulting in the early termination of a drilling contract. In the course of obtaining a full release from our obligations under the contract, we incurred net costs of $8.7 million, which are reflected as drilling interruption costs on our Consolidated Statements of Operations. Because the necessary drilling permits were not issued, drilling interruption costs also include $14.9 million of stand-by costs for a drilling rig and support operations at our Gomez Hub and Telemark Hub properties.

Our revenues from oil and natural gas are highly dependent on the underlying commodity prices. During 2010 domestic oil prices hit a high of $91 per Bbl in December and a low of $66 per Bbl. Natural gas followed a similar trend, falling from a high of $7.51 per MMBtu in January to a low of $3.18 per MMBtu in October. During 2010 our realized oil price per barrel increased 27% to $72.94 compared to 2009, and natural gas prices increased 10% to $4.83 per Mcf in the same period. Coupled with the overall 30% increase in production in 2010, our oil and gas revenues rose 47% in 2010.

In spite of that, our cash flows from operations were significantly negatively impacted by the drilling moratoriums, as we incurred the additional costs noted above and at the same time were unable to place on production three wells during 2010 that were originally part of the 2010 development program. We funded our 2010 activities through a combination of new debt financings, the sale or conveyance of economic interests in selected properties and financing arrangements with our suppliers. During 2010, we raised $373.8 million in net proceeds from a debt refinancing, $228.8 million in net proceeds from theTitanassets – Term Loan Facility –and $228.4 million net proceeds from sales of limited-term overriding royalty interests and net profit interests.

During this period we financed significant portions of our development program with transactions entered into with our suppliers and their affiliates. We have conveyed to certain suppliers net profits interests in our Telemark Hub, Gomez Hub and Clipper oil and gas properties in exchange for development services. We have also negotiated with certain other vendors involved in the development of the Telemark Hub and Clipper to partially defer payments for a period of twelve months. Development of the Cheviot Hub in the U.K. North Sea continues. We have arranged with the fabricator of the floating production facility to defer $121.5 million of payments until 2011 ($54.5 million) and the remainder until 2012. These types of financial arrangements preserve our current cash and allow us to pay from the proceeds of future production. (See Note 7 to our Consolidated Financial Statements for further details.)

During May and June 2010, the MMS, which is now known as BOEM, awarded us leases for 100% of the working interests in Entrada and the SS Block 361, respectively. SS Block 361 is in close proximity to our SS Block 358 Hub. Entrada is in the vicinity of existing infrastructure owned by others. We paid $0.4 million for these leases.

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During January 2010, we consummated a nonmonetary exchange of our 10% nonoperated working interest in MC Block 800, for an incremental 50% working interest in MC Block 754, both proved undeveloped properties at the time. Our consolidated financial statements reflect the incremental interest acquired in MC Block 754 at fair value and removal of the carrying costs of MC Block 800, resulting in recognition of a $12.0 million gain. MC Block 754 began production in February 2011.

Also during January 2010, we acquired a 100% working interest in MC Block 710, an exploratory prospect adjacent to our Gomez Hub in MC Block 711 and surrounding blocks, in exchange for the conveyance of an overriding royalty interest in this block.

During July 2010, we sold to a third party our 67% working interest in the deep operating rights of one of our Gulf of Mexico properties resulting in a $15.0 million gain.

2011 Operational Objectives

All of our 2011 development plans in the Gulf of Mexico are dependent upon receiving deepwater drilling and other permits from the BOEM. While we believe it is likely that we will receive permits in 2011 allowing us to execute our drilling plans, there is no assurance that the permits will be received in time to impact our 2011 results of operations. Our goals for 2011 include drilling and completing two additional development wells at our Telemark Hub and, later in 2011, two additional wells at our Gomez Hub. In late February 2011, we began production from MC Block 754, which produces into the Gomez Hub. Additional opportunities may be pursued at our Clipper project in the Gulf of Mexico. Also, if approved by the Israel Ministry of National Infrastructures, we will begin the process of expanding our deepwater operating and infrastructure expertise to offshore Israel.

Risks and Uncertainties

Our 2011 development plans in the Gulf of Mexico, as well as our longer term business plan, are dependent on receiving approval for deepwater drilling and other permits submitted to the BOEM. While we believe we can satisfy the permitting requirements for our planned 2011 development wells which will allow us to significantly increase our production from current levels, there is no assurance that they will be received in time to benefit our 2011 results or that permits will be issued in the future. Should the permitting process in the Gulf of Mexico continue to be delayed, we believe we can continue to meet our existing obligations for at least the next twelve months; however, absent alternative funding sources, our ability to do so is dependent on maintaining existing production levels from our currently producing wells and maintaining commodity prices and operating costs near current levels. The size of our operations and our capital expenditures budget limit the number of properties that we can develop in any given year and a substantial portion of our current production is concentrated among relatively few wells located offshore in the Gulf of Mexico and in the North Sea, which are characterized by rapid production declines. As a result, we are particularly vulnerable to a near term severe impact resulting from unanticipated complications in the development of, or production from, any single material well or infrastructure installation, including lack of sufficient capital, delays in receiving necessary drilling and operating permits, increased regulation, reduced access to equipment and services, mechanical or operational failures, and bad weather. Any unanticipated significant disruption to, or decline in, our current production levels or negative changes in current commodity prices or operating cost levels could have a material adverse effect on our financial position, results of operations and cash flows and our ability to meet our commitments as they come due. We have historically obtained various other sources of funding to supplement our cash flow from operations and we will continue to pursue them in the future, however, there is no assurance that these alternative sources will be available should these risks and uncertainties materialize.

We have incurred substantial costs in 2010 caused by the deepwater drilling moratoriums and subsequent drilling permit delays and some of these costs are continuing into 2011 and are expected to continue until permits are issued. In addition, we cannot predict how federal and state authorities will further respond to the Macondo incident in the Gulf of Mexico or whether additional changes in laws and regulations governing oil and gas operations in the Gulf of Mexico will result. New regulations already issued will, and potential future regulations or additional statutory limitations, if enacted or issued, could, require a change in the way we conduct our business, increase our costs of doing business or ultimately prohibit us from drilling for or

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producing hydrocarbons in the Gulf of Mexico. We cannot predict if or how the governments of other countries in which we operate will respond to the accident in the Gulf of Mexico.

We have financed a significant portion of our development program with transactions entered into with our suppliers and financial institutions that either defer payments to future years or will be repaid based on production throughput or from the revenues or net profits generated from future production. While these financing transactions have enabled us to continue the development of our properties and preserve cash, they will significantly burden the future net cash flows from our production until these obligations are satisfied (See Note 7 to our consolidated financial statements for further details).

As an independent oil and gas producer, our revenue, profitability, cash flows, and future rate of growth are substantially dependent on prevailing prices for oil and natural gas. Historically, the energy markets have been very volatile, and we expect such price volatility to continue. Any extended decline in oil or gas prices could have a material adverse effect on our financial position, results of operations, cash flows, the quantities of oil and gas reserves that we can economically produce, and may restrict our ability to obtain additional financing or to meet the contractual requirements of our debt and other obligations.

In addition, our estimates of proved oil and natural gas reserves and the estimated future net revenues from such reserves are based upon various assumptions, including assumptions relating to oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The estimation process requires significant 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. Estimates of our oil and natural gas reserves and the costs and timing associated with developing these reserves are subject to change, and may differ materially from the quantities of oil and natural gas that we ultimately produce. As of December 31, 2010, approximately 81% of our total proved reserves were undeveloped. We intend to continue to develop these reserves through the end of the year and beyond, but there can be no assurance we will be successful, particularly if permitting delays continue to negatively impact our liquidity and limit the amount of capital available for us to invest in our development plan. Development of these reserves may not yield the expected results, or the development may be delayed or the costs may exceed our estimates, any of which may materially affect our financial position, results of operations, cash flows and our ability to meet the requirements of our financing obligations.

Results of Operations

For the years ended December 31, 2010, 2009 and 2008 we reported net income (loss) attributable to common shareholders of ($348.8) million, ($51.8) million and $121.7 million, or ($6.88), ($1.24) and $3.39 per diluted share, respectively.

Oil and Gas Production Revenues

Revenues presented in the table and the discussion below represent revenues from sales of oil and natural gas production volumes. Production sold in prior years under fixed-price delivery contracts designated for the normal sale exception under the accounting standards for derivatives and hedging are also included in prior year amounts. At December 31, 2008, we began accounting for our open fixed-price physical forward contracts as derivatives because we could no longer assert that our remaining contracts would result in physical delivery. Consequently, changes in their fair value during the period are reflected as derivative income/expense instead of oil and gas revenues in our consolidated statement of operations. The 2008 realized prices below may differ from the market prices in effect depending on when the fixed-price delivery contract was executed.

During the second quarter of 2008, we completed the sale of 0.96 MMBoe of proved Gulf of Mexico (“GOM”) reserves in the form of a 15% limited-term overriding royalty interest for $82.0 million. In accordance with the accounting standards for extractive activities – oil and gas, the transaction was accounted for as a volumetric production payment. The net proceeds received were recorded as deferred revenue to be recognized in earnings as the production is delivered and are presented on the 2008 consolidated statements of cash flows as proceeds from disposition of oil and gas properties. The table below includes oil and gas production revenues from amortization of deferred revenue related to this transaction. Because the volumetric production payment represents a conveyance, the reserves were treated as sold in 2008 and we do not reflect any production volumes associated with those revenues.

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								% Change from 2009 to 2010			% Change from 2008 to 2009
	Year Ended December 31,
	2010		2009		2008
Production:
Oil and condensate (MBbls)		4,471		3,353		4,267			33	%		(21	%)
Natural gas (MMcf)		19,151		15,119		31,862			27	%		(53	%)
Total (MBoe)		7,663		5,873		9,578			30	%		(39	%)
Gulf of Mexico (MBoe)		7,114		5,342		7,026			33	%		(24	%)
North Sea (MBoe)		549		531		2,552			3	%		(79	%)
Revenues from production (in thousands):
Oil and condensate	$	326,110	$	192,044	$	308,910			70	%		(38	%)
Effects of cash flow hedges		—		—		(2,390	)
Amortization of deferred revenue		17,819		32,649		18,976
Total	$	343,929	$	224,693	$	325,496			53	%		(31	%)
Natural gas	$	92,551	$	64,834	$	264,204			43	%		(75	%)
Effects of cash flow hedges		—		1,719		(8,672	)
Amortization of deferred revenue		1,517		7,244		3,795
Total	$	94,068	$	73,797	$	259,327			27	%		(72	%)
Oil, condensate and natural gas	$	418,661	$	256,878	$	573,114			63	%		(55	%)
Effects of cash flow hedges		—		1,719		(11,062	)
Amortization of deferred revenue		19,336		39,893		22,771
Total	$	437,997	$	298,490	$	584,823			47	%		(49	%)
Average realized sales price:
Oil and condensate (per Bbl)	$	72.94	$	57.28	$	72.41			27	%		(21	%)
Effects of cash flow hedges (per Bbl)		—		—		(0.56	)
Total (per Bbl)	$	72.94	$	57.28	$	71.85			27	%		(21	%)
Gulf of Mexico (per Bbl)		72.92		57.34		71.67			27	%		(20	%)
North Sea (per Bbl)		87.00		34.67		95.53			151	%		(64	%)
Natural gas (per Mcf)	$	4.83	$	4.29	$	8.29			13	%		(48	%)
Effects of cash flow hedges (per Mcf)		—		0.11		(0.27	)
Total (per Mcf)	$	4.83	$	4.40	$	8.02			10	%		(45	%)
Gulf of Mexico (per Mcf)		4.53		4.16		9.68			9	%		(57	%)
North Sea (per Mcf)		6.32		5.34		6.18			18	%		(14	%)
Oil, condensate and natural gas (per Boe)	$	54.66	$	43.73	$	59.82			25	%		(27	%)
Effects of cash flow hedges (per Boe)		—		0.30		(1.14	)
Total (per Boe)	$	54.66	$	44.03	$	58.68			24	%		(25	%)
Gulf of Mexico (per Boe)		55.88		45.22		66.24			24	%		(32	%)
North Sea (per Boe)		38.54		32.07		37.86			20	%		(15	%)

Revenues from production increased in 2010 compared to 2009 due to a 30% increase in production and a 24% increase in average realized sales price. The production increase occurred primarily in the Gulf of Mexico where we now have production from two wells at our Telemark Hub, where we had a workover operation and reversion of an overriding revenue interest at our Gomez Hub and where our Canyon Express property has been returned to production. The higher average realized sales price is due to increased commodity market prices.

Revenues from production decreased in 2009 compared to 2008 due to a 39% decrease in overall production and a 25% decrease in average realized sales prices. The lower production in the Gulf of Mexico was primarily the result of the September 2008 sale of a 15% limited-term overriding royalty interest in production, the continuing effects in 2009 of the 2008 hurricanes and natural production declines and shut-ins for recompletions at the Gomez Hub. The lower production in the North Sea is primarily due to the sale of 80% of our working interest in Tors and Wenlock in the fourth quarter of 2008 and due to voluntary production curtailment as a result of low natural gas prices. The lower average realized sales price is due to decreased commodity market prices.

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Other Revenues

Other revenues for 2009 and 2008 are comprised of amounts realized under our loss of production income insurance policy due to disruptions caused by Hurricane Ike.

Lease Operating

Lease operating expenses include costs incurred to operate and maintain wells. These costs include, among others, workover expenses, operator fees, processing fees and insurance. Lease operating expense was as follows (in thousands, except per Boe amounts):

							% Change from 2009 to 2010			% Change from 2008 to 2009
	Year Ended December 31,
	2010		2009		2008
Recurring operating expenses	$	88,437	$	66,440	$	86,060		33	%		(23	%)
Workover expenses		44,106		18,517		5,136		138	%		261	%
Lease operating		132,544		84,956		91,196		56	%		(7	%)
Recurring operating expenses per Boe		11.54		11.31		8.99		2	%		26	%
Gulf of Mexico		11.57		11.31		8.85		2	%		28	%
North Sea		11.19		11.34		9.36		(1	%)		21	%

Lease operating expense for 2010 increased $47.6 million compared to 2009. The increase in recurring operating expense was primarily due to the new production from the Telemark and Canyon Express Hubs. The workover expenses during 2010 were primarily due to inspection activities on many of our Gulf of Mexico properties and hydrate remediation activities on our Canyon Express and Telemark Hubs, which enabled us to commence production at our new well at Kings Peak (MC Block 217) and to re-establish production from two wells at Aconcagua (MC Block 305). The workover expenses for 2009 included Hurricane Ike repairs and non-routine surveys for properties in the North Sea.

Lease operating expense for 2009 decreased compared to 2008 primarily due to the sale of 80% of our working interest in Tors and Wenlock in the fourth quarter 2008 and due to reduced fuel and chemical costs in the Gulf of Mexico. These cost decreases were partially offset by increases related to insurance premiums and non-recurring workover activities at various Gulf of Mexico and North Sea properties. The per unit cost increased primarily due to the effect of fixed costs on lower production volumes.

General and Administrative

General and administrative expenses are overhead-related expenses, including employee compensation, legal and accounting fees, insurance, and investor relations expenses. General and administrative expense was as follows:

							% Change from 2009 to 2010			% Change from 2008 to 2009
	Year Ended December 31,
	2010		2009		2008
General and administrative (in thousands)	$	44,894	$	44,211	$	41,653		2	%		6	%
Per Boe		5.86		7.53		4.32		(22	%)		74	%

The general and administrative expense increased in 2009 compared to 2008 due primarily to the payment of third party fees of $6.2 million related to our debt modification in the fourth quarter of 2009.

Depreciation, Depletion and Amortization

Depreciation, depletion and amortization (“DD&A”) expense was as follows:

							% Change from 2009 to 2010			% Change from 2008 to 2009
	Year Ended December 31,
	2010		2009		2008
DD&A (in thousands)	$	220,657	$	152,780	$	246,434		44	%		(38	%)
Per Boe		28.80		26.01		25.74		11	%		1	%
Gulf of Mexico		28.18		24.11		21.66		17	%		11	%
North Sea		36.79		45.20		36.90		(19	%)		22	%

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DD&A expense for 2010 increased $67.9 million compared to 2009 primarily due to the commencement of production at Telemark Hub. The per unit increase in the Gulf of Mexico is primarily a result of higher costs incurred on our new developments relative to some of our older properties and the recognition of straight-line depreciation on ourATP Titan production platform. The per unit costs for the North Sea decreased primarily due to the effect of production mix differences.

DD&A expense for 2009 decreased compared to 2008 primarily due to decreased production discussed above. The per unit increase is primarily a result of higher costs incurred on our new developments relative to some of our older properties. The increased rate was partially offset by expense decreases related to the change from unit-of-production depletion to straight-line depreciation for theATP Innovator upon contribution to ATP-IP.

Impairment of Oil and Gas Properties

We recorded impairments during the years ended December 31, 2010, 2009 and 2008 totaling $42.4 million, $44.6 million and $124.7 million, respectively, on certain proved properties in the Gulf of Mexico. We also recorded impairments totaling $14.9 million during 2010, on certain proved properties in the North Sea.

Impairments of unproved properties were $6.0 million, $1.2 million and $0.4 million in 2010, 2009 and 2008, respectively, primarily related to surrendered leases in the Gulf of Mexico.

Accretion of Asset Retirement Obligation

Accretion expense in 2010 increased to $13.8 million compared to $11.7 million in 2009 primarily due to the addition of the future retirement obligations associated with our Telemark Hub. Accretion expense in 2009 decreased to $11.7 million compared to $15.6 million in 2008 primarily due to the North Sea property sale noted above and changes in estimates of future abandonment obligations in 2008.

Drilling Interruption Costs

Drilling interruption costs represent the costs we have incurred as a result of the deepwater drilling moratoriums and subsequent drilling permit delays caused by the April 2010 Macondo incident in the Gulf of Mexico. During 2010, a side-track well operation in 7,000 feet of water was interrupted when the moratorium was imposed and work on that project stopped, resulting in the early termination of a drilling contract. In the course of obtaining a full release from our obligations under the contract, we incurred net costs of $8.7 million. Additionally, because the necessary deepwater drilling permits were not issued, drilling interruption costs also include $14.9 million of stand-by costs related to drilling operations at our Telemark and Gomez Hubs.

Loss on Abandonment

We recognized aggregate loss on abandonment during 2010, 2009 and 2008 of $4.8 million, $2.9 million and $13.3 million, respectively. These amounts are the result of actual abandonment costs exceeding the previously accrued estimates, due to unforeseen circumstances that required additional work or the use of equipment more expensive than anticipated and unanticipated vendor price increases.

Gain on Exchange/Disposal of Properties

In 2010, we sold to a third party our 67% working interest in the deep operating rights of one of our Gulf of Mexico properties resulting in a $15.0 million gain. In 2010, we also consummated a nonmonetary exchange of our 10% nonoperated working interest in MC Block 800, for an incremental 50% working interest in MC Block 754, both proved undeveloped properties. The consolidated financial statements reflect the incremental interest acquired in MC Block 754 at fair value and removal of the carrying costs of MC Block 800, resulting in recognition of a $12.0 million gain.

In December 2009, we sold to a third party our 25% working interest in the deep operating rights of one of our Gulf of Mexico properties for $13.0 million in cash, all of which was recognized as a gain.

During October 2008, we finalized a sale of 80% of our working interests in certain producing natural gas properties, leasehold acreage and gathering infrastructures, all located in the U.K. North Sea at the Tors and Wenlock fields. The sale was effective July 1, 2008. The closing of the transaction occurred on December 18, 2008, after which we own a 20% working interest in the Wenlock field and a 17% working interest in the Tors field. The cash received for the transaction was £258.2 million (approximately $389.2 million as of the closing

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date) after deducting £6.8 million ($10.3 million) for transaction costs and fees and adjustment for each party’s share of production proceeds received and expenses paid for periods after July 1, 2008. We recorded a $119.1 million gain on disposition of assets related to this sale.

Interest Income

Interest income varies directly with the amount of temporary cash investments. The decrease in interest income from period to period is the result of a decrease in average cash on hand and a decrease in interest rates.

Interest Expense, net

Interest expense, net of amounts capitalized increased to $222.1 million in 2010 compared to $40.9 million in 2009. In 2010, we capitalized interest of $53.3 million ($40.4 million related to the construction of our Telemark Hub development in the Gulf of Mexico and $12.9 million related to our Cheviot development in the U.K.) compared to 2009 capitalized interest of $110.1 million ($102.2 million related to Telemark Hub and $7.9 million related to Cheviot). Interest expense has increased primarily for three reasons: (i) our Telemark Hub was placed in service and we ceased capitalizing related interest costs as a consequence, (ii) due to higher balances of other long-term obligations, (iii) in the second quarter of 2010, we refinanced our long-term debt and increased our outstanding debt balance and the associated interest rate.

Interest expense decreased to $40.9 million in 2009 compared to $100.7 million in 2008 primarily due to 2009 capitalized interest of $110.1 million ($102.2 million related to the construction of the Telemark Hub development in the Gulf of Mexico and $7.9 million related to Cheviot in the U.K.) compared to capitalized interest of $44.6 million in 2008 ($42.7 million related to the Telemark Hub development and $1.9 million related to Cheviot). Capitalized interest increased due to higher average construction work-in-progress balances in 2009.

Derivative Income (Expense)

Derivative income (expense) is primarily related to net gains and losses associated with our oil and gas price derivative contracts and is as follows (in thousands):

										% Change from 2009 to 2010			% Change from 2008 to 2009
	Year Ended December 31,
	2010			2009			2008
Gulf of Mexico
Realized gains (losses)	$	(1,099	)	$	29,760		$	81,141			(104	%)		(63	%)
Unrealized gains (losses)		(15,154	)		(39,594	)		15,366			(62	%)		(358	%)
		(16,253	)		(9,834	)		96,507			65	%		(110	%)
North Sea
Realized gains (losses)		(1,587	)		7,801			(3,919	)		(120	%)		(299	%)
Unrealized gains (losses)		(4,579	)		1,321			(3,554	)		(447	%)		(137	%)
		(6,166	)		9,122			(7,473	)		(168	%)		(222	%)
Total
Realized gains (losses)		(2,686	)		37,561			77,222			(107	%)		(51	%)
Unrealized gains (losses)		(19,733	)		(38,273	)		11,813			(48	%)		(424	%)
		(22,419	)		(712	)		89,035			3,050	%		(101	%)

Derivatives income in 2008 was $89.0 million (Gulf of Mexico, $96.5 million gain and North Sea, $7.5 million loss). As a result of the limited-term overriding royalty interest and changes in forecasts of production, we determined that it was no longer probable that forecasted production would be sufficient to satisfy amounts designated under certain of our cash flow commodity-price hedges. Consequently, we dedesignated some of these instruments as hedges and recognized expense of $40.5 million. During 2008, we terminated our oil puts, oil swaps and oil fixed-price physical forward sale contracts. We also entered into and subsequently terminated oil price collar derivatives. These terminations resulted in realized derivative income of $83.9 million. Due to

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termination of the oil fixed-price physical forward sale contracts for which we had claimed the normal sales derivative accounting exception provided by the accounting standards for derivatives and hedging, we determined that it was no longer appropriate to claim that exception for our gas fixed forwards. Consequently, we recorded derivative income of $14.4 million. The balance of the derivatives income is primarily related to changes in fair value of derivatives no longer designated as cash flow hedges.

Loss on Debt Extinguishment

Loss on debt extinguishment was $75.3 million in 2010 primarily due to the second quarter refinancing of our previously outstanding term loans in which we charged to expense the remaining unamortized deferred financing costs, debt discount related to the retired debt and repayment premiums.

Loss on debt extinguishment in 2008 is $24.2 million. As discussed below, during the second quarter of 2008, we refinanced the term loans and subordinated notes and recorded as an expense the remaining unamortized deferred financing costs, debt discount related to the retired debt and repayment premiums associated with the subordinated notes.

Income Taxes

During 2010, we recorded a net tax benefit of $36.3 million, determined based on the results of operations for the year for each jurisdiction and permanent differences affecting the overall tax rate in each jurisdiction, resulting in an effective tax rate of 10.1%. As of December 31, 2010, for U.S. tax provision purposes, we have a valuation allowance of $97.4 million, which is comprised of a $94.4 million valuation allowance against the net deferred income tax asset position and a $3.0 million valuation allowance related to excess tax benefits from stock options and restricted stock prior to adoption of accounting standards related to stock-based compensation. In addition, as of December 31, 2010 for Netherlands’ income tax provision purposes, we have a valuation allowance of $1.7 million related to the net operating loss carryovers generated in 2010 and in prior periods.

During 2009, we recorded a net tax benefit of $22.5 million, determined based on the results of operations for the year for each jurisdiction and permanent differences affecting the overall tax rate in each jurisdiction, resulting in an effective tax rate of 38.8%. As of December 31, 2009, for U.S. tax provision purposes, we have a valuation allowance of $3.0 million related to excess tax benefits from stock options and restricted stock prior to adoption of accounting standards related to stock-based compensation. In addition, as of December 31, 2009 for Netherlands’ income tax provision purposes, we have a valuation allowance of $1.3 million related to the net operating loss carryover generated in 2009.

During 2008, we recorded net tax expense of $50.0 million, determined based on the results of operations for the year for each jurisdiction and permanent differences affecting the overall tax rate in each jurisdiction, resulting in an effective tax rate of 29.1%. As of December 31, 2008, for U.S. tax provision purposes all of our valuation allowance was released except the portion related to our excess tax benefits from stock options and restricted stock prior to adoption of accounting standards related to stock-based compensation.

Income Attributable to the Redeemable Noncontrolling Interest

Income attributable to the redeemable noncontrolling interest represents the 49% Class A limited partner interest in the earnings of ATP-IP. The amount of $15.5 million in 2010 is higher than the amount of $13.4 million in 2009 primarily because of the inception of this arrangement in the middle of the first quarter of 2009.

Convertible Preferred Stock Dividends

Convertible preferred stock dividends in 2010 represent declared cash dividends for the year ended December 31, 2010. Convertible preferred stock dividends in 2009 represent cash dividends due for the period from the September 2009 issue date of the preferred stock through December 31, 2009. The outstanding shares of convertible preferred stock accrue cumulative preferred dividends at the annual rate of 8% of the $140.0 million aggregate liquidation value and are payable in either cash or stock at the Company’s option.

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Liquidity and Capital Resources

Overview

Historically, we have funded our acquisition and development activities through a combination of bank borrowings, proceeds from equity offerings, cash from operations, the sale or conveyance of interests in selected properties and vendor financings. Our ongoing cash requirements consist primarily of servicing our debt and other obligations and funding development of our oil and gas reserves. Cash paid for capital expenditures for oil and gas properties was approximately $598.1 million, $635.4 million and $917.7 million for the years ended December 31, 2010, 2009 and 2008, respectively. In 2010, we refinanced our long-term debt and obtained additional financing from other transactions, all of which are discussed below.

Our 2011 development plans in the Gulf of Mexico, as well as our longer term business plan, are dependent on receiving approval for deepwater drilling and other permits submitted to the BOEM. While we believe we can satisfy the permitting requirements for our planned 2011 development wells which will allow us to significantly increase our production from current levels, there is no assurance that they will be received in time to benefit our 2011 results or that permits will be issued in the future. Should the permitting process in the Gulf of Mexico continue to be delayed, we believe we can continue to meet our existing obligations for at least the next twelve months; however, absent alternative funding sources, our ability to do so is dependent on maintaining existing production levels from our currently producing wells and maintaining commodity prices and operating costs near current levels. The size of our operations and our capital expenditures budget limit the number of properties that we can develop in any given year and a substantial portion of our current production is concentrated among relatively few wells located offshore in the Gulf of Mexico and in the North Sea, which are characterized by rapid production declines. As a result, we are particularly vulnerable to a near term severe impact resulting from unanticipated complications in the development of, or production from, any single material well or infrastructure installation, including lack of sufficient capital, delays in receiving necessary drilling and operating permits, increased regulation, reduced access to equipment and services, mechanical or operational failures, and bad weather. Any unanticipated significant disruption to, or decline in, our current production levels or negative changes in current commodity prices or operating cost levels could have a material adverse effect on our financial position, results of operations and cash flows and our ability to meet our commitments as they come due. We have historically obtained various other sources of funding to supplement our cash flow from operations and we will continue to pursue them in the future, however, there is no assurance that these alternative sources will be available should these risks and uncertainties materialize. We recently amended our first lien credit facility to provide for an increase to the principal amount from the current $150 million to the lesser of $210 million or 10% of the Company’s Adjusted Consolidated Net Tangible Assets, which we expect will provide an additional $60 million, before transaction costs, of available liquidity.

Our longer term liquidity is also dependent on our ability to bring the next two wells at Telemark on production in the near term and continuing to operate in the Gulf of Mexico, which we expect will generate sufficient cash flows to fund subsequent development projects and service our long-term debt and other obligations. Our longer term liquidity is also dependent on the prevailing prices for oil and natural gas which has historically been very volatile. To mitigate future price volatility, we may continue to hedge the sales price of a portion of our future production.

We have conveyed to certain vendors and financial parties dollar-denominated net profits interests and overriding royalty interests in our Telemark Hub, Gomez Hub and Clipper oil and gas properties in exchange for development services, equipment and cash. We have also negotiated with certain other vendors involved in the development of the Telemark Hub to partially defer payments until after the beginning of production. These net profits interests and deferrals allow us to match our development cost cash flows with those from production. (See Other Long-term Obligations below.)

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2010 Activities

During January 2010, we sold overriding royalty interests, which are primarily dollar denominated, in future production from our Gomez Hub producing properties for cash proceeds of $121.1 million, net of costs. The dollar-denominated overriding royalty interests obligate us to deliver proceeds from the future sale of hydrocarbons from the specified properties equal to the purchasers’ original investment, plus an overall rate of return. The percentage of property revenues available to satisfy these obligations is dependent upon certain conditions specified in the agreement. Upon payment of the agreed dollar amounts, the ownership interests revert to us. Because these interests were conveyed in proved properties where repayment is deemed to be reasonably assured, they are reflected as financing obligations on our consolidated balance sheet and the associated reserves and production are retained by the Company.

In April 2010, we entered into a first lien revolving credit facility (the “Original Credit Facility”) with an initial borrowing base of $100.0 million, due April 23, 2013, and issued senior second lien notes (the “Notes”) in an aggregate principal amount of $1.5 billion, due May 1, 2015. We used proceeds from the Notes to repay the entire amount due under our term loans previously outstanding.

In June 2010, we entered into a new first lien credit agreement (the “New Credit Facility”) for $150.0 million, due October 15, 2014, to replace the Original Credit Facility. Proceeds of the New Credit Facility were $144.3 million, net of original issue discount and transaction fees. The New Credit Facility allows the Company to incur up to $350.0 million of additional indebtedness as our Adjusted Consolidated Net Tangible Assets (as defined in the New Credit Facility) increase. On February 19, 2011, we entered into Incremental Loan Assumption Agreement and Amendment No. 1 to the New Credit Facility (“The Amendment”). The Amendment provides for an increase to the principal amount of the New Credit Facility from $150 million to the lesser of $210 million or 10% of the Company’s Adjusted Consolidated Net Tangible Assets, as defined. The Amendment also reduces the interest rate of the New Credit Facility from 11% to 9% and extends the maturity date from October 15, 2014 to January 15, 2015.

In September 2010, we formed ATP Titan, LLC (“Titan LLC”), a wholly owned and operated subsidiary, and transferred to it our 100% ownership of theATP Titan platform and related infrastructure assets. Simultaneous with the transfer, we entered into a $350.0 million term loan facility (the “ATP TitanFacility”), of which $150.0 million was drawn initially. At closing, we received proceeds of $140.8 million net of discount and direct issuance costs. There are provisions in theATP Titan Facility under which the undrawn balance may be funded upon our request and subject to lender approval based on first production from wells at Telemark Hub as follows: $100.0 million from the second well and $50.0 million each from the third and fourth wells. The second well, MC Block 941 #3, began production during October 2010, and we received the second tranche of $100.0 million ($92.5 million, net of discount and transaction costs).

Also, in 2010, we granted dollar-denominated overriding royalty interests in the form of net profits interests (“NPI”) in certain of our oil and gas properties in and around the Telemark Hub and Gomez Hub to certain of our vendors in exchange for oil and gas property development services and cash. The interests earned by the vendors are paid solely from the net profits, as defined, of the subject properties. As the net profits increase or decrease, primarily through higher or lower production levels and higher or lower prices of oil and natural gas, the payments due the holders of the net profits interests increase or decrease accordingly. If there is no production from a property or if the net profits are negative during a payment period, there is no payment required. Because these interests were conveyed in proved properties where repayment is deemed to be reasonably assured, they are reflected as financing obligations on our consolidated balance sheet and the associated reserves and production are retained by the Company.

During November 2010, a dollar-denominated overriding royalty interest in the form of net profits interest that we originally granted during 2009 in exchange for vendor services was acquired by an investor, who repaid the vendor in full, extended the payout term of the NPI, and increased the size of the obligation to $100.0 million. The proceeds of the transaction were $60.3 million, net of transaction costs, and we recognized a gain on debt extinguishment of $2.9 million.

In the Gulf of Mexico, in addition to the net profits interests exchanged for development services and cash described above, we have negotiated with certain other vendors involved in the development of the Telemark and Gomez Hubs to partially defer payments. In the U.K. North Sea, development of our interest in the

46

Cheviot field continues. We have arranged with the fabricator of the floating production facility to defer $121.5 million of committed expenditures: $54.5 million to be paid in 2011 and $67.0 million to be paid in 2012.

2011 Activities

In 2011, we anticipate incurring $400 million to $500 million in total capital expenditures of which $250 million to $325 million will be cash with the balance contributed by suppliers through existing NPI programs or deferral programs. Because of the uncertainty associated with the regulatory environment, our capital expenditures could increase or decrease from these levels. As operator of most of our projects under development, we have the ability to control the timing and extent of most of our capital expenditures should future market conditions warrant. During 2011, we plan to finance anticipated expenses, debt service, development and abandonment requirements with cash on hand, funds generated by operating activities the committed property conveyance transactions described above, and, potentially, proceeds from capital market transactions , other financings and the sales of assets.

Cash Flows

	Year Ended December 31,
	2010			2009			2008
Cash provided by (used in) (in thousands):
Operating activities	$	(37,280	)	$	159,827		$	546,967
Investing activities		(610,821	)		(632,951	)		(432,010	)
Financing activities		694,024			358,673			(69,327	)

As of December 31, 2010, we had a working capital deficit of approximately $106.1 million, a decrease of approximately $79.7 million from December 31, 2009.

Cash provided by (used in) operating activities during 2010 and 2009 was ($37.3) million and $159.8 million, respectively. Cash flow from operating activities has decreased primarily due to increased net interest costs, debt extinguishment costs and drilling interruption costs, partially offset by increased oil and gas revenues.

Cash provided by operating activities during 2009 and 2008 was $159.8 million and $547.0 million, respectively, primarily due to lower net income and from changes in working capital in 2009 compared to 2008. Net income in 2009 decreased primarily due to lower production and lower commodity prices discussed above.

Cash used in investing activities was $610.8 million and $633.0 million during 2010 and 2009, respectively. During 2010, cash expended in the Gulf of Mexico and North Sea for additions to oil and gas properties was approximately $534.3 million and $63.8 million, respectively. During 2009, cash expended in the Gulf of Mexico and North Sea for additions to oil and gas properties was approximately $551.4 million and $83.9 million, respectively. During 2008, cash expended in the Gulf of Mexico and North Sea for additions to oil and gas properties was approximately $751.0 million and $166.7 million, respectively. Also in 2008, cash received from investing activities includes proceeds, net of costs, from the sale of interests in North Sea properties for $389.2 million and the sale of proved reserves in the form of a limited-term overriding royalty interest for $82.0 million.

Cash provided by financing activities was $694.0 million and $358.7 million during 2010 and 2009, respectively. The amount in 2010 is primarily related to $373.8 million net proceeds from the debt refinancing and $228.8 million net proceeds from theTitanAssets – Term loan facility, $228.4 million proceeds net of costs from sales of limited-term overriding royalty interests and net profit interests on proved properties, partially offset by principal payments toward our other long-term obligations and outstanding term loans. The amount in 2009 includes proceeds, net of costs, from the sale of a redeemable noncontrolling interest in ATP-IP of $148.8 million, the issuance of common and preferred stock for $306.2 million, net of costs, the monetization of the Gomez hub pipeline for $74.5 million and $14.5 million from sale of an overriding royalty interest. These increases in cash flows were partially offset by $157.5 million of net debt repayments and $19.0 million of distributions to the Class A limited partner in ATP-IP. The amount in 2008 includes proceeds from and payments of term loans previously outstanding from the refinancing of $1,202.2 million of borrowings under our former credit agreement and of $199.5 million of subordinated notes. Further, we repaid $273.3 million of those term loans with a portion of the net proceeds from the North Sea property sale described

47

above. Proceeds from those term loans were comprised of $1,593.3 million (net of issuance costs) of proceeds from the term loans and $31.0 million drawn under our former revolving credit facility.

Long-term Debt

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

	December 31,
	2010			2009
First lien term loans, net of $2,644 unamortized discount	$	146,607		$	—
Senior second lien notes, net of $6,071 unamortized discount		1,493,929			—
Term loan facility –ATP Titanassets, net of $10,760 unamortized discount		238,873			—
Term Loans, net of $28,266 unamortized discount		—			1,216,685
Total debt		1,879,409			1,216,685
Less current maturities		(21,625	)		(16,838	)
Total long-term debt	$	1,857,784		$	1,199,847

In April 2010, we entered into a first lien revolving credit facility (the “Original Credit Facility”) with an initial borrowing base of $100.0 million, due April 23, 2013, and issued senior second lien notes (the “Notes”) in an aggregate principal amount of $1.5 billion, due May 1, 2015. We used proceeds from the Notes to repay the entire amount due under our term loans previously outstanding and subsequently replaced the Original Credit Facility with the New Credit Facility, discussed below.

The Notes bear interest at an annual rate of 11.875%, payable each May 1 and November 1, and contain restrictions that, among other things, limit the incurrence of additional indebtedness, mergers and consolidations, and certain restricted payments. The Notes were issued at 99.531% of their face amount to yield 12.0% and we incurred issuance costs of $38.2 million.

At any time (which may be more than once), on or prior to May 1, 2013, the Company may, at its option, redeem up to 35% of the outstanding Notes with money raised in certain equity offerings, at a redemption price of 111.9%, plus accrued interest, if any. In addition, the Company may redeem the Notes, in whole or in part, at any time before May 1, 2013 at a redemption price equal to par plus an applicable make-whole premium plus accrued and unpaid interest to the date of redemption. The Company may also redeem any of the Notes at any time on or after May 1, 2013, in whole or in part, at specified redemption prices, plus accrued and unpaid interest to the date of redemption.

The Notes also contain a provision allowing the holders thereof to require the Company to purchase some or all of those Notes at a purchase price equal to 101% of their aggregate principal amount, plus accrued and unpaid interest to the date of repurchase, upon the occurrence of specified change of control events.

In June 2010, we entered into a new first lien credit agreement (the “New Credit Facility”) with an initial balance of $150.0 million, due October 15, 2014, to replace the Original Credit Facility. Proceeds of the New Credit Facility were $144.3 million, net of original issue discount and transaction fees. Principal outstanding under the term loans issued pursuant to the New Credit Facility bears interest at an annual rate of 11.0%. As security for the Company’s obligations under the New Credit Facility, the Company granted the lenders a security interest in and a first lien on not less than 80% of its proved oil and gas reserves in the Gulf of Mexico, capital stock of material subsidiaries (limited in the case of the Company’s non-U.S. subsidiaries to not more than 65% of the capital stock) and certain infrastructure assets, a portion of which has since been released in connection with the ATP Titan LLC financing discussed below. Principal of $750,000 is due each June and December beginning December 18, 2010 until June 18, 2014. The remaining principal balance is due October 15, 2014. The New Credit Facility allows the Company to incur up to $350.0 million of additional indebtedness secured by our oil and gas properties as Adjusted Consolidated Net Tangible Assets (as defined in the New Credit Facility) increase. See also Note 16, “Subsequent Events” to the Consolidated Financial Statements.

The Notes and New Credit Facility contain certain negative covenants which place limits on the Company’s ability to, among other things:

• incur additional indebtedness;

• pay dividends on the Company’s capital stock or purchase, repurchase, redeem, defease or retire the Company’s capital stock or subordinated indebtedness;

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• make investments outside of our normal course of business;

• incur liens;

• create any consensual restriction on the ability of the Company’s restricted subsidiaries to pay dividends, make loans or transfer property to the Company;

• engage in transactions with affiliates;

• sell assets; and

• consolidate, merge or transfer assets.

In September 2010, we formed ATP Titan LLC (“Titan LLC”), a wholly owned and operated subsidiary which we consolidate in our financial statements, and transferred to it our 100% ownership of theATP Titan platform and related infrastructure assets. Simultaneous with the transfer, Titan LLC entered into a $350.0 million term loan facility (the “ATP TitanFacility”), of which $250.0 million has been drawn for which we received proceeds of $228.8 million, net of discount and direct issuance costs. There are provisions in theATP Titan Facility under which the undrawn balance may be funded upon our request and subject to lender approval based on first production from the third and fourth wells ($50.0 million each) at our Telemark Hub. See also Note 16, “Subsequent Events.” Based on the outstanding balance at December 31, 2010, theATP Titan Facility is to be repaid as follows (in millions): 2011 – $20.1; 2012 – $22.6; 2013 to 2016 – $25.0 per year and 2017 – $106.9. TheATP Titan Facility bears interest at LIBOR (floor of 0.75%) plus 8%. TheATP Titan Facility requires us to maintain in a restricted account a minimum $10.0 million cash balance plus additional amounts based on production at the Telemark Hub to be used for the quarterly debt service of theATP Titan Facility. TheATP TitanFacility is secured solely by theATP Titan and related infrastructure assets (net book value at December 31, 2010 of $1,163.7 million) and the outstanding member interests in Titan LLC, which are all owned indirectly by the Company. TheATP Titan Facility includes a customary condition that there has not occurred a material adverse change with respect to the Company. The Company remains operator and 100% owner of theATP Titan platform, related infrastructure assets and the working interest in its Telemark Hub oil and gas reserves.

The New Credit Facility and the Notes contain customary events of default, and if certain of those events of default were to occur and remain uncured, such as a failure to pay principal or interest when due, our lenders could terminate future lending commitments under the New Credit Facility, and our lenders could declare the outstanding borrowings due and payable. The New Credit Facility also contains an event of default if there has occurred a material adverse change with respect to the Company’s compliance with environmental requirements and applicable laws and regulations. TheATP Titan Facility contains standard events of default and an event of default if there has occurred a material adverse change with respect to the Company. TheATP Titan Facility also contains provisions that provide for cross defaults among the documents entered into in connection with theATP Titan Facility and acceleration of Titan LLC’s payment obligations under theATP Titan Facility in certain situations. In addition, our hedging arrangements contain standard events of default, including cross default provisions, that, upon a default, provide for (i) the delivery of additional collateral, (ii) the termination and acceleration of the hedge, (iii) the suspension of the lenders’ obligations under the hedging arrangement or (iv) the setoff of payment obligations owed between the parties.

The effective annual interest rate of our long-term debt was 12.2% at December 31, 2010. The fair value of the aggregate long-term debt as of December 31, 2010 was approximately $1.8 billion.

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Other Long-term Obligations

Other long-term obligations consisted of the following (in thousands):

	December 31,
	2010			2009
Net profits interests	$	331,776		$	180,818
Dollar-denominated overriding royalty interests		52,825			14,941
Gomez pipeline obligation		73,868			75,152
Vendor deferrals – Gulf of Mexico		7,096			7,490
Vendor deferrals – North Sea		90,874			17,053
Other		2,582			2,582
Total		559,021			298,036
Less current maturities		(86,521	)		(23,094	)
Other long-term obligations	$	472,500		$	274,942

Net Profits Interests

During 2009 and 2010, we granted dollar-denominated overriding royalty interests in the form of net profits interests (“NPIs”) in certain of our proved oil and gas properties in and around the Telemark Hub, Gomez Hub and Clipper to certain of our vendors in exchange for oil and gas property development services. The interests earned by the vendors are paid solely from the net profits, as defined, of the subject properties. As the net profits increase or decrease, primarily through higher or lower production levels and higher or lower prices of oil and natural gas, the payments due the holders of the net profits interests increase or decrease accordingly. If there is no production from a property or if the net profits are negative during a payment period, there is no payment required. We also accrete the liability over the estimated term in which the NPI is expected to be settled using the effective interest method with related interest expense presented net of amounts capitalized on the Consolidated Statement of Operations. The term of the NPIs will be dependent on the value of the services contributed by these vendors coupled with the timing of production and future economic conditions, including commodity prices and operating costs. Because NPIs were granted on proved properties where production is reasonably assured, we have accounted for these NPI’s as financing obligations on our Consolidated Balance Sheet. As such, the reserves and production revenues associated with the NPIs are retained by the Company. We expect approximately 75% of the NPIs to be repaid over the next 24 months based on projected production, commodity prices and operating costs.

During November 2010, a NPI originally granted during 2009 in exchange for vendor services was acquired by an investor, who repaid the vendor $39.2 million outstanding under the original NPI, extended the payout term of the NPI, and increased the size of the obligation to $100.0 million. The proceeds of the transaction were $60.3 million, net of transaction costs, and we recognized a gain on debt extinguishment of $2.9 million.

Dollar-denominated Overriding Royalty Interests

In October 2009, we sold a dollar-denominated overriding royalty interest (“Override”) in our Gomez Hub properties for $14.5 million, net of costs. During 2010, we sold Overrides (primarily dollar-denominated) in future production from the Gomez Hub properties for $140.0 million ($121.1 million net of transaction costs and fourth quarter 2009 royalty payments). These Overrides obligate us to deliver proceeds from the future sale of hydrocarbons in the specified proved properties equal to the purchasers’ original investments, plus an overall rate of return. As the proceeds from the sale of hydrocarbons increase or decrease, primarily through changes in production levels and oil and natural gas prices, the payments due the holders of the overriding royalty interests will increase or decrease accordingly. If there is no production from a property during a payment period, there is no payment required. The percentage of property revenues available to satisfy these obligations is dependent upon certain conditions specified in the agreement. Upon payment of the agreed dollar amounts, the ownership of the Overrides reverts to us. Because of the explicit rate of return, dollar-denomination and limited payment terms of the Overrides, they are reflected in the accompanying financial statements as financing obligations. As such, the reserves and production revenues are retained by the Company. Related interest expense is presented net of amounts capitalized on the Consolidated Statements of Operations. We expect the Overrides to be repaid over the next 12 months based on projected production and commodity prices.

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Gomez Pipeline Obligation

In 2009, we executed an asset purchase and sale agreement for net proceeds of $74.5 million pursuant to which the Company sold to a third party the oil and natural gas pipelines that service the Gomez Hub at MC Block 711. In conjunction with the sale, we entered into agreements with the third party to transport our oil and natural gas production for the remaining production life of our fields serviced by theATP Innovator for a per-unit fee that is subject to a minimum monthly payment through December 31, 2016. Such minimum fees, if applicable, can be recovered by ATP in future periods within the same calendar year whenever fees owed during a month exceed the minimum due. We remain the operator of the pipeline and are responsible for all of the related operating costs. As a result of the retained asset retirement obligation and the purchaser’s option to convey the pipeline back to us at the end of the life of the fields in the Gomez Hub, the transaction has been accounted for as a financing obligation equal to the net proceeds received. This obligation is being amortized based on the estimated proved reserve life of the Gomez properties using the effective interest method with related interest expense presented net of amounts capitalized, on the Consolidated Statements of Operations. All payments made in excess of the minimum fee in future periods will be reflected as interest expense of the financing obligation.

Vendor Deferrals

In the Gulf of Mexico, in addition to the NPIs exchanged for development services described above, we have negotiated with certain other vendors involved in the development of the Telemark and Gomez Hubs to partially defer payments over a twelve-month period beginning with first production. We accrue the present value of the deferred payments and accrete the balance over the estimated term in which it is expected to be paid using the effective interest method with related interest expense presented net of amounts capitalized, on the Consolidated Statements of Operations.

In the U.K. North Sea, development of our interest in the Cheviot field continues. We have arranged with the fabricator of the floating production facility to defer $121.5 million of committed expenditures: $54.5 million to be paid in 2011 and $67.0 million to be paid in 2012. As work is completed, we record obligations and related interest expense, net of amounts capitalized, on the Consolidated Statements of Operations. See also Note 16 “Subsequent Events.”

The weighted average effective interest rate on our other long-term obligations was 16.7% at December 31, 2010.

Recently Issued Accounting Pronouncements

See Note 2, “Significant Accounting Policies - Recently Issued Accounting Pronouncements” to the Consolidated Financial Statements.

Contractual Obligations

The following table summarizes certain contractual obligations at December 31, 2010 (in thousands):

	Total		Less than 1 year		1 – 3 years		3 – 5 years		More than 5 years
First lien term loans	$	149,251	$	1,500	$	3,000	$	144,751	$	—
Interest on first lien term loans (1)		67,457		18,273		35,769		13,415		—
Senior second lien notes		1,500,000		—		—		1,500,000		—
Interest on senior second lien notes (1)		772,865		178,125		356,250		238,490		—
Term loan facility –ATP Titan assets		249,633		20,125		47,632		50,000		131,876
Interest on term loan facility –ATP Titan assets (1)		97,929		20,766		35,638		26,968		14,557
Other long-term obligations (2)		213,365		98,852		87,013		20,000		7,500
Other trade commitments		23,985		23,985		—		—		—
Noncancelable operating leases		1,526		1,360		166		—		—
Total contractual obligations	$	3,076,011	$	362,986	$	565,468	$	1,993,624	$	153,933

(1) Interest is based on rates and principal repayment requirements in effect at December 31, 2010.

(2) Included in the table above are $30.6 million of contractual amounts that we have committed to pay that are not yet incurred.

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Excluded from the table above are the following:

• Net profits interests payable and overriding royalty interests payable of $331.8 million and $52.8 million, respectively, as of December 31, 2010 that are payable only from the future cash flows of specified properties. The ultimate amount and timing of the payments will depend on production from the properties and future commodity prices and operating costs. We expect approximately 75% of the NPIs to be repaid over the next 24 months and all of the overrides to be repaid over the next 12 months based on projected production, commodity prices and operating costs.

• Dividends on our 8% convertible perpetual preferred stock, which are approximately $11.2 million per year. These dividends are payable in cash or stock at the Company’s option.

• Asset retirement obligations ($43.4 million current and $123.5 million long-term) at December 31, 2010. The ultimate settlement of such obligations is uncertain because they are subject to, among other things, federal, state, and local regulation, economic and operational factors.

Critical Accounting Policies and Estimates

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

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

Oil and Gas Property Accounting

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

Capitalized proved property acquisition costs are depleted on the unit-of-production method on the basis of total estimated units of proved reserves. Development costs relating to producing properties are depleted on the unit-of-production method on the basis of total estimated units of proved developed reserves. When significant development costs (such as the cost of an offshore production platform) are incurred in connection with a planned group of development wells before all of the planned wells have been drilled, it is occasionally necessary to exclude a portion of those development costs in determining the unit-of-production amortization rate until the additional development wells are drilled. However, in no case are future development costs anticipated in computing our amortization rate. Estimated dismantlement, restoration and abandonment costs and estimated residual salvage values are taken into account in calculating DD&A provisions. OurATP Titan andATP Innovator floating platforms are included in oil and gas properties and depreciated straight line over 40 and 25 years, respectively. Expenditures for geological and geophysical testing costs are generally charged to expense unless the costs can be specifically attributed to mapping a proved reservoir and determining the optimal placement for future developmental well locations. Expenditures for repairs and maintenance are charged to expense as incurred; renewals and betterments are capitalized. The costs and related accumulated DD&A and impairment of properties sold or otherwise retired are eliminated from the accounts, and gains or losses on disposition are reflected in the statements of operations.

We perform an impairment analysis whenever events or changes in circumstances indicate that an asset’s carrying amount may not be recoverable. To determine if a depletable unit is impaired, we compare the carrying value of the depletable unit to the undiscounted future net cash flows by applying management’s

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estimates of future oil and gas prices to the estimated future production of oil and gas reserves over the economic life of the property and deducting estimated future costs. Future net cash flows are based upon reservoir engineers’ estimates of proved reserves. In addition, other factors such as probable and possible reserves are taken into consideration when justified by economic conditions and actual or planned drilling or other development activities. For a property determined to be impaired, an impairment loss equal to the difference between the carrying value and the estimated fair value of the impaired property will be recognized. Fair value, on a depletable unit basis, is estimated to be the present value of the aforementioned expected future net cash flows. Unproved properties are assessed periodically to determine whether they have been impaired. An impairment allowance is provided on an unproved property when we determine that the property will not be developed, but no later than lease expiration. Any impairment charge incurred is recorded in accumulated DD&A to reduce our recorded basis in the asset. Each part of this calculation is subject to a large degree of judgment, including the determination of the depletable units’ estimated reserves, future net cash flows and fair value.

Oil and Gas Reserves

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

Asset Retirement Obligations

We have obligations related to the plugging and abandonment of our oil and gas wells, dismantling our offshore production platforms, and the removal of equipment and facilities from leased acreage and returning such land to its original condition. We estimate the future cost of this obligation, discounted to its present value, and record a corresponding liability and asset in our consolidated balance sheets. The values ultimately derived are based on many significant estimates, including the ultimate expected cost of the obligation, the expected future date of the required cash payment, and interest and inflation rates. Revisions to these estimates may be required based on changes to cost estimates, the timing of settlement, and changes in legal requirements. Any such changes that result in upward or downward revisions in the estimated obligation will result in an adjustment to the liability with the offset to the related capitalized asset on a prospective basis. We recognize accretion expense on our aggregate asset retirement obligations, reflecting the change in the present value of the approaching obligations with the passage of time.

Other Long-term Obligations

We have significant obligations primarily related to placing theATP Titan in service and completing and commencing production from the underlying Telemark Hub oil and gas wells. A significant portion of these costs will be paid from net profits interests in the underlying reserves, or under vendor payment deferral arrangements. The recorded liabilities for these costs are affected by some significant estimates, including the ultimate cost of the obligations, the ultimate reserves produced and the timing of production, which dictates the timing of the future cash payments. Such estimated amounts are discounted so that they are reflected on the consolidated balance sheet at present value. Revisions to these estimates may be required which will result in upward or downward revisions in the recorded long-term obligations and associated interest expense on a prospective basis.

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Price Risk-Management Activities

We periodically enter into commodity derivative contracts and fixed-price physical forward contracts to manage our exposure to oil and natural gas price volatility. We primarily utilize fixed-price physical forward contracts, price swaps and put options, which are generally placed with major financial institutions or with counterparties of high credit quality to minimize our credit risks. The oil and natural gas reference prices of these commodity derivative contracts are based upon oil and natural gas market exchanges, which have a high degree of historical correlation with actual prices we receive. All derivative instruments, unless designated as normal purchases and sales, are recorded on the balance sheet at fair value. We are accounting for these contracts as derivatives under the accounting standards for derivatives and hedging with changes in fair value recorded as components of derivative income (expense) in our consolidated statement of operations.

Changes in the derivative’s fair value are recognized currently in earnings unless specific hedge accounting criteria are met. For qualifying cash flow hedges, hedge accounting rules provide that the gain or loss on the derivative is deferred in accumulated other comprehensive income to the extent the hedge is effective, and such deferred gains or losses are reclassified to oil and natural gas sales revenue in the period that the related production is delivered. At December 31, 2010, we had no derivative contracts in place that qualified for hedge accounting.

Valuation of Deferred Tax Asset

We compute income taxes using an asset and liability approach, which results in the recognition of deferred tax liabilities and assets for the expected future tax consequences of temporary differences between the carrying amounts and the tax basis of those assets and liabilities. We also record a valuation allowance if it is more likely than not that some or all of a deferred tax asset will not be realized. In determining whether a valuation allowance is appropriate, we weigh positive and negative evidence that suggests whether a deferred tax asset is likely to be recoverable. As of December 31, 2010, for U.S. tax provision purposes, we have provided valuation allowance for the remainder of our net deferred tax assets based on our cumulative net losses coupled with the increased uncertainties surrounding our future earnings forecasts arising from the continued permitting delays in the Gulf of Mexico.

Off-Balance Sheet Arrangements

The Company has no off-balance sheet arrangements at December 31, 2010.

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

Commodity Price Risk

Our revenues, profitability and future growth depend substantially on prevailing prices for oil and natural gas. Prices also affect the amount of cash flow available for capital expenditures and our ability to borrow and raise additional capital. Lower prices may also reduce the amount of oil and natural gas that we can economically produce. We currently sell a portion of our oil and natural gas production under market price contracts. We periodically use derivative instruments to hedge our commodity price risk. We hedge a portion of our projected oil and natural gas production through a variety of financial and physical arrangements intended to support oil and natural gas prices at targeted levels and to manage our exposure to price fluctuations. We may use futures contracts, swaps, put options, price collars and fixed-price physical forward contracts to hedge our commodity prices. See Note 13, “Derivative Instruments and Risk Management Activities” to Consolidated Financial Statements. We do not hold or issue derivative instruments for speculative purposes.

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At February 28, 2011, we had derivative contracts in place for the following oil and natural gas volumes:

Period	Type	Volumes		Price
				$/Unit (1)
Oil (Bbl) –Gulf of Mexico
2011	Swaps		1,873,750		82.31
2012	Swaps		1,120,750		89.37
2013	Swaps		90,000		90.00
2011	Swaps (2)		734,000		78.67
Natural Gas (MMBtu)
North Sea
2011	Swaps		1,346,000		7.56
2012	Swaps		1,464,000		8.20
Gulf of Mexico
2011	Fixed-price physicals		4,435,000		4.69
2012	Fixed-price physicals		1,365,000		4.64
2011	Collars		465,000		4.75-7.95

(1) Unit prices for collars reflect the floor and ceiling prices, respectively.

(2) These swaps have been matched with call options to allow us to reparticipate in per barrel price increases above $110.83.

Interest Rate Risk

We are exposed to changes in interest rates on ourATP Titan assets - Term Loan Facility as described in Management’s Discussion and Analysis of Financial Condition and Results of Operations: Liquidity and Capital Resources. Otherwise we have no exposure to changes in interest rates because the interest rates on our other long-term debt instruments are fixed.

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 value of the local currency arising from the process of re-measuring the local functional currency in U.S. dollars.

Item 8.Financial Statements and Supplementary Data.

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

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

None.

Item 9A. Controls and Procedures.

Disclosure Controls and Procedures

Our management, under the supervision of and with the participation of our Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of ATP Oil & Gas Corporation’s disclosure controls and procedures, as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Securities and Exchange Act of 1934, as amended (the “Exchange Act”) as of December 31, 2010 (the “Evaluation Date”). Based on this evaluation, the Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of the Evaluation Date to ensure that the information required to be disclosed

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in our Exchange Act filings is (1) recorded, processed, summarized and reported within the time periods specified in Securities and Exchange Commission’s rules and forms, and (2) accumulated and communicated to management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.

Management’s Report on Internal Control over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) promulgated under the Exchange Act).

Our management assessed the effectiveness of our internal control over financial reporting as of December 31, 2010. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission inInternal Control – Integrated Framework. Based on this assessment, management concluded that our internal control over financial reporting was effective as of December 31, 2010.

PricewaterhouseCoopers LLP, an independent registered public accounting firm, has audited the effectiveness of our internal control over financial reporting as of December 31, 2010, as stated in their report, which appears herein.

Changes in Internal Control Over Financial Reporting

There were no changes in internal control over financial reporting during the quarter ended December 31, 2010 that materially affected, or are reasonably likely to materially affect our internal control over financial reporting.

Remediation of Material Weakness

As of December 31, 2009, we determined that a material weakness existed in our internal control over accounting for outstanding liabilities. Specifically, our procedures were not adequate to ensure proper cut-off associated with goods received or services rendered by our vendors and that liabilities and the associated capital additions were recorded in the appropriate periods. We believe that the material weakness identified at December 31, 2009 was attributable to factors caused by the substantial activity at year-end 2009 focused on the completion of our major development project at our Telemark Hub. During the first quarter of 2010, we emphasized the importance of the accrual process with all employees who are integral to the accruals process and we enhanced our processes to address such changes in activity by implementing new procedures to seek out sufficient information related to major vendor activities at each balance sheet date to ensure that we have proper cut-off when preparing capital accruals. We also implemented secondary reviews of the accruals to ensure the reasonableness of the accruals as of the balance sheet date. In the second quarter of 2010, we refined the changes introduced in the prior quarter and further introduced a process to increase accountability through written certifications from certain key employees in the accrual process. Management has performed testing that validates the operating effectiveness of these controls. Based on management’s operating effectiveness testing of these controls, we believe that this material weakness in internal control over financial reporting has been fully remediated as of the Evaluation Date.

Item 9B. Other Information.

None.

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PART III

Item 10. Directors, Executive Officers and Corporate Governance.

Executive Officers of the Company and Other Key Employees

Set forth below are the names, ages (as of February 28, 2011) and titles of the persons currently serving as executive officers of the Company. There are no term limits for the executive officers.

Name	Age	Position
T. Paul Bulmahn	67	Chairman and Chief Executive Officer
Leland E. Tate	63	President
Albert L. Reese Jr.	61	Chief Financial Officer
George R. Morris	56	Chief Operating Officer
John E. Tschirhart	60	Senior Vice President, International, General Counsel
Isabel M. Plume	50	Chief Communications Officer
Keith R. Godwin	43	Chief Accounting Officer

T. Paul Bulmahn has served as our Chairman and Chief Executive Officer since May 2008 and before that as 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.

Leland E. Tate has served as our President since May 2008, before that as Chief Operating Officer since December 2003 and Sr. Vice President, Operations since August 2000. Prior to joining us, 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.

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

George R. Morris has served as our Chief Operating Officer since May 2008. He served as our Vice President, Acquisitions from 2002 until 2004 and upon his return to the company in 2007. From 2004 until 2007, Mr. Morris was Chief Operating Officer at Chroma Exploration & Production. Prior to joining us in 2002 and during a career that spanned 30 years, Mr. Morris held executive and management positions in operations and engineering at Burlington Resources, Louisiana Land and Exploration, Nerco Oil & Gas and Union Texas Petroleum. Mr. Morris is a registered professional engineer in the State of Texas and has a B.S. in mechanical engineering from Colorado State University.

John E. Tschirhart joined us in November 1997 and has served as our General Counsel since March 1998 and Assistant Corporate Secretary since 2007. 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

57

law firm of Tschirhart and Daines, a partnership in Houston, Texas. From 1985 to 1993 Mr. Tschirhart was in private practice handling civil litigation matters including oil and gas and employment law. From 1979 to 1985, he was with Coastal Oil & Gas Corporation and from 1974 to 1979 he was with Shell Oil Company.

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

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

Except for the information relating to Executive Officers of the Registrant set forth above, the information required by Item 10 of Form 10-K is incorporated herein by reference to the definitive proxy statement for the Company’s Annual Meeting of Shareholders to be held on May 26, 2011 (the “Proxy Statement.”)

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

Item 11.Executive Compensation.

Incorporated by reference to the Company’s Proxy Statement.

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

Incorporated by reference to the Company’s Proxy Statement.

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

Incorporated by reference to the Company’s Proxy Statement.

Item 14. Principal Accounting Fees and Services.

Incorporated by reference to the Company’s Proxy Statement.

58

PART IV

Item 15.Exhibits, Financial Statement Schedules.

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

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

(a) (3) Exhibits

3.1	Amended and Restated Certificate of Formation, incorporated by reference to Exhibit 3.1 of the Current Report on Form 8-K of ATP Oil & Gas Corporation (“ATP”) filed June 10, 2010.
3.2	Statement of Resolutions Establishing the 8.00% Convertible Perpetual Preferred Stock of ATP Oil & Gas Corporation, incorporated by reference to Exhibit 4.4 of Registration Statement No. 333-162574 on Form S-3 of ATP filed October 19, 2009.
3.3	Third Amended and Restated Bylaws of ATP Oil & Gas Corporation, incorporated by reference to Exhibit 3.1 of ATP’s Current Report on Form 8-K filed December 15, 2009.
4.1	Rights Agreement dated October 11, 2005 between ATP and American Stock Transfer & Trust Company, as Rights Agent, specifying the terms of the Rights, which includes the form of Statement of Designations of Junior Participating Preferred Stock as Exhibit A, the form of Right Certificate as Exhibit B and the form of the Summary of Rights to Purchase Preferred Shares as Exhibit C, incorporated by reference to Exhibit 1 to the Company’s Registration Statement on Form 8-A filed with the Securities and Exchange Commission on October 14, 2005.
4.2	Form of Stock Certificate for 8.00% Convertible Perpetual Preferred Stock, incorporated by reference to Exhibit 4.1 of ATP’s Form 8-K dated September 29, 2009.
4.3	Indenture dated as of April 23, 2010 between the Company and The Bank of New York Mellon Trust Company, N.A., as trustee (“Trustee”), incorporated by reference to Exhibit 4.1 to ATP’s Current Report on Form 8-K dated April 29, 2010.
4.4	Registration Rights Agreement dated as of April 23, 2010 between the Company and J.P. Morgan Securities Inc., incorporated by reference to Exhibit 10.2 to ATP’s Current Report on Form 8-K dated April 29, 2010.
4.5	Form of Nonqualified Stock Option Agreement, incorporated by reference to Exhibit 4.6 of Registration Statement No. 333-171263 on Form S-8 of ATP filed December 17, 2010.
4.6	Form of Restricted Stock Award Agreement (to be used in connection with awards to directors of ATP), incorporated by reference to Exhibit 4.7 of Registration Statement No. 333-171263 on Form S-8 of ATP filed December 17, 2010.
4.7	Form of Restricted Stock Award Agreement (to be used in connection with awards to executive officers of ATP), incorporated by reference to Exhibit 4.8 of Registration Statement No. 333-171263 on Form S-8 of ATP filed December 17, 2010.
10.1	Credit Agreement dated as of June 18, 2010 among ATP Oil & Gas Corporation, Credit Suisse AG and the lenders party thereto, incorporated by reference to Exhibit 10.1 of ATP’s Current Report on Form 8-K dated June 18, 2010.
10.2	Term Loan Agreement, dated as of September 24, 2010 among Titan LLC, as the Borrower, CLMG Corp., as Agent, and the Lenders party thereto incorporated by reference to Exhibit 99.1 to ATP’s Current Report on Form 8-K dated September 24, 2010.
10.3	ATP Oil & Gas Corporation 2010 Stock Plan incorporated by reference to Appendix A to ATP’s Schedule 14A dated April 29, 2010.
10.4	Intercreditor Agreement dated as of April 23, 2010 among the Company, the Trustee and Credit Suisse AG, incorporated by reference to Exhibit 10.3 to ATP’s Current Report on Form 8-K dated April 29, 2010.
10.5	Sale and Purchase Agreement between ATP Oil & Gas (UK) Limited and EDF Production UK Ltd., as amended and restated on October 23, 2008, incorporated by reference to Exhibit 10.1 to ATP’s Report on Form 10-Q for the quarter ended September 30, 2008.
10.6	Employment Agreement between ATP and Leland E. Tate, dated December 30, 2010, incorporated by reference to Exhibit 10.5 to ATP’s Form 8-K dated December 30, 2010.

59

10.7	Employment Agreement between ATP and Albert L. Reese, Jr., dated December 30, 2010, incorporated by reference to Exhibit 10.4 to ATP’s Form 8-K dated December 30, 2010.
10.8	Employment Agreement between ATP and Keith R. Godwin, dated December 30, 2010, incorporated by reference to Exhibit 10.2 to ATP’s Form 8-K dated December 30, 2010.
10.9	Employment Agreement between ATP and T. Paul Bulmahn, dated December 30, 2010, incorporated by reference to Exhibit 10.1 to ATP’s Form 8-K dated December 30, 2010.
10.10	Employment Agreement between ATP and George R. Morris, dated December 30, 2010, incorporated by reference to Exhibit 10.3 to ATP’s Form 8-K dated December 30, 2010.
10.11	All Employee Bonus Policy, incorporated by reference to exhibit 10.16 to ATP’s Annual Report on Form 10-K for the year ended December 31, 2008.
10.12	Discretionary Bonus Policy, incorporated by reference to exhibit 10.17 to ATP’s Annual Report on Form 10-K for the year ended December 31, 2008.
10.13	Incremental Loan Assumption Agreement and Amendment No. 1 to Credit Agreement among ATP, the lenders party thereto and Credit Suisse AG, incorporated by reference to Exhibit 10.1 of ATP’s form 8-K dated February 19, 2011.
21.1	Subsidiaries of ATP, incorporated by reference to Exhibit 21.1 to ATP’s Report on Form 10-Q for the quarter ended September 30, 2010.
*23.1	Consent of PricewaterhouseCoopers LLP.
*23.2	Consent of Collarini Associates.
*23.3	Consent of Ryder Scott Company, L.P.
*23.4	Management report of third party engineers – Collarini Associates
*23.5	Management report of third party engineers – Ryder Scott Company, L.P. – Gulf of Mexico
*31.1	Certification of Principal Executive Officer pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934, the “Act”
*31.2	Certification of Principal Financial Officer pursuant to Rule 13a-14(a) of the Act
*32.1	Certification of Principal Executive Officer pursuant to 18 U.S.C. Section 1350
*32.2	Certification of Principal Financial Officer pursuant to 18 U.S.C. Section 1350

* Filed herewith

60

SIGNATURES

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

ATP Oil & Gas Corporation
By:	/s/ Albert L. Reese Jr.
	Albert L. Reese Jr.
	Chief Financial Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the registrant in the capacities indicated on March 15, 2011.

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

61

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

	Page
Report of Independent Registered Public Accounting Firm		F-2
Consolidated Balance Sheets as of December 31, 2010 and 2009		F-3
Consolidated Statements of Operations for the years ended December 31, 2010, 2009 and 2008		F-4
Consolidated Statements of Cash Flows for the years ended December 31, 2010, 2009 and 2008		F-5
Consolidated Statements of Shareholders’ Equity and Noncontrolling Interest for the years ended December 31, 2010, 2009 and 2008		F-6
Consolidated Statements of Comprehensive Income (Loss) for the years ended December  31, 2010, 2009 and 2008		F-7
Notes to Consolidated Financial Statements		F-8
Supplemental Disclosures About Oil and Gas Producing Activities (Unaudited)		F-33
Schedule I – Parent Company Financial Statements		S-1
Schedule II – Valuation and Qualifying Accounts for each of the three years ended December  31, 2010		S-5

F-1

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Shareholders of

ATP Oil & Gas Corporation:

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of operations, of shareholders’ equity and noncontrolling interest, of comprehensive income (loss) and of cash flows present fairly, in all material respects, the financial position of ATP Oil & Gas Corporation and its subsidiaries at December 31, 2010 and 2009, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2010 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedules listed in the accompanying index present fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2010, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for these financial statements and financial statement schedules, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s Report on Internal Control over Financial Reporting appearing under Item 9A. Our responsibility is to express opinions on these financial statements, on the financial statement schedules, and on the Company’s internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

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

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ PricewaterhouseCoopers LLP

Houston, Texas

March 16, 2011

F-2

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(In Thousands, Except Share Amounts)

	December 31,
	2010			2009
Assets
Current assets:
Cash and cash equivalents	$	154,695		$	108,961
Restricted cash		30,270			10,504
Accounts receivable (net of allowance of $225 and $291, respectively)		92,737			52,551
Deferred tax asset		8,191			101,956
Derivative asset		1,688			1,321
Other current assets		26,408			10,615
Total current assets		313,989			285,908
Oil and gas properties (using the successful efforts method of accounting):
Proved properties		4,291,440			3,609,131
Unproved properties		20,402			13,910
		4,311,842			3,623,041
Less accumulated depletion, depreciation, impairment and amortization		(1,407,206	)		(1,137,269	)
Oil and gas properties, net		2,904,636			2,485,772
Restricted cash		10,000			—
Deferred financing costs, net		48,353			16,378
Other assets, net		13,124			15,089
Total assets	$	3,290,102		$	2,803,147
Liabilities and Equity
Current liabilities:
Accounts payable and accruals	$	230,703		$	212,736
Current maturities of long-term debt		21,625			16,838
Asset retirement obligation		43,386			43,418
Derivative liability		37,893			16,216
Other current liabilities		86,521			23,094
Total current liabilities		420,128			312,302
Long-term debt		1,857,784			1,199,847
Other long-term obligations		472,500			274,942
Asset retirement obligation		123,472			106,781
Deferred tax liability		16,956			146,764
Derivative liability		6,425			7,646
Deferred revenue		—			19,336
Total liabilities		2,897,265			2,067,618
Commitments and contingencies (Note 12)
Temporary equity – redeemable noncontrolling interest		140,851			139,598
Shareholders’ equity:
8% convertible perpetual preferred stock: $0.001 par value, 10,000,000 shares authorized; 1,400,000 issued and outstanding at December 31, 2010 and 2009 at liquidation value		140,000			140,000
Common stock: $0.001 par value, 100,000,000 shares authorized; 51,271,323 issued and 51,267,573 outstanding at December 31, 2010; 50,755,310 issued and 50,679,470 outstanding at December 31, 2009		51			51
Additional paid-in capital		570,739			571,595
Accumulated deficit		(356,866	)		(19,317	)
Accumulated other comprehensive loss		(101,027	)		(95,487	)
Treasury stock, at cost		(911	)		(911	)
Total shareholders’ equity		251,986			595,931
Total liabilities and equity	$	3,290,102		$	2,803,147

See accompanying notes to the consolidated financial statements.

F-3

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(In Thousands, Except Per Share Amounts)

	Year Ended December 31,
	2010			2009			2008
Revenues:
Oil and gas production	$	437,997		$	298,490		$	584,823
Other		—			13,664			33,206
		437,997			312,154			618,029
Costs, operating expenses and other:
Lease operating		132,544			84,956			91,196
Exploration		1,174			264			48
General and administrative		44,894			44,211			41,653
Depreciation, depletion and amortization		220,657			152,780			246,434
Impairment of oil and gas properties		63,267			45,799			125,059
Accretion of asset retirement obligation		13,827			11,676			15,566
Drilling interruption costs		23,647			—			—
Loss on abandonment		4,829			2,872			13,289
Gain on exchange/disposal of properties		(26,720	)		(12,433	)		(119,233	)
Other, net		(946	)		(742	)		(99	)
		477,173			329,383			413,913
Income (loss) from operations		(39,176	)		(17,229	)		204,116
Other income (expense):
Interest income		696			710			3,476
Interest expense, net		(222,104	)		(40,884	)		(100,729	)
Derivative income (expense)		(22,419	)		(712	)		89,035
Loss on debt extinguishment		(75,316	)		—			(24,220	)
		(319,143	)		(40,886	)		(32,438	)
Income (loss) before income taxes		(358,319	)		(58,115	)		171,678
Income tax (expense) benefit:
Current		859			(545	)		(1,969	)
Deferred		35,414			23,079			(48,004	)
		36,273			22,534			(49,973	)
Net income (loss)		(322,046	)		(35,581	)		121,705
Less income attributable to the redeemable noncontrolling interest		(15,503	)		(13,380	)		—
Less convertible preferred stock dividends		(11,248	)		(2,856	)		—
Net income (loss) attributable to common shareholders	$	(348,797	)	$	(51,817	)	$	121,705
Net income (loss) per share attributable to common shareholders:
Basic	$	(6.88	)	$	(1.24	)	$	3.43
Diluted	$	(6.88	)	$	(1.24	)	$	3.39
Weighted average number of common shares:
Basic		50,715			41,853			35,457
Diluted		50,715			41,853			35,868

See accompanying notes to the consolidated financial statements.

F-4

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In Thousands)

	Year Ended December 31,
	2010			2009			2008
Cash flows from operating activities
Net income (loss)	$	(322,046	)	$	(35,581	)	$	121,705
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities –
Depreciation, depletion and amortization		220,657			152,780			246,434
Impairment of oil and gas properties		63,267			45,799			125,059
Gain on exchange/disposal of properties		(26,720	)		(12,433	)		(119,233	)
Accretion of asset retirement obligation		13,827			11,676			15,566
Deferred income tax expense (benefit)		(35,414	)		(23,079	)		48,004
Derivative (income) expense		20,090			39,648			(3,976	)
Loss on debt extinguishment		18,973			—			15,370
Stock-based compensation		6,825			7,951			12,018
Amortization of deferred revenue		(19,336	)		(39,893	)		(22,771	)
Noncash interest expense		28,078			13,262			14,998
Other noncash items, net		3,245			2,443			13,630
Changes in assets and liabilities –
Accounts receivable and other current assets		(31,979	)		50,402			32,546
Accounts payable and accruals		23,213			(53,168	)		49,658
Other assets and liabilities		40			20			(2,041	)
Net cash provided by (used in) operating activities		(37,280	)		159,827			546,967
Cash flows from investing activities
Additions to oil and gas properties		(598,108	)		(635,447	)		(917,693	)
Proceeds from disposition of properties		17,053			13,000			471,846
Decrease (increase) in restricted cash		(29,766	)		(10,504	)		13,837
Net cash used in investing activities		(610,821	)		(632,951	)		(432,010	)
Cash flows from financing activities
Proceeds from senior second lien notes		1,492,965			—			—
Proceeds from first lien term loans		147,000			—			—
Proceeds from term loan facility–Titan assets		238,750			—			—
Proceeds from term loans		46,000			19,000			1,639,750
Payments of term loans		(1,263,727	)		(176,512	)		(1,680,190	)
Deferred financing costs		(62,937	)		(6,490	)		(15,523	)
Issuance of common stock, net of costs		—			170,629			—
Issuance of preferred stock, net of costs		—			135,549			—
Proceeds from other long-term obligations		231,888			89,011			—
Payments of other long-term obligations		(102,818	)		(2,298	)		(13,397	)
Sale of redeemable noncontrolling interest, net of costs		—			148,751			—
Distributions to noncontrolling interest		(14,250	)		(18,970	)		—
Preferred stock dividends		(11,276	)		—			—
Payments of short-term notes		(11,180	)		—			—
Exercise of stock options		3,609			3			33
Net cash provided by (used in) financing activities		694,024			358,673			(69,327	)
Effect of exchange rate changes on cash and cash equivalents		(189	)		8,419			(30,086	)
Increase (decrease) in cash and cash equivalents		45,734			(106,032	)		15,544
Cash and cash equivalents, beginning of year		108,961			214,993			199,449
Cash and cash equivalents, end of year	$	154,695		$	108,961		$	214,993

See accompanying notes to the consolidated financial statements.

F-5

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY

AND NONCONTROLLING INTEREST

(In Thousands)

	2010					2009					2008
	Shares		Amount			Shares		Amount			Shares		Amount
Temporary Equity – Redeemable
Noncontrolling Interest
Balance, beginning of year			$	139,598				$	—				$	—
Sale of Class A Limited Partner Interest, net of formation costs				—					148,751					—
Income attributable to the redeemable noncontrolling interest				15,503					13,380					—
Limited partner distributions				(14,250	)				(22,533	)				—
Balance, end of year			$	140,851				$	139,598				$	—
Shareholders’ Equity:
8% Convertible Perpetual Preferred Stock, liquidation value
Balance, beginning of year		1,400	$	140,000			—	$	—			—	$	—
Issuance of preferred stock		—		—			1,400		140,000			—		—
Balance, end of year		1,400	$	140,000			1,400	$	140,000			—	$	—
Common Stock
Balance, beginning of year		50,679	$	51			35,903	$	36			35,732	$	36
Issuances of common stock
Secondary offerings		—		—			14,565		15			—		—
Exercise of stock options/warrants		418		—			—		—			8		—
Restricted stock, net of forfeitures		171		—			211		—			163		—
Balance, end of year		51,268	$	51			50,679	$	51			35,903	$	36
Paid-in Capital
Balance, beginning of year			$	571,595				$	400,334				$	388,250
Issuances of common stock
Secondary offerings				—					179,750					—
Costs of issuances				—					(13,588	)				—
Exercise of stock options/warrants				3,567					4					66
Stock-based compensation				6,825					7,951					12,018
Preferred stock dividends				(11,248	)				(2,856	)				—
Balance, end of year			$	570,739				$	571,595				$	400,334
Retained Earnings (Accumulated Deficit)
Balance, beginning of year			$	(19,317	)			$	29,644				$	(92,061	)
Net income (loss)				(322,046	)				(35,581	)				121,705
Income attributable to the redeemable noncontrolling interest				(15,503	)				(13,380	)				—
Balance, end of year			$	(356,866	)			$	(19,317	)			$	29,644
Accumulated Other Comprehensive Income (Loss)
Balance, beginning of year			$	(95,487	)			$	(112,754	)			$	14,552
Other comprehensive income (loss)				(5,540	)				17,267					(127,306	)
Balance, end of year			$	(101,027	)			$	(95,487	)			$	(112,754	)
Treasury Stock, at Cost
Balance, beginning of year		76	$	(911	)		76	$	(911	)		76	$	(911	)
Balance, end of year		76	$	(911	)		76	$	(911	)		76	$	(911	)
Total Shareholders’ Equity			$	251,986				$	595,931				$	316,349

See accompanying notes to the consolidated financial statements.

F-6

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(In Thousands)

	Year Ended December 31,
	2010			2009			2008
Net income (loss)	$	(322,046	)	$	(35,581	)	$	121,705
Other comprehensive income (loss):
Reclassification adjustment for settled hedge contracts (net of taxes of $0, $859 and ($5,083), respectively)		—			(859	)		5,890
Change in fair value of outstanding hedge positions (net of taxes of $0, ($3,736) and $12,237, respectively)		—			3,736			(12,677	)
Reclassification adjustment for dedesignated hedge contracts (net of taxes of $0, $0 and ($19,288), respectively)		—			—			21,258
Foreign currency translation adjustment, net of tax		(5,540	)		14,390			(141,777	)
Other comprehensive income (loss)		(5,540	)		17,267			(127,306	)
Comprehensive loss		(327,586	)		(18,314	)		(5,601	)
Less comprehensive income attributable to the redeemable noncontrolling interest		(15,503	)		(13,380	)		—
Comprehensive loss attributable to shareholders		(343,089	)		(31,694	)		(5,601	)
Less convertible preferred stock dividends		(11,248	)		(2,856	)		—
Comprehensive loss attributable to common shareholders	$	(354,337	)	$	(34,550	)	$	(5,601	)

See accompanying notes to the consolidated financial statements.

F-7

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1 — Organization and Basis of Presentation

Organization

ATP Oil & Gas Corporation (“the Company”) was incorporated in Texas in 1991. We are engaged in the acquisition, development and production of oil and natural gas properties in the Gulf of Mexico and the U.K. and Dutch Sectors of the North Sea (the “North Sea”). We primarily focus our efforts on oil and natural gas properties where previous drilling has encountered reservoirs that appear to contain commercially productive quantities of oil and gas. Many of these properties contain proved undeveloped reserves that are economically attractive to us but are not strategic to major or large exploration-oriented independent oil and gas companies. Occasionally we will acquire properties that are already producing or where previous drilling has encountered reservoirs that appear to contain commercially productive quantities of oil and gas even though the reservoirs do not meet the Securities and Exchange Commission (“SEC”) definition of proved reserves.

Basis of Presentation

The consolidated financial statements include our accounts, the accounts of our majority owned limited partnership, ATP Infrastructure Partners, L.P. (“ATP-IP”) and those of our wholly-owned subsidiaries; ATP Energy, Inc.; ATP Oil & Gas (UK) Limited, or “ATP (UK);” ATP Oil & Gas (Netherlands) B.V.; ATP Titan, LLC (“Titan LLC”) and four other wholly owned limited liability companies created to own our interests in ATP-IP and Titan LLC. All intercompany transactions are eliminated in consolidation, and we separate the redeemable noncontrolling interest in ATP-IP in the accompanying statements because the partnership agreement provides certain redemption rights to the Class A limited partner interests in the event a change of control occurs at ATP.

Note 2 — Summary of Significant Accounting Policies

Use of Estimates

The preparation of financial statements in accordance with U.S. generally accepted accounting principles and pursuant to the rules and regulations of the 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. Actual results could differ from those estimates.

Cash and Cash Equivalents

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

Restricted Cash

At December 31, 2010, restricted cash relates to an escrow account for ATP-IP, discussed below, which holds cash in excess of monthly partnership distributions and operating needs. Also, theATP Titan Facility, discussed below, requires us to maintain in a restricted account a minimum $10.0 million cash balance (classified as noncurrent on the Consolidated Balance Sheet) plus additional amounts based on production at the Telemark Hub to be used for the quarterly debt service of theATP Titan Facility.

Oil and Gas Properties

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

Capitalized proved property acquisition costs are depleted on the unit-of-production method on the basis of total estimated units of proved reserves. Capitalized costs relating to producing properties are depleted on the unit-of-production method on the basis of total estimated units of proved developed reserves. When significant development costs (such as the cost of an offshore production platform) are incurred in connection with a planned group of development wells before all of the planned wells have been drilled, it is occasionally necessary to exclude a portion of those development costs in determining the unit-of-production depletion rate

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ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

until the additional development wells are drilled. However, in no case are future development costs anticipated in computing our depletion rate. Estimated dismantlement, restoration and abandonment costs and estimated residual salvage values are taken into account in determining depletion provisions. OurATP Titan andATP Innovator floating platforms are included in oil and gas properties and depreciated straight line over 40 and 25 years, respectively. Expenditures for geological and geophysical testing costs are generally charged to expense unless the costs can be specifically attributed to mapping a proved reservoir and determining the optimal placement for future developmental well locations. Expenditures for repairs and maintenance are charged to expense as incurred; renewals and betterments are capitalized. The costs and related accumulated depreciation, depletion, and amortization of properties sold or otherwise retired are eliminated from the accounts, and gains or losses on disposition are reflected in the statements of operations.

We perform impairment analysis whenever events or changes in circumstances indicate that an asset’s carrying amount may not be recoverable. To determine if a depletable unit is impaired, we compare the carrying value of the depletable unit to the undiscounted future net cash flows by applying management’s estimates of future oil and gas prices to the estimated future production of oil and gas reserves over the economic life of the property and deducting future costs. Future net cash flows are based upon reservoir engineers’ estimates of proved reserves. In addition, other factors such as probable and possible reserves are taken into consideration when justified by economic conditions and actual or planned drilling or other development activities. For a property determined to be impaired, an impairment loss equal to the difference between the carrying value and the estimated fair value of the impaired property will be recognized. Fair value, on a depletable unit basis, is estimated to be the present value of the aforementioned expected future net cash flows. Unproved properties are assessed periodically to determine whether they have been impaired. An impairment allowance is provided on an unproved property when we determine that the property will not be developed, but no later than lease expiration. Any impairment charge incurred is recorded in accumulated depletion, depreciation, impairment and amortization to reduce our basis in the asset. Each part of these calculations is subject to a large degree of judgment, including estimated reserves, future net cash flows and fair value.

We recorded impairments during the years ended December 31, 2010, 2009 and 2008 totaling $42.4 million, $44.6 million and $124.7 million, respectively, on certain proved properties in the Gulf of Mexico. We also recorded impairments totaling $14.9 million during 2010, on certain proved properties in the North Sea. The 2010 impairments were primarily due to updated performance history. The 2009 impairments are primarily a result of reduced commodity prices and unfavorable operating performance. The 2008 impairments are primarily due to reduced commodity prices and reductions in estimates of recoverable reserves.

Impairments of unproved properties were $6.0 million, $1.2 million and $0.4 million in 2010, 2009 and 2008, respectively, primarily related to surrendered leases in the Gulf of Mexico.

Management’s assumptions used in calculating oil and gas reserves or regarding the future net 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 commodity price forecasts change, so too will the estimate of future net cash flows and the fair value estimates.

As of December 31, 2010, there were $9.5 million of capitalized exploratory well costs (suspended well costs) related to two wells in the North Sea which were still being evaluated, none of which have been capitalized in excess of one year.

Asset Retirement Obligation

We recognize liabilities associated with the eventual retirement of tangible long-lived assets, upon the acquisition, construction and development of the assets. We record the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of the related long-lived asset. Changes in estimates on fully depleted properties are charged directly to loss on abandonment.

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ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

We recognize (i) depletion expense on the additional capitalized asset retirement costs; (ii) accretion expense as the present value of the future asset retirement obligation increases with the passage of time, and; (iii) the impact, if any, of changes in estimates of the liability. The following table sets forth a reconciliation of the beginning and ending asset retirement obligation (in thousands):

	December 31,
	2010			2009			2008
Asset retirement obligation, beginning of year	$	150,199		$	132,108		$	186,771
Liabilities incurred		5,960			16,220			7,642
Liabilities settled		(15,362	)		(9,603	)		(18,595	)
Property dispositions		(242	)		(292	)		(17,681	)
Accretion expense		13,827			11,676			15,566
Changes in estimates		12,476			90			(41,595	)
Total asset retirement obligation, end of year		166,858			150,199			132,108
Less current portion		43,386			43,418			32,854
Total long-term asset retirement obligation, end of year	$	123,472		$	106,781		$	99,254

During 2010, 2009 and 2008, we recognized loss on abandonment of $4.8 million, $2.9 million and $13.3 million, respectively. These amounts are primarily the result of actual abandonment operations in the Gulf of Mexico requiring more work than originally estimated.

Limited Partnership

On March 6, 2009, along with GE Energy Financial Services (“GE”), we formed ATP-IP to own theATP Innovator, the floating production facility that currently serves our Mississippi Canyon Block 711 Gomez Hub properties. We contributed theATP Innovatorin exchange for a 49% subordinated limited partner interest, a 2% general partner interest and cash. GE paid $150.0 million to ATP-IP for a 49% Class A limited partner interest. We remain the operator and continue to hold a 100% working interest in the Gomez field and its oil and gas reserves. The transaction was effective June 1, 2008 and allows us exclusive use of theATP Innovatorduring the term of the Platform Use Agreement (“PUA”), which is expected to be the economic life of the Gomez Hub reserves.

From an operational standpoint, during the term of the PUA, we are obligated to pay to ATP-IP a per unit fee for all hydrocarbons processed by theATP Innovator, subject to a minimum throughput fee of $53,000 per day. Such minimum fees, if applicable, can be recovered by us in future periods whenever fees owed during a month exceed the minimum due. We may also be subject to a minimum fee of $53,000 per day for up to 180 days under certain circumstances, including if we fail to provide the minimum notification period before the Gomez field ceases production. We made no other performance guarantees to GE and the ultimate fees earned by ATP-IP beyond the minimum fees will be determined by the volumes of hydrocarbons processed through the facility. During the term of the PUA, we are responsible for all of the operating costs and periodic maintenance of theATP Innovator. ATP-IP pays us a monthly fee for certain administrative services we provide to the partnership. Additionally, we will share in partnership net income and regular minimum quarterly cash distributions in accordance with the provisions of the ATP-IP partnership agreement. Partnership cash in excess of monthly distributions and operating needs is transferred to an escrow account which is classified as restricted cash on the consolidated balance sheet.

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ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For financial reporting purposes, because we are the general partner of the partnership, we consolidate ATP-IP, along with three wholly owned limited liability companies (the “LLCs”) we created to own our interests in ATP-IP.

Capitalized Interest

Interest costs during the construction phase of certain long-term assets are capitalized and amortized over the related assets’ estimated useful lives. During 2010, 2009 and 2008, we capitalized $53.3, $110.1 million and $44.6 million, respectively, of interest costs to oil and gas properties. For the year ended December 31, 2010, capitalized interest was $40.4 million related to the construction of theATP Titan at our Telemark development in the Gulf of Mexico and $12.9 million related to the construction of theOctabuoy for our Cheviot property in the U.K. For the year ended December 31, 2009, capitalized interest was $102.2 million related to the construction of theATP Titan and $7.9 million related to theOctabuoy. For the year ended December 31, 2008, capitalized interest was $42.7 million related to the construction of theATP Titan and $1.9 million related to theOctabuoy.

Deferred Financing Costs

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

Environmental Liabilities

Environmental liabilities are recognized when the expenditures are considered probable and can be reasonably estimated. Measurement of liabilities is based on currently enacted laws and regulations, existing technology and undiscounted site-specific costs. Generally, such recognition would coincide with a commitment to a formal plan of action. We have no accruals for such liabilities at December 31, 2010 or 2009.

Revenue Recognition

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

Drilling Interruption Costs

Drilling interruption costs represent the costs we have incurred as a result of the deepwater drilling moratoriums and subsequent drilling permit delays caused by the April 2010 Macondo incident in the Gulf of Mexico. During 2010 a side-track well operation in 7,000 feet of water was interrupted when the moratorium was imposed and work on that project stopped, resulting in the early termination of a drilling contract. In the course of obtaining a full release from our obligations under the contract, we incurred net costs of $8.7 million. Additionally, because the necessary deepwater drilling permits were not issued, drilling interruption costs also include $14.9 million of stand-by costs related to drilling operations at our Telemark and Gomez Hubs.

Concentration of Credit Risk

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

Major Customers

Historically, we have sold our oil and natural gas production to a relatively small number of purchasers. We are not dependent upon, or confined to, any one purchaser or small group of purchasers. Due to the nature

F-11

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

of oil and natural gas markets and because oil and natural gas are commodities and there are numerous purchasers in the areas in which we sell production, we do not believe the loss of a single purchaser, or a few purchasers, would materially affect our ability to sell our production.

For the year ended December 31, 2010, revenues from four purchasers accounted for 65%, 12%, 11% and 5%, respectively, of oil and gas production revenues. For the year ended December 31, 2009, revenues from four purchasers accounted for 39%, 33%, 13% and 7%, respectively, of oil and gas production revenues. For the year ended December 31, 2008, revenues from four purchasers accounted for 32%, 32%, 17% and 10%, respectively, of oil and gas production revenues. A substantial portion of our oil and gas production revenues in the North Sea are from one customer.

Translation of Foreign Currencies

The local currency is the functional currency for our foreign subsidiaries, and as such, assets and liabilities are translated into U.S. dollars at year-end exchange rates. Income and expense items are translated at average exchange rates during the year. The gains or losses resulting from such translations are deferred and included in accumulated other comprehensive income as a separate component of shareholders’ equity. Gains and losses arising from transactions denominated in a currency other than the functional currency of a particular entity are included in net income. At December 31, 2010, accumulated other comprehensive loss consisted of $101.0 million of loss related to cumulative foreign currency translation adjustments.

Insurance Recoveries

When realized, insurance recoveries under our loss of production income policy are reported as other revenues in the consolidated statements of operations and in cash flows from operating activities in the consolidated statements of cash flows. During 2010, 2009 and 2008, insurance recoveries were $0, $13.7 million and $33.2 million, respectively, and were related to disruptions caused by Hurricane Ike in 2008.

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 for 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. A valuation allowance is recorded to reduce deferred tax assets to an amount that management believes is more likely than not to be realized in future years.

Stock-based Compensation

We recognize stock-based compensation expense as vesting of the stock award occurs. Generally, restricted stock awards vest over three years and common stock option awards vest evenly over four years.

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 fair value of the long-term debt as of December 31, 2010 was approximately $1.8 billion.

Derivative Instruments

We utilize derivative instruments and fixed-price forward sales contracts with respect to a portion of our expected production in order to manage our exposure to oil and natural gas price volatility. These instruments expose us to risk of financial loss if:

• production is less than expected for forward sales contracts;

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

• there is an adverse change in the expected differential between the underlying price in the derivative instrument and the actual prices received for our production at the physical sales point.

F-12

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Our results of operations may be negatively impacted in the future by our derivative instruments and fixed-price forward sales contracts as these instruments may limit any benefit we would otherwise receive from increases in the prices for oil and natural gas.

We primarily utilize fixed-price physical forward contracts, price swaps, price collars and put options which are generally placed with major financial institutions or with counterparties of high credit quality in order to minimize our credit risks. The oil and natural gas reference prices of these commodity derivative contracts are based upon oil and natural gas market exchanges which have a high degree of historical correlation with the actual prices we receive. All derivative instruments are recorded on the balance sheet at fair value with changes in fair value recorded as a component of derivative income (expense) in our consolidated statement of operations. Settlements of commodity derivative instruments are included in cash flows from operating activities in our consolidated statement of cash flows.

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

Recently Issued Accounting Pronouncements

Effective January 2010, the Company adopted the applicable provisions of FASB ASU No. 2010-06, “Improving Disclosures about Fair Value Measurements,” which amends ASC 820-10-50 to require new disclosures concerning (1) transfers into and out of Levels 1 and 2 of the fair value measurement hierarchy, and (2) activity in Level 3 measurements. In addition, ASU No. 2010-06 clarifies certain existing disclosure requirements regarding the level of disaggregation and inputs and valuation techniques and makes conforming amendments to the guidance on employers’ disclosures about postretirement benefit plans assets. The requirements to disclose separately purchases, sales, issuances, and settlements in the Level 3 reconciliation are effective for fiscal years beginning after December 15, 2010 (and for interim periods within such years). Accordingly, we will apply the disclosure requirements relative to the Level 3 reconciliation in the first quarter of 2011. There was no impact on our financial position, results of operations or cash flows as a result of the adoption of this standard.

Effective April 2010, the Company adopted the provisions of FASB ASU No. 2010-14, “Accounting for Extractive Activities – Oil & Gas,” which amends ASC 932-10-S99-1 to provide definitions of some of the terms used in the standard. There was no impact on our financial position, results of operations or cash flows as a result of the adoption of this standard.

Note 3 — Risks and Uncertainties

Our 2011 development plans in the Gulf of Mexico, as well as our longer term business plan, are dependent on receiving approval for deepwater drilling and other permits submitted to the Bureau of Ocean Energy Management, Regulation and Enforcement of the Department of the Interior (“BOEM”), successor to the Minerals Managements Service. While we believe we can satisfy the permitting requirements for our planned 2011 development wells which will allow us to significantly increase our production from current levels, there is no assurance that they will be received in time to benefit our 2011 results or that permits will be issued in the future. Should the permitting process in the Gulf of Mexico continue to be delayed, we believe we can continue to meet our existing obligations for at least the next twelve months; however, absent alternative funding sources, our ability to do so is dependent on maintaining existing production levels from our currently producing wells and maintaining commodity prices and operating costs near current levels. The size of our operations and our capital expenditures budget limit the number of properties that we can develop in any given year and a substantial portion of our current production is concentrated among relatively few wells located offshore in the Gulf of Mexico and in the North Sea, which are characterized by rapid production declines. As a result, we are particularly vulnerable to a near term severe impact resulting from unanticipated complications in the development of, or production from, any single material well or infrastructure installation, including lack of sufficient capital, delays in receiving necessary drilling and operating permits, increased regulation, reduced access to equipment and services, mechanical or operational failures, and bad weather. Any unanticipated significant disruption to, or decline in, our current production levels or negative changes in current commodity prices or operating cost levels could have a material adverse effect on our financial position, results of operations and cash flows and our ability to meet our commitments as they come due. We

F-13

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

have historically obtained various other sources of funding to supplement our cash flow from operations and we will continue to pursue them in the future, however, there is no assurance that these alternative sources will be available should these risks and uncertainties materialize.

We have incurred substantial costs in 2010 caused by the deepwater drilling moratoriums and subsequent drilling permit delays and some of these costs are continuing into 2011 and are expected to continue until permits are issued. In addition, we cannot predict how federal and state authorities will further respond to the Macondo incident in the Gulf of Mexico or whether additional changes in laws and regulations governing oil and gas operations in the Gulf of Mexico will result. New regulations already issued will, and potential future regulations or additional statutory limitations, if enacted or issued, could, require a change in the way we conduct our business, increase our costs of doing business or ultimately prohibit us from drilling for or producing hydrocarbons in the Gulf of Mexico. We cannot predict if or how the governments of other countries in which we operate will respond to the accident in the Gulf of Mexico.

We have financed a significant portion of our development program with transactions entered into with our suppliers and financial institutions that either defer payments to future years or will be repaid based on production throughput or from the revenues or net profits generated from future production. While these financing transactions have enabled us to continue the development of our properties and preserve cash, they will significantly burden the future net cash flows from our production until these obligations are satisfied (See Note 7 for further details).

As an independent oil and gas producer, our revenue, profitability, cash flows, and future rate of growth are substantially dependent on prevailing prices for oil and natural gas. Historically, the energy markets have been very volatile, and we expect such price volatility to continue. Any extended decline in oil or gas prices could have a material adverse effect on our financial position, results of operations, cash flows, the quantities of oil and gas reserves that we can economically produce, and may restrict our ability to obtain additional financing or to meet the contractual requirements of our debt and other obligations.

In addition, our estimates of proved oil and natural gas reserves and the estimated future net revenues from such reserves are based upon various assumptions, including assumptions relating to oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The estimation process requires significant 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. Estimates of our oil and natural gas reserves and the costs and timing associated with developing these reserves are subject to change, and may differ materially from the quantities of oil and natural gas that we ultimately produce. As of December 31, 2010, approximately 81% of our total proved reserves were undeveloped. We intend to continue to develop these reserves through the end of the year and beyond, but there can be no assurance we will be successful, particularly if permitting delays continue to negatively impact our liquidity and limit the amount of capital available for us to invest in our development plan. Development of these reserves may not yield the expected results, or the development may be delayed or the costs may exceed our estimates, any of which may materially affect our financial position, results of operations, cash flows and our ability to meet the requirements of our financing obligations.

F-14

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 4 — Supplemental Disclosures of Cash Flow Information

Supplemental disclosures of cash flow information (in thousands):

	Year Ended December 31,
	2010			2009			2008
Cash paid during the year for interest, net of amounts capitalized	$	192,697		$	16,536		$	88,429
Cash paid (received) during the year for income taxes		—			(13,581	)		6,282
Noncash investing and financing activities:
Increase (decrease) in noncash property additions		86,491			187,880			(56,577	)
Accrued distributions to noncontrolling interest		—			3,563			—
Accrued preferred stock dividends		(28	)		2,856			—

Note 5 — Oil and Gas Properties

Acquisitions

During May and June 2010, the BOEM, awarded us leases for 100% of the working interests in the Garden Banks Block 782 (“Entrada”) and the Ship Shoal (“SS”) Block 361, respectively. SS Block 361 is in close proximity to our SS Block 358 Hub. Entrada is in the vicinity of existing infrastructure owned by others. We paid $0.4 million for these leases.

During January 2010, we acquired a 100% working interest in MC Block 710, an exploratory prospect adjacent to our Gomez Hub in MC Block 711 and surrounding blocks, in exchange for the conveyance of an overriding royalty interest in this block.

During June 2009, we paid $0.2 million to acquire a 55.3% working interest in Green Canyon Block 344, a lease with unproved reserves south of our Green Canyon Block 300 property in the Gulf of Mexico. Also, in exchange for assumption of any property abandonment obligations and payment to us of $4.8 million, we acquired a partner’s working interests in certain properties in the Gulf of Mexico. In the U.K. North Sea, we participated in the 25th licensing round and were awarded a 50% equity interest in Block 9/21a, a property known as “Skipper,” for no upfront investment.

Exchange of Properties

During January 2010, we consummated a nonmonetary exchange of our 10% nonoperated working interest in Mississippi Canyon (“MC”) Block 800, for an incremental 50% working interest in MC Block 754, both proved undeveloped properties. Our consolidated financial statements reflect the incremental interest acquired in MC Block 754 at fair value and removal of the carrying costs of MC Block 800, resulting in recognition of a $12.0 million gain.

Dispositions

In July 2010, we sold to a third party our 67% working interest in the deep operating rights of one of our Gulf of Mexico properties resulting in a $15.0 million gain.

In December 2009, we sold to a third party our 25% working interest in the deep operating rights of one of our Gulf of Mexico properties resulting in a $13.0 million gain.

F-15

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 6 — Long-term Debt

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

	December 31,
	2010			2009
First lien term loans, net of $2,644 unamortized discount	$	146,607		$	—
Senior second lien notes, net of $6,071 unamortized discount		1,493,929			—
Term loan facility –ATP Titanassets, net of $10,760 unamortized discount		238,873			—
Term Loans, net of $28,266 unamortized discount		—			1,216,685
Total debt		1,879,409			1,216,685
Less current maturities		(21,625	)		(16,838	)
Total long-term debt	$	1,857,784		$	1,199,847

In April 2010, we entered into a first lien revolving credit facility (the “Original Credit Facility”) with an initial borrowing base of $100.0 million, due April 23, 2013, and issued senior second lien notes (the “Notes”) in an aggregate principal amount of $1.5 billion, due May 1, 2015. We used proceeds from the Notes to repay the entire amount due under our term loans previously outstanding and subsequently replaced the Original Credit Facility with the New Credit Facility, discussed below.

The Notes bear interest at an annual rate of 11.875%, payable each May 1 and November 1, and contain restrictions that, among other things, limit the incurrence of additional indebtedness, mergers and consolidations, and certain restricted payments. The Notes were issued at 99.531% of their face amount to yield 12.0% and we incurred issuance costs of $38.2 million.

At any time (which may be more than once), on or prior to May 1, 2013, the Company may, at its option, redeem up to 35% of the outstanding Notes with money raised in certain equity offerings, at a redemption price of 111.9%, plus accrued interest, if any. In addition, the Company may redeem the Notes, in whole or in part, at any time before May 1, 2013 at a redemption price equal to par plus an applicable make-whole premium plus accrued and unpaid interest to the date of redemption. The Company may also redeem any of the Notes at any time on or after May 1, 2013, in whole or in part, at specified redemption prices, plus accrued and unpaid interest to the date of redemption.

The Notes also contain a provision allowing the holders thereof to require the Company to purchase some or all of those Notes at a purchase price equal to 101% of their aggregate principal amount, plus accrued and unpaid interest to the date of repurchase, upon the occurrence of specified change of control events.

In June 2010, we entered into a new first lien credit agreement (the “New Credit Facility”) with an initial balance of $150.0 million, due October 15, 2014, to replace the Original Credit Facility. Proceeds of the New Credit Facility were $144.3 million, net of original issue discount and transaction fees. Principal outstanding under the term loans issued pursuant to the New Credit Facility bears interest at an annual rate of 11.0%. As security for the Company’s obligations under the New Credit Facility, the Company granted the lenders a security interest in and a first lien on not less than 80% of its proved oil and gas reserves in the Gulf of Mexico, capital stock of material subsidiaries (limited in the case of the Company’s non-U.S. subsidiaries to not more than 65% of the capital stock) and certain infrastructure assets, a portion of which has since been released in connection with the ATP Titan LLC financing discussed below. Principal of $750,000 is due each June and December beginning December 18, 2010 until June 18, 2014. The remaining principal balance is due October 15, 2014. The New Credit Facility allows the Company to incur up to $350.0 million of additional indebtedness secured by our oil and gas properties as Adjusted Consolidated Net Tangible Assets (as defined in the New Credit Facility) increase. See also Note 16, “Subsequent Events.”

The Notes and New Credit Facility contain certain negative covenants which place limits on the Company’s ability to, among other things:

• incur additional indebtedness;

• pay dividends on the Company’s capital stock or purchase, repurchase, redeem, defease or retire the Company’s capital stock or subordinated indebtedness;

F-16

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

• make investments outside of our normal course of business;

• incur liens;

• create any consensual restriction on the ability of the Company’s restricted subsidiaries to pay dividends, make loans or transfer property to the Company;

• engage in transactions with affiliates;

• sell assets; and

• consolidate, merge or transfer assets.

In September 2010, we formed ATP Titan LLC (“Titan LLC”), a wholly owned and operated subsidiary which we consolidate in our financial statements, and transferred to it our 100% ownership of theATP Titan platform and related infrastructure assets. Simultaneous with the transfer, Titan LLC entered into a $350.0 million term loan facility (the “ATP TitanFacility”), of which $250.0 million has been drawn for which we received proceeds of $228.8 million, net of discount and direct issuance costs. There are provisions in theATP Titan Facility under which the undrawn balance may be funded upon our request and subject to lender approval based on first production from the third and fourth wells ($50.0 million each) at our Telemark Hub. See also Note 16 “Subsequent Events.” Based on the outstanding balance at December 31, 2010, theATP Titan Facility is to be repaid as follows (in millions): 2011 – $20.1; 2012 – $22.6; 2013 to 2016 – $25.0 per year and 2017 – $106.9. TheATP Titan Facility bears interest at LIBOR (floor of 0.75%) plus 8%. TheATP Titan Facility requires us to maintain in a restricted account a minimum $10.0 million cash balance plus additional amounts based on production at the Telemark Hub to be used for the quarterly debt service of theATP Titan Facility. TheATP TitanFacility is secured solely by theATP Titan and related infrastructure assets (net book value at December 31, 2010 of $1,163.7 million) and the outstanding member interests in Titan LLC, which are all owned indirectly by the Company. TheATP Titan Facility includes a customary condition that there has not occurred a material adverse change with respect to the Company. The Company remains operator and 100% owner of theATP Titan platform, related infrastructure assets and the working interest in its Telemark Hub oil and gas reserves.

The New Credit Facility and the Notes contain customary events of default, and if certain of those events of default were to occur and remain uncured, such as a failure to pay principal or interest when due, our lenders could terminate future lending commitments under the New Credit Facility, and our lenders could declare the outstanding borrowings due and payable. The New Credit Facility also contains an event of default if there has occurred a material adverse change with respect to the Company’s compliance with environmental requirements and applicable laws and regulations. TheATP Titan Facility contains standard events of default and an event of default if there has occurred a material adverse change with respect to the Company. TheATP Titan Facility also contains provisions that provide for cross defaults among the documents entered into in connection with theATP Titan Facility and acceleration of Titan LLC’s payment obligations under theATP Titan Facility in certain situations. In addition, our hedging arrangements contain standard events of default, including cross default provisions, that, upon a default, provide for (i) the delivery of additional collateral, (ii) the termination and acceleration of the hedge, (iii) the suspension of the lenders’ obligations under the hedging arrangement or (iv) the setoff of payment obligations owed between the parties.

The effective annual interest rate of our long-term debt was 12.2% at December 31, 2010. The fair value of the aggregate long-term debt as of December 31, 2010 was approximately $1.8 billion.

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ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 7 — Other Long-term Obligations

Other long-term obligations consisted of the following (in thousands):

	December 31,
	2010			2009
Net profits interests	$	331,776		$	180,818
Dollar-denominated overriding royalty interests		52,825			14,941
Gomez pipeline obligation		73,868			75,152
Vendor deferrals – Gulf of Mexico		7,096			7,490
Vendor deferrals – North Sea		90,874			17,053
Other		2,582			2,582
Total		559,021			298,036
Less current maturities		(86,521	)		(23,094	)
Other long-term obligations	$	472,500		$	274,942

Net Profits Interests

During 2009 and 2010, we granted dollar-denominated overriding royalty interests in the form of net profits interests (“NPIs”) in certain of our proved oil and gas properties in and around the Telemark Hub, Gomez Hub and Clipper to certain of our vendors in exchange for oil and gas property development services. The interests earned by the vendors are paid solely from the net profits, as defined, of the subject properties. As the net profits increase or decrease, primarily through higher or lower production levels and higher or lower prices of oil and natural gas, the payments due the holders of the net profits interests increase or decrease accordingly. If there is no production from a property or if the net profits are negative during a payment period, there is no payment required. We also accrete the liability over the estimated term in which the NPI is expected to be settled using the effective interest method with related interest expense presented net of amounts capitalized on the Consolidated Statement of Operations. The term of the NPIs will be dependent on the value of the services contributed by these vendors coupled with the timing of production and future economic conditions, including commodity prices and operating costs. Because NPIs were granted on proved properties where production is reasonably assured, we have accounted for these NPI’s as financing obligations on our Consolidated Balance Sheet. As such, the reserves and production revenues associated with the NPIs are retained by the Company. We expect approximately 75% of the NPIs to be repaid over the next 24 months based on projected production, commodity prices and operating costs.

During November 2010, a NPI originally granted during 2009 in exchange for vendor services was acquired by an investor, who repaid the vendor $39.2 million outstanding under the original NPI, extended the payout term of the NPI, and increased the size of the obligation to $100.0 million. The proceeds of the transaction were $60.3 million, net of transaction costs, and we recognized a gain on debt extinguishment of $2.9 million.

Dollar-denominated Overriding Royalty Interests

In October 2009, we sold a dollar-denominated overriding royalty interest (“Override”) in our Gomez Hub properties for $14.5 million, net of costs. During 2010, we sold Overrides (primarily dollar-denominated) in future production from the Gomez Hub properties for $140.0 million ($121.1 million net of transaction costs and fourth quarter 2009 royalty payments). These Overrides obligate us to deliver proceeds from the future sale of hydrocarbons in the specified proved properties equal to the purchasers’ original investments, plus an overall rate of return. As the proceeds from the sale of hydrocarbons increase or decrease, primarily through changes in production levels and oil and natural gas prices, the payments due the holders of the overriding royalty interests will increase or decrease accordingly. If there is no production from a property during a payment period, there is no payment required. The percentage of property revenues available to satisfy these obligations is dependent upon certain conditions specified in the agreement. Upon payment of the agreed dollar amounts, the ownership of the Overrides reverts to us. Because of the explicit rate of return, dollar-denomination and limited payment terms of the Overrides, they are reflected in the accompanying financial statements as financing obligations. As such, the reserves and production revenues are retained by the

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ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Company. Related interest expense is presented net of amounts capitalized on the Consolidated Statements of Operations. We expect the Overrides to be repaid over the next 12 months based on projected production and commodity prices.

Gomez Pipeline Obligation

In 2009, we executed an asset purchase and sale agreement for net proceeds of $74.5 million pursuant to which the Company sold to a third party the oil and natural gas pipelines that service the Gomez Hub at MC Block 711. In conjunction with the sale, we entered into agreements with the third party to transport our oil and natural gas production for the remaining production life of our fields serviced by theATP Innovator for a per-unit fee that is subject to a minimum monthly payment through December 31, 2016. Such minimum fees, if applicable, can be recovered by ATP in future periods within the same calendar year whenever fees owed during a month exceed the minimum due. We remain the operator of the pipeline and are responsible for all of the related operating costs. As a result of the retained asset retirement obligation and the purchaser’s option to convey the pipeline back to us at the end of the life of the fields in the Gomez Hub, the transaction has been accounted for as a financing obligation equal to the net proceeds received. This obligation is being amortized based on the estimated proved reserve life of the Gomez properties using the effective interest method with related interest expense presented net of amounts capitalized, on the Consolidated Statements of Operations. All payments made in excess of the minimum fee in future periods will be reflected as interest expense of the financing obligation.

Vendor Deferrals

In the Gulf of Mexico, in addition to the NPIs exchanged for development services described above, we have negotiated with certain other vendors involved in the development of the Telemark and Gomez Hubs to partially defer payments over a twelve-month period beginning with first production. We accrue the present value of the deferred payments and accrete the balance over the estimated term in which it is expected to be paid using the effective interest method with related interest expense presented net of amounts capitalized, on the Consolidated Statements of Operations.

In the U.K. North Sea, development of our interest in the Cheviot field continues. We have arranged with the fabricator of the floating production facility to defer $121.5 million of committed expenditures: $54.5 million to be paid in 2011 and $67.0 million to be paid in 2012. As work is completed, we record obligations and related interest expense, net of amounts capitalized, on the Consolidated Statements of Operations.

The weighted average effective interest rate on our other long-term obligations was 16.7% at December 31, 2010.

Note 8 — Equity

Preferred Stock

During 2009, we issued 1.4 million shares of convertible preferred stock and received net proceeds of $135.5 million ($100 per share before underwriters’ discounts and commissions and offering expenses). Each share of convertible preferred stock is perpetual, has no voting rights, has a liquidation preference of $100, pays cumulative dividends at an annual rate of 8% and is convertible at any time, at the option of the holder, into 4.5045 shares of common stock. After September 30, 2014, we have the option to force conversion to common stock provided that the prevailing common stock market price exceeds the conversion price by 150% on average for a stipulated period of time. In the event of certain fundamental changes of the Company, each share of convertible preferred stock is subject to adjustment to prevent dilution and would receive a conversion benefit as defined in the related statement of resolutions that established the convertible preferred stock. In December 2010, we announced a quarterly cash dividend of $2.8 million ($2.02 per share of preferred stock) which was paid in January 2011.

Common Stock

During 2009, we issued 14.6 million shares of common stock and received net proceeds of $170.6 million (an average of $12.31 per share before underwriters’ discounts and commissions and offering expenses).

F-19

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Rights Plan

On October 1, 2005, the Board of Directors of ATP authorized the issuance of one preferred share purchase right (a “Right”) with respect to each outstanding share of common stock, par value $0.001 per share (the “Common Shares”), of the Company (the “Shareholder Rights Plan”). The Rights were issued on October 17, 2005 to the holders of record of Common Shares on that date. Each Right entitles the registered holder to purchase from the Company one one-hundredth (1/100) of a share of Junior Participating Preferred Stock, par value $0.001 per share (the “Preferred Shares”), of the Company at a price of $150 per one one-hundredth of a Preferred Share, subject to adjustment. The description and terms of the Rights are set forth in a Rights Agreement dated as of October 11, 2005 between the Company and American Stock Transfer & Trust Company, as Rights Agent.

Note 9 — Stock-Based and Other Compensation Plans

In January 2001, the Board of Directors approved the 2000 Stock Plan (the “2000 Plan”) and in June 2010 the Shareholders approved the 2010 Stock Plan (the “2010 Plan”) to provide increased incentive for the Company’s employees and directors. The 2000 Plan authorizes the granting of options and restricted stock awards for up to 4,000,000 shares of common stock, and expired in February 2011. The 2010 Plan authorizes the granting of options, restricted stock awards, restricted stock bonus awards and performance share bonus awards for up to an aggregate 6,000,000 shares of common stock. Generally, options are granted at prices equal to at least 100% of the fair value of the stock at the date of grant, expire not later than five years from the date of grant and vest ratably over a four-year period following the date of grant. From time to time, as approved by the Board of Directors, options with differing terms have also been granted. We recognized stock option compensation expense of $2.5 million, $3.0 million and $2.6 million for the years ended December 31, 2010, 2009 and 2008, respectively.

The fair values of options granted during the years ended December 31, 2010, 2009 and 2008 were estimated at the date of grant using a Black-Scholes option-pricing model assuming no dividends and with the following weighted average assumptions for grants during the periods indicated:

	Year Ended December 31,
	2010			2009			2008
Weighted average volatility		84	%		76	%		53	%
Expected term (in years)		3.8			3.8			3.8
Risk-free rate		1.0	%		1.7	%		2.2	%
Weighted average fair value of options – grant date	$	5.53		$	8.81		$	6.31

Volatilities are based on the historical volatility of our closing common stock price. Expected term of options granted represents the period of time that options granted are expected to be outstanding. The expected term of the options granted in 2010, 2009 and 2008 is estimated using the simplified method because the option terms are homogeneous and the Company has insufficient option exercise history to refine its expectations. The risk-free rate for periods within the contractual life of the options is based on the comparable U.S. Treasury rates in effect at the time of each grant. The aggregate intrinsic values of options exercised during the years ended December 31, 2010, 2009 and 2008 were $0.4, $0 million and $0.1 million, respectively. The following table sets forth a summary of option transactions for the year ended December 31, 2010:

F-20

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

	Number of Options			Weighted Average Grant Price		Aggregate Intrinsic Value (1) ($000)		Weighted Average Remaining Contractual Life
								(in years)
Outstanding at beginning of year		1,634,105		$	24.69
Granted		297,250			9.47
Exercised		(70,522	)		15.17
Forfeited		(77,078	)		18.51
Expired		(262,464	)		19.79
Outstanding at end of year		1,521,291			23.31	$	5,344		2.8
Vested and expected to vest		1,325,449			23.53	$	4,579		2.7
Options exercisable at end of year		587,319			35.68	$	608		1.6

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

A summary of the status of ATP’s nonvested stock options as of December 31, 2010 and changes during the year is presented below:

	Number of Options			Weighted Average Grant-date Fair Value
Nonvested at beginning of year		978,103		$	8.15
Granted		297,250			5.53
Vested		(270,948	)		9.49
Forfeited		(70,433	)		7.41
Nonvested at end of year		933,972			6.98

At December 31, 2010, unrecognized compensation expense related to nonvested stock option grants totaled $2.7 million. Such unrecognized expense will be recognized as vesting occurs over a weighted average period of 2.6 years.

Restricted stock grants vest over a three-year period, are subject to forfeiture, and cannot be sold, transferred or disposed of during the restriction period. The holders of the shares have voting and dividend rights with respect to such shares. During the years ended December 31, 2010, 2009 and 2008, we recognized aggregate compensation expense of $4.3 million, $4.9 million and $8.9 million, respectively, related to outstanding restricted stock grants.

The following table sets forth the changes in nonvested restricted stock for the year ended December 31, 2010:

	Number of Shares			Weighted Average Grant-date Fair Value		Aggregate Intrinsic Value (1) ($000)
Nonvested at beginning of year		419,293		$	26.25
Granted		179,179			13.85
Forfeited		(8,181	)		16.93
Vested		(167,654	)		29.82
Nonvested at end of year		422,637			19.76	$	7,075

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

F-21

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

At December 31, 2010, unrecognized compensation expense related to restricted stock totaled $1.8 million. Such unrecognized expense will be recognized as vesting occurs over a weighted average period of 1.5 years.

We have a 401(k) Savings Plan which covers all domestic employees. At our discretion, we may match a certain percentage of the employees’ contributions to the plan. The matching percentage is currently 100% of the first 3% and 50% of the next 2% of each participant’s compensation. Our matching contributions to the plan were approximately $299,000, $289,000 and $211,000 for the years ended December 31, 2010, 2009 and 2008, respectively.

We also have a defined contribution plan for our U.K. employees. We currently contribute 4% to the plan and such contributions are subject to the Pensions Act 1999 (U.K.) and to U.K. rules on taxation. For the years ended December 31, 2010, 2009 and 2008, we contributed approximately $23,000, $33,000 and $32,000, respectively.

Note 10 — Earnings Per Share

Basic earnings per share (“EPS”) is computed by dividing net income or loss attributable to common shareholders by the weighted average number of common shares (other than nonvested restricted stock) outstanding during the period. Weighted average shares outstanding for diluted EPS also includes a hypothetical number of additional shares (“Common Stock Equivalents”) calculated assuming the exercise or conversion of all in-the-money options, warrants and convertible preferred stock and full vesting of restricted stock awards. Common Stock Equivalents are excluded from the computation of weighted average common shares outstanding when the per share effect is antidilutive. The impact of assumed conversion of preferred stock on net income attributable to common shareholders is excluded from the computation of EPS when its impact is antidilutive. For 2010, 2009 and 2008, 0.5 million, 1.4 million and 0.5 million, respectively, Common Stock Equivalents were excluded from the diluted EPS calculation in the table below because their inclusion would have been antidilutive. For 2010 and 2009, preferred stock dividends of $11.2 million and $2.9 million, respectively, were excluded from the diluted EPS computation of net loss attributable to common shareholders because their inclusion would have been antidilutive. Also for 2010 and 2009, a total of 6.3 million and 1.6 million, respectively, potential shares from the assumed conversion of preferred stock have been excluded because their effect would have been antidilutive.

Basic and diluted EPS are computed based on the following information (in thousands, except per share amounts):

	Year Ended December 31,
	2010			2009			2008
Income
Net income (loss) attributable to common shareholders	$	(348,797	)	$	(51,817	)	$	121,705
Add impact of assumed preferred stock conversions (if-converted method)		—			—			—
Net income (loss) attributable to common shareholders and impact of assumed conversions	$	(348,797	)	$	(51,817	)	$	121,705
Shares outstanding
Weighted average shares outstanding - basic		50,715			41,853			35,457
Effect of potentially dilutive securities:
Stock options and warrants		—			—			253
Nonvested restricted stock		—			—			158
Preferred stock		—			—			—
Weighted average shares outstanding - diluted		50,715			41,853			35,868
Net income (loss) per share attributable to common shareholders:
Basic	$	(6.88	)	$	(1.24	)	$	3.43
Diluted	$	(6.88	)	$	(1.24	)	$	3.39

F-22

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 11 — Income Taxes

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

	Year Ended December 31,
	2010			2009			2008
Current:
Domestic	$	924		$	(924	)	$	(1,326	)
Foreign		(65	)		379			(643	)
		859			(545	)		(1,969	)
Deferred:
Domestic		117,459			19,809			(42,184	)
Foreign		12,790			4,570			(5,820	)
		130,249			24,379			(48,004	)
Valuation allowance		(94,835	)		(1,300	)		—
Total income tax (expense) benefit	$	36,273		$	22,534		$	(49,973	)

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

	Year Ended December 31,
	2010			2009			2008
Domestic	$	(329,497	)	$	(46,860	)	$	105,793
Foreign		(28,822	)		(11,255	)		65,885
	$	(358,319	)	$	(58,115	)	$	171,678

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

	Year Ended December 31,
	2010			2009			2008
Statutory federal income tax rate		35.00	%		35.00	%		35.00	%
Nondeductible and other		(0.80	)		(3.63	)		1.77
Foreign operations		0.88			1.52			(7.65	)
Impact of redeemable noncontrolling interest		1.51			8.06			—
Valuation allowance		(26.47	)		(2.18	)		—
		10.12	%		38.77	%		29.12	%

Significant components of our deferred tax assets (liabilities) as of December 31, 2010 and 2009 are as follows (in thousands):

	December 31, 2010
	U.S.			Foreign			Total
Deferred tax asset:
Net operating loss carry forwards	$	215,174		$	178,882		$	394,056
Unrealized derivative loss		13,356			—			13,356
Alternative minimum tax credit		1,840			—			1,840
Stock-based compensation		5,064			211			5,275
Asset retirement obligation		10,918			—			10,918
Other		572			—			572
Valuation allowance		(97,385	)		(1,676	)		(99,061	)
Deferred tax asset		149,539			177,417			326,956
Deferred tax liability:
Oil and gas property basis differences		(143,431	)		(186,182	)		(329,613	)
Other		(6,108	)	��	—			(6,108	)
Deferred tax liability		(149,539	)		(186,182	)		(335,721	)
Net deferred tax liability		—			(8,765	)		(8,765	)
Less net current deferred tax asset		(8,191	)		—			(8,191	)
Noncurrent deferred tax liability	$	(8,191	)	$	(8,765	)	$	(16,956	)

F-23

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

	December 31, 2009
	U.S.			Foreign			Total
Deferred tax asset:
Net operating loss carry forwards	$	93,263		$	116,150		$	209,413
Unrealized derivative loss		8,056			—			8,056
Alternative minimum tax credit		2,764			—			2,764
Stock-based compensation		5,048			—			5,048
Asset retirement obligation		9,228			—			9,228
Other		2,102			—			2,102
Valuation allowance		(3,025	)		(1,300	)		(4,325	)
Deferred tax asset		117,436			114,850			232,286
Deferred tax liability:
Oil and gas property basis differences		(139,692	)		(136,559	)		(276,251	)
Other		(843	)		—			(843	)
Deferred tax liability		(140,535	)		(136,559	)		(277,094	)
Net deferred tax liability		(23,099	)		(21,709	)		(44,808	)
Less net current deferred tax asset		(101,956	)		—			(101,956	)
Noncurrent deferred tax liability	$	(125,055	)	$	(21,709	)	$	(146,764	)

We compute income taxes using an asset and liability approach which results in the recognition of deferred tax liabilities and assets for the expected future tax consequences of temporary differences between the carrying amounts and the tax basis of those assets and liabilities. As of December 31, 2010 and 2009, for U.S. tax provision purposes, we have provided valuation allowance for that portion of excess tax benefits resulting from stock options and restricted stock outstanding as of the date we adopted the accounting standards for stock-based compensation. As of December 31, 2010, for U.S. tax provision purposes, we have also provided valuation allowance for the remainder of our net deferred tax assets based on our cumulative net losses coupled with the increased uncertainties surrounding our future earnings forecasts arising from the continued permitting delays in the Gulf of Mexico. Additionally, the deferred tax asset related to the U.S. net operating loss carry forwards (“NOLs”) as disclosed does not include an additional $19.5 million of net operating loss, as we included this amount in our 2008 U.S. Income Tax Return and net operating loss carry forwards in relation to excess tax benefits on stock option exercises and restricted stock vested through the fiscal year ended December 31, 2008.

At December 31, 2010 and 2009, we had U.S. net operating loss carry forwards (“NOLs”) for financial statement purposes of approximately $614.8 million and $266.5 million, respectively, which begin to expire in 2024. ATP (UK) had NOLs of $678.5 million and $432.0 million available for corporate tax carry-forward at December 31, 2010 and 2009, respectively, which are presented in Foreign Operations above. As of December 31, 2010 we have a net current deferred tax asset of approximately $8.1 million, which is primarily attributable to bad debt reserve and unrealized hedging losses.

No tax expense is provided on the income attributable to the redeemable noncontrolling interest in ATP Infrastructure Partners, LP, as the partnership is a pass-through entity and is not subject to federal income taxes. Taxes attributable to the income of the redeemable noncontrolling interest would be the liability of the ultimate taxpayers owning that interest.

The Company and its subsidiaries file income tax returns in the United States federal jurisdiction, two states, the U.K. and the Netherlands. Our open tax years in our major jurisdictions are from 2002 to current. As of December 31, 2010, we are not aware of any uncertain tax positions requiring adjustments to our tax liability. If applicable, we will record to the income tax provision any interest and penalties related to unrecognized tax positions.

F-24

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

U.S. deferred taxes have not been recognized with respect to foreign income of $35.1 million that is permanently reinvested internationally. We currently do not have any foreign tax credits available to reduce U.S. taxes on this income if it was repatriated.

Note 12 — Commitments and Contingencies

The development, production and sale of oil and natural gas in the Gulf of Mexico and in the North Sea are subject to extensive laws and regulations, including environmental laws and regulations. We may be required to make large expenditures to comply with environmental and other governmental regulations. 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 (see the discussion in Note 3, “Risks and Uncertainties”). Accordingly, any of these liabilities, penalties, suspensions, terminations or regulatory changes could materially adversely affect our financial condition and results of operations. We believe that we are in compliance with all of the laws and regulations which apply to our operations.

Under the provisions of our limited partnership agreement with ATP-IP, we could be required to repurchase the Class A limited partner interest if certain change of control events were to occur. If a change of control were to become probable in a future period, we would be required to adjust the carrying amount of the redeemable noncontrolling interest to its redemption amount, to the extent it differed from the carrying amount, at the time the change of control was deemed to be probable. We do not currently believe a change of control is probable.

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

In the normal course of business, we occasionally purchase oil and gas properties for little or no up-front costs and instead commit to pay consideration contingent upon the successful development and operation of the properties. The contingent consideration generally includes amounts to be paid upon achieving specified operational milestones, such as first commercial production and again upon achieving designated cumulative sales volumes. At December 31, 2010, the aggregate amount of such contingent commitments related to unmet operational milestones was $7.8 million. During 2010, we paid $2.4 million of additional consideration for two of our North Sea properties under a similar provision.

We maintain insurance to protect the Company and its subsidiaries against losses arising out of our oil and gas operations. Our insurance includes coverage for physical damage to our offshore properties, general (third party) liability, workers compensation and employers liability, seepage and pollution and other risks. Our insurance includes various limits and deductibles or retentions, which must be met prior to or in conjunction with recovery. Additionally, our insurance is subject to the terms, conditions and exclusions of such policies. For losses emanating from offshore operations, ATP has up to an aggregate of $2.1 billion of various insurance coverages with individual policy limits ranging from $1.0 million to over $500 million each. While we maintain insurance levels, deductibles and retentions that we believe are prudent and responsible, there is no assurance that such coverage will adequately protect us against liability from all potential consequences and damages.

In general, our current insurance policies cover physical damage to our oil and gas assets. The coverage is designed to repair or replace assets damaged by insurable events.

Our excess liability policies generally provide coverage (dependent on the asset) for bodily injury and property damage, including coverage for negative environmental effects such as seepage and pollution. This liability coverage would cover claims for bodily injury or death brought against the company by or on behalf

F-25

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

of individuals who are not employees of the company. The liability limits scale to either our operating interest or the total insured interest including nonoperating partners.

Our energy insurance package includes coverage for operator’s extra expense, which provides coverage for control of well, re-drill and pollution arising from a covered event. We maintain a $150 million Oil Spill Financial Responsibility policy in order to provide a Certificate of Financial Responsibility to the BOEM under the requirements of the Oil Pollution Act of 1990. Additionally, as noted above, our excess liability policies provide coverage (dependent on the asset) for bodily injury and property damage, including coverage for negative environmental effects such as seepage and pollution. Legislation has been proposed to increase the limit of the Oil Spill Financial Responsibility policy required for the certificate and there is no assurance that we will be able to obtain this insurance should that happen.

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

On January 29, 2010, Bison Capital Corporation (“Bison”) filed suit against ATP in the United States District Court for the Southern district of New York alleging ATP owed fees totaling $102 million to Bison under a February 2004 agreement. The case was tried in January 2011. On March 8, 2011 the Court entered a judgment in favor of Bison for $1.65 million plus prejudgment interest and Bison’s reasonable attorney’s fees. Either party may file a notice of appeal within 30 days of the judgment. ATP has provided for this judgment in the financial statements as of December 31, 2010.

We are, in the ordinary course of business, involved in various other legal proceedings from time to time. Management does not believe that the outcome of these proceedings as of December 31, 2010, either individually or in the aggregate, will have a material adverse effect on our financial condition, results of operations or cash flows.

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ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 13 — Derivative Instruments and Price Risk Management Activities

At December 31, 2010, we had the following derivative contracts in place:

						Net Fair Value Asset (Liability) (2)
Period	Type	Volumes		Price		Current			Noncurrent
				$/Unit (1)		($000)			($000)
Oil (Bbl) –Gulf of Mexico
2011	Swaps		2,124,500		81.99		(23,084	)		—
2012	Swaps		1,120,750		89.37		—			(4,236	)
2013	Swaps		90,000		90.40		—			(199	)
2011	Swaps (3)		911,000		78.41		(12,027	)		—
Total						$	(35,111	)	$	(4,435	)
Natural Gas (MMBtu)
North Sea
2011	Swaps		1,641,000		7.21		(2,782	)		—
2012	Swaps		1,464,000		8.20		—			(1,249	)
Gulf of Mexico
2011	Fixed-price physicals		5,025,000		4.78		1,030			—
2012	Fixed-price physicals		1,365,000		4.64		—			(741	)
2011	Collars		1,350,000		4.75-7.95		658			—
Total						$	(1,094	)	$	(1,990	)
Derivative asset						$	1,688		$	—
Derivative liability							(37,893	)		(6,425	)
Total						$	(36,205	)	$	(6,425	)

(1) Unit price for collars reflects the floor and the ceiling prices, respectively.

(2) None of the derivatives outstanding is designated as a hedge for accounting purposes.

(3) These swaps include call options to allow us to participate in per barrel price increases above $111.00.

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ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

At December 31, 2009, we had the following derivative contracts in place:

						Net Fair Value Asset (Liability) (2)
Period	Type	Volumes		Price		Current			Noncurrent
				$/Unit (1)		($000)			($000)
Oil (Bbl) –Gulf of Mexico
2010	Puts		365,000		24.70	$	2		$	—
2010	Swaps		733,000		79.76		(2,212	)		—
2011	Swaps		1,095,000		80.17		—			(5,625	)
2010	Swaps (3)		1,273,000		68.29		(13,402	)		—
2011	Swaps (3)		181,000		72.00		—			(1,508	)
Total						$	(15,612	)	$	(7,133	)
Natural Gas (MMBtu)
North Sea
2010	Fixed-price physicals		1,095,000		7.01	$	1,321		$	—
Gulf of Mexico
2010	Fixed-price physicals		4,525,000		5.58		(778	)		—
2010	Collars		4,575,000		4.68-7.86		173			—
2011	Collars		1,350,000		4.75-7.95		—			(512	)
Total						$	716		$	(512	)
Derivative asset						$	1,321		$	—
Derivative liability							(16,216	)		(7,646	)
Total						$	(14,895	)	$	(7,646	)

(1) Unit price for collars reflects the floor and the ceiling prices, respectively.

(2) None of the derivatives outstanding is designated as a hedge for accounting purposes.

(3) These swaps include call options to allow us to participate in per barrel price increases above $99.34 and $115.00 in 2010 and 2011, respectively.

There was no other comprehensive income related to hedges during 2010. The following AOCI table shows where gains and (losses), net of taxes, on cash flow hedge derivatives were reported in the year ended December 31, 2009 (in thousands):

AOCI for cash flow hedges – beginning of period	$	(2,877	)
Derivative gains		3,736
Gains reclassified from AOCI to oil and gas revenues		(859	)
AOCI for cash flow hedges – end of period	$	—

During the year ended December 31, 2010, we paid net cash settlements of $2.3 million related to our derivatives. Our derivative income (expense) is based entirely on nondesignated derivatives and consists of the following (in thousands):

	Year Ended December 31,
	2010			2009			2008
Realized gains (losses) from:
Settlements of contracts	$	(2,686	)	$	18,335		$	(6,701	)
Early terminations of contracts		—			19,226			83,923
Unrealized gains (losses) on open contracts		(19,733	)		(38,273	)		11,813
Derivative income (expense)	$	(22,419	)	$	(712	)	$	89,035

F-28

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 14 — Segment Information

The Company’s operations are focused in the Gulf of Mexico and in the North Sea. Management reviews and evaluates separately the operations of its Gulf of Mexico segment and its North Sea segment. The operations of both segments include natural gas and liquid hydrocarbon production and sales. The accounting policies of the reportable segments are the same as those described in Note 2 to the Consolidated Financial Statements. Segment activity for the years ended December 31, is as follows (in thousands):

	Gulf of Mexico			North Sea			Total
2010
Revenues	$	416,836		$	21,161		$	437,997
Depreciation, depletion and amortization		200,457			20,200			220,657
Impairment of oil and gas properties		48,392			14,875			63,267
Gain on exchange/disposal of properties		26,720			—			26,720
Loss from operations		16,071			23,105			39,176
Interest income		243			453			696
Interest expense, net		222,104			—			222,104
Derivative expense		16,253			6,166			22,419
Loss on debt extinguishment		75,316			—			75,316
Income tax benefit		24,023			12,250			36,273
Additions to oil and gas properties		570,393			139,890			710,283
Total assets		2,896,486			393,616			3,290,102
2009
Revenues	$	295,124		$	17,030		$	312,154
Depreciation, depletion and amortization		128,777			24,003			152,780
Impairment of oil and gas properties		45,799			—			45,799
Gain (loss) on disposal of properties		13,177			(744	)		12,433
Income (loss) from operations		3,825			(21,054	)		(17,229	)
Interest income		537			173			710
Interest expense, net		40,884			—			40,884
Derivative income (expense)		(9,834	)		9,122			(712	)
Income tax benefit		18,885			3,649			22,534
Additions to oil and gas properties		721,793			96,386			818,179
Total assets		2,545,876			257,271			2,803,147
2008
Revenues	$	521,463		$	96,566		$	618,029
Depreciation, depletion and amortization		152,246			94,188			246,434
Impairment of oil and gas properties		125,059			—			125,059
Gain on disposal of properties		160			119,073			119,233
Income from operations		113,254			90,862			204,116
Interest income		1,344			2,132			3,476
Interest expense, net		100,729			—			100,729
Derivative income (expense)		96,507			(7,472	)		89,035
Loss on debt extinguishment		24,220			—			24,220
Income tax expense		43,510			6,463			49,973
Additions to oil and gas properties		774,925			136,034			910,959
Total assets		1,954,302			321,308			2,275,610

F-29

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 15 — Fair Value Measurements

The accounting standards for fair value measurement and disclosure applies to all financial assets and financial liabilities that are being measured and reported on a fair value basis. Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). The standards establish a framework for measuring fair value and expands disclosure about fair value measurements. The standards require fair value measurements be classified and disclosed in one of the following categories:

Level 1:	Measured based on unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities.
Level 2:	Measured based on quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability. This category includes those derivative instruments that we value using observable market data. Substantially all of these inputs are observable in the marketplace throughout the full term of the derivative instrument, can be derived from observable data, or supported by observable levels at which transactions are executed in the marketplace.
Level 3:	Measured based on prices or valuation models that require inputs that are both significant to the fair value measurement and less observable from objective sources (i.e., supported by little or no market activity). Our option pricing models are industry-standard and consider various inputs including forward commodity price estimates, volatility and time value of money.

Financial assets and liabilities are classified based on the lowest level input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and determines the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels.

Assets and Liabilities Measured at Fair Value on a Recurring Basis

The fair values of our derivative contracts are classified as Level 3 based on the significant unobservable inputs into our expected present value models (see Note 13, “Derivative Instruments and Price Risk Management Activities”). The following table sets forth a reconciliation of changes in the fair value of these financial assets (liabilities) during the year ended December 31, 2010 (in thousands):

	U.S Gas Fixed-Price Physicals			U.S Gas Price Collars			U.S. Oil Swaps			U.S Oil Swaps(1)			U.K. Gas Swaps			Total
Balance at beginning of period	$	(778	)	$	(339	)	$	(7,837	)	$	(14,910	)	$	—		$	(23,864	)
Derivative income (expense)		9,161			3,727			(24,276	)		(4,090	)		(5,751	)		(21,229	)
Settlements and terminations		(8,094	)		(2,730	)		4,594			6,973			1,720			2,463
Balance at end of period	$	289		$	658		$	(27,519	)	$	(12,027	)	$	(4,031	)	$	(42,630	)
Changes in unrealized gain (loss) included in derivative income (expense) relating to derivatives still held at December 31, 2010	$	289		$	1,170		$	(21,892	)	$	(10,520	)	$	(4,031	)	$	(34,984	)

(1) These swaps have been matched with call options to allow us to reparticipate in price increases above certain levels.

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ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

Oil and gas properties are measured at fair value on a nonrecurring basis upon impairment and when acquired in a nonmonetary property exchange. During 2010, we recorded impairment expense of $63.3 million on proved and unproved properties and gain on nonmonetary property exchange of $12.0 million related to proved Gulf of Mexico properties. The impairment charges reduce the oil and gas properties’ carrying values to their estimated fair values and are classified as Level 3. Fair value is calculated as the estimated discounted future net cash flows attributable to the assets. The gain on nonmonetary property exchange reflects the difference between the carrying value of the property surrendered and the estimated fair value of the property received which is classified as Level 3 and which is calculated based on the estimated discounted future net cash flows attributable to that asset.

The Company’s primary assumptions in preparing the estimated discounted future net cash flows to be recovered from oil and gas properties are based on (i) proved reserves and risk-adjusted probable and possible reserves, (ii) commodity forward-curve prices and assumptions as to costs and expenses, and (iii) the estimated discount rate that would be used by potential market participants to determine the fair value of the assets.

Note 16 — Subsequent Events

Our evaluation has identified the following matters which require disclosure as events subsequent to December 31, 2010:

On February 19, 2011, we entered into Incremental Loan Assumption Agreement and Amendment No. 1 to the New Credit Facility (“The Amendment”). The Amendment provides for an increase to the principal amount of the New Credit Facility from $150 million to the lesser of $210 million or 10% of the Company’s Adjusted Consolidated Net Tangible Assets, as defined. The Amendment also reduces the interest rate of the New Credit Facility from 11% to 9% and extends the maturity date from October 15, 2014 to January 15, 2015. The other terms of the New Credit Facility are essentially unchanged by the Amendment.

We announced on February 24, 2011 our plans to expand our operations into the Mediterranean Sea off the coast of Israel. Subject to approval of the Israel Ministry of National Infrastructures, we have signed agreements to acquire five licenses, two of which are pending, in approximately 4,000 feet of water. We will operate all of the licenses with working interests ranging from 40% to 50%.

In January 2011, the Company entered into a $114.9 million agreement for the construction of topsides facilities for the Octabuoy floating production platform, which is under construction for deployment at our Cheviot property in the U.K. The agreement was entered into with the construction contractor of the hull and provided for payment of 25% of the contract cost at closing (January 2011) with the balance of the contract due upon completion of the topsides late in 2012. In February 2011, the company amended its Octabuoy hull construction contract to defer until 2012 an additional $25.2 million of payments that were previously scheduled to be paid in 2011.

In March 2011, the Company entered into an amendment of the Term loan facility –ATP Titan assets whereby the lender agreed to fund the $50.0 million draw related to the third well at Telemark prior to first production from that well which was required under the original terms of the agreement. ATP received net proceeds of $44.2 million after deducting original issue discount and transaction fees.

F-31

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 17 — Supplemental Quarterly Financial Information (Unaudited)

(In Thousands, Except Per Share Amounts)

	First Quarter			Second Quarter			Third Quarter			Fourth Quarter
2010
Revenues	$	93,029		$	101,099		$	102,121		$	141,748
Costs, expenses and other (1)		77,715			116,513			91,773			192,172
Income (loss) from operations		16,314			(15,414	)		10,348			(50,424	)
Net loss attributable to common shareholders (2)		(886	)		(82,919	)		(58,350	)		(206,642	)
Net loss per share attributable to common shareholders (3):
Basic		(0.02	)		(1.63	)		(1.15	)		(4.06	)
Diluted		(0.02	)		(1.63	)		(1.15	)		(4.06	)
2009
Revenues		81,920			80,897			75,010			74,327
Costs, expenses and other (1)		82,987			72,027			72,635			101,734
Income (loss) from operations		(1,067	)		8,870			2,375			(27,407	)
Net income (loss) attributable to common shareholders		1,636			(4,366	)		(9,121	)		(39,966	)
Net income (loss) per share attributable to common shareholders (3):
Basic		0.05			(0.12	)		(0.20	)		(0.80	)
Diluted		0.05			(0.12	)		(0.20	)		(0.80	)

(1) Included here is impairment of oil and gas properties the most significant amounts of which are in the fourth quarters of 2010 and 2009 when impairment was $48.2 million and $37.1 million, respectively.

(2) In the second quarter of 2010, we refinanced our long-term debt and recognized a loss on debt extinguishment of $78.2 million. Also in the second quarter of 2010, we completed construction of theATP Titan and therefore ceased capitalizing related interest.

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

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ATP OIL & GAS CORPORATION AND SUBSIDIARIES

SUPPLEMENTAL DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES

Oil and Gas Reserves and Related Financial Data (Unaudited)

Capitalized Costs Related to Oil and Gas Producing Activities

The following table summarizes capitalized costs related to our oil and gas operations as of December 31 (in thousands):

	Gulf of Mexico			North Sea			Total
2008
Oil and gas properties:
Unproved	$	13,172		$	1,533		$	14,705
Proved		2,550,856			251,459			2,802,315
Accumulated depletion, impairment and amortization		(863,826	)		(80,991	)		(944,817	)
	$	1,700,202		$	172,001		$	1,872,203
2009
Oil and gas properties:
Unproved	$	12,219		$	1,691		$	13,910
Proved		3,261,445			347,686			3,609,131
Accumulated depletion, depreciation, impairment and amortization		(1,025,741	)		(111,528	)		(1,137,269	)
	$	2,247,923		$	237,849		$	2,485,772
2010
Oil and gas properties:
Unproved	$	9,249		$	11,153		$	20,402
Proved		3,813,325			478,115			4,291,440
Accumulated depletion, depreciation, impairment and amortization		(1,265,217	)		(141,989	)		(1,407,206	)
	$	2,557,357		$	347,279		$	2,904,636

Costs Incurred

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

	Gulf of Mexico		North Sea		Total
2008
Property acquisition costs:
Proved	$	2,462	$	—	$	2,462
Unproved		1,466		—		1,466
Development costs		714,704		105,809		820,513
Exploratory costs		28,596		—		28,596
Oil and gas expenditures	$	747,228	$	105,809	$	853,037
2009
Unproved property acquisition costs	$	161	$	4	$	165
Development costs		712,531		95,922		808,453
Oil and gas expenditures	$	712,692	$	95,926	$	808,618
2010
Property acquisition costs:
Proved	$	20,283	$	—	$	20,283
Unproved		625		—		625
Development costs		533,553		139,890		673,443
Oil and gas expenditures	$	554,461	$	139,890	$	694,351

F-33

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

SUPPLEMENTAL DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES

Results of Operations for Oil and Gas Producing Activities

The results of operations for oil and gas producing activities for the years ended December 31 below exclude general and administrative expenses, interest charges and other non operating items except income tax expense which was determined by applying the statutory rates to pretax operating results (in thousands).

	Gulf of Mexico			North Sea			Total
2008
Oil and gas production	$	488,258		$	96,565		$	584,823
Other revenues		33,206			—			33,206
Total revenues		521,464			96,565			618,029
Lease operating		67,262			23,934			91,196
Exploration		48			—			48
Depreciation, depletion and amortization		151,996			93,973			245,969
Impairment of oil and gas properties		125,059			—			125,059
Accretion of asset retirement obligation		12,412			3,154			15,566
Loss on abandonment		13,289			—			13,289
Gain on disposal of properties		(160	)		(119,073	)		(119,233	)
Income before income taxes		151,558			94,577			246,135
Income tax expense		(53,045	)		(47,289	)		(100,334	)
Results of operations from producing activities (excluding corporate overhead and interest costs)	$	98,513		$	47,288		$	145,801
2009
Oil and gas production	$	281,460		$	17,030		$	298,490
Other revenues		13,664			—			13,664
Total revenues		295,124			17,030			312,154
Lease operating		74,973			9,983			84,956
Exploration		233			31			264
Depreciation, depletion and amortization		128,777			24,003			152,780
Impairment of oil and gas properties		45,799			—			45,799
Accretion of asset retirement obligation		10,441			1,235			11,676
Loss on abandonment		2,872			—			2,872
(Gain) loss on disposal of properties		(13,177	)		744			(12,433	)
Income (loss) before income taxes		45,206			(18,966	)		26,240
Income tax (expense) benefit		(15,822	)		9,484			(6,338	)
Results of operations from producing activities (excluding corporate overhead and interest costs)	$	29,384		$	(9,482	)	$	19,902
2010
Oil and gas production revenues	$	416,836		$	21,161		$	437,997
Lease operating		126,394			6,150			132,544
Exploration		1,165			9			1,174
Depreciation, depletion and amortization		200,457			20,200			220,657
Impairment of oil and gas properties		48,392			14,875			63,267
Accretion of asset retirement obligation		12,466			1,361			13,827
Drilling interruption costs		23,647			—			23,647
Loss on abandonment		4,829			—			4,829
Gain on disposal of properties		(26,720	)		—			(26,720	)
Income (loss) before income taxes		26,206			(21,434	)		4,772
Income tax (expense) benefit		(9,172	)		10,717			1,545
Results of operations from producing activities (excluding corporate overhead and interest costs)	$	17,034		$	(10,717	)	$	6,317

Oil and Natural Gas Reserves

Proved reserves are the estimated quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible – from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government

F-34

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

SUPPLEMENTAL DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES

regulations. Reservoirs are considered proved if shown to be economically producible by either actual production or conclusive formation tests.

In December 2008, the SEC issued its final rule, “Modernization of Oil and Gas Reporting” (Release Nos. 33-8995; 34-59192; FR-78). The disclosure requirements under the final rule became effective for this filing for the year ended December 31, 2009. The final rule changed a number of oil and gas reserve estimation and disclosure requirements under SEC Regulations S-K and S-X. Subsequently, the FASB updated Extractive Industries — Oil and Gas (Topic 932) to align the oil and gas reserves estimation and disclosure requirements with the SEC’s final rule. Among the principal changes affecting us in the final rule are requirements to use estimated future sales prices based on a first-of-month 12-month arithmetic average price for reserve estimation and disclosure instead of a single end-of-year price; the ability to use new reliable technologies to establish reasonable certainty of proved reserves; expanding proved undeveloped reserves disclosures, including a discussion of proved undeveloped reserves that have remained undeveloped for five years or more; and the requirement to disclose the qualifications of the chief technical person who oversees the company’s overall reserves estimation process.

We have applied this guidance at December 31, 2009 and 2010 in the supplementary oil and gas information presented below or under Item 2 properties. The adoption of these new rules has been treated as a change in accounting principle that is inseparable from a change in accounting estimate, as it is impracticable to estimate the impact of the new rules because of the cost and resources required to prepare duplicate reserve valuations. Beginning with 2009, the first-of-month 12-month average prices for crude oil and natural gas for 2009 were lower than the subsequent year-end spot prices applicable under the old rules. Because of the changes in assumptions, the 2010 and 2009 reserve valuations below may not be comparable to those of prior years.

In all years presented, 100% of our reserves were prepared by independent petroleum engineers. As of December 31, 2010, we use Collarini Associates and Ryder Scott Company, L.P. The following table sets forth our net proved oil and gas reserves at December 31, 2007, 2008, 2009 and 2010 and the changes in net proved oil and gas reserves for the years ended December 31, 2008, 2009 and 2010:

F-35

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

SUPPLEMENTAL DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES

	Oil and Condensate (MBbls)									Natural Gas (MMcf)									Equivalent Barrels (MBoe)
	Gulf of Mexico			North Sea			Total			Gulf of Mexico			North Sea			Total			Gulf of Mexico			North Sea			Total
Proved Reserves at December 31, 2007		42,342			17,551			59,893			187,633			168,577			356,210			73,613			45,648			119,261
Revisions of previous estimates		(1,308	)		8,017			6,709			23,753			18,668			42,421			2,651			11,128			13,780
Purchases of minerals in place		1,944			—			1,944			11,173			—			11,173			3,806			—			3,806
Extensions and discoveries		1,795			—			1,795			6,339			—			6,339			2,852			—			2,852
Sales of minerals in place (1)		(730	)		(31	)		(761	)		(1,380	)		(61,156	)		(62,536	)		(960	)		(10,224	)		(11,184	)
Production		(4,232	)		(35	)		(4,267	)		(16,759	)		(15,103	)		(31,862	)		(7,025	)		(2,552	)		(9,578	)
Proved Reserves at December 31, 2008		39,811			25,502			65,313			210,759			110,986			321,745			74,937			44,000			118,937
Revisions of previous estimates (2)		13,621			9			13,630			18,605			(740	)		17,866			16,723			(114	)		16,609
Purchases of minerals in place		12			—			12			314			—			313			64			—			64
Extensions and discoveries		2,340			—			2,340			15,349			3,127			18,476			4,898			521			5,419
Production		(3,344	)		(9	)		(3,353	)		(11,988	)		(3,131	)		(15,119	)		(5,342	)		(531	)		(5,873	)
Proved Reserves at December 31, 2009		52,440			25,502			77,942			233,039			110,242			343,281			91,280			43,876			135,156
Revisions of previous estimates		743			126			869			(12,546	)		(6,373	)		(18,919	)		(1,348	)		(936	)		(2,284	)
Purchases of minerals in place		1,617			—			1,617			2,990			—			2,990			2,115			—			2,115
Extensions and discoveries		—			—			—			—			824			824			—			137			137
Sales of minerals in place		(828	)		—			(828	)		(1,253	)		—			(1,253	)		(1,037	)		—			(1,037	)
Production		(4,464	)		(7	)		(4,471	)		(15,899	)		(3,252	)		(19,151	)		(7,114	)		(549	)		(7,663	)
Proved Reserves at December 31, 2010		49,508			25,621			75,129			206,331			101,441			307,772			83,896			42,528			126,424

(1) The effect of the sale in 2008 of the Tors and Wenlock fields is shown here for the North Sea.

(2) These revisions relate to our Gomez and Telemark Hubs primarily related to well performance and drilling results.

	Oil and Condensate (MBbls)						Natural Gas (MMcf)						Equivalent Barrels (MBoe)
	Gulf of Mexico		North Sea		Total		Gulf of Mexico		North Sea		Total		Gulf of Mexico		North Sea		Total
Proved Developed Reserves at
December 31, 2008		7,578		4		7,582		57,645		8,233		65,878		17,187		1,376		18,563
December 31, 2009		7,826		4		7,830		44,517		12,745		57,262		15,246		2,128		17,374
December 31, 2010		13,626		4		13,630		52,656		8,323		60,979		22,402		1,391		23,793

F-36

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

SUPPLEMENTAL DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES

Standardized Measure

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

	Gulf of Mexico			North Sea			Total
2008
Future cash inflows	$	2,946,012		$	2,014,704		$	4,960,716
Future operating expenses		(586,559	)		(320,587	)		(907,146	)
Future development costs		(785,225	)		(624,259	)		(1,409,484	)
Future income taxes		(272	)		(409,535	)		(409,807	)
Future net cash flows		1,573,956			660,323			2,234,279
10% annual discount		(620,621	)		(485,576	)		(1,106,197	)
Standardized measure of discounted future net cash flows	$	953,335		$	174,747		$	1,128,082
2009
Future cash inflows	$	4,041,874		$	1,965,631		$	6,007,505
Future operating expenses		(718,854	)		(353,644	)		(1,072,498	)
Future development costs		(891,928	)		(577,080	)		(1,469,008	)
Future income taxes		(129,055	)		(317,628	)		(446,683	)
Future net cash flows		2,302,037			717,279			3,019,316
10% annual discount		(778,752	)		(465,857	)		(1,244,609	)
Standardized measure of discounted future net cash flows	$	1,523,285		$	251,422		$	1,774,707
2010
Future cash inflows	$	4,876,858		$	2,600,173		$	7,477,031
Future operating expenses		(1,067,346	)		(315,814	)		(1,383,160	)
Future development costs		(791,939	)		(950,870	)		(1,742,809	)
Future income taxes		(158,093	)		(346,104	)		(504,197	)
Future net cash flows		2,859,480			987,385			3,846,865
10% annual discount		(829,465	)		(668,640	)		(1,498,105	)
Standardized measure of discounted future net cash flows	$	2,030,015		$	318,745		$	2,348,760

Future cash inflows for 2010 and 2009 are computed by applying average oil and gas prices to the year-end estimated future production of proved oil and gas reserves. The timing of our future production assumes we will receive the drilling permits necessary to drill development wells at Telemark and Gomez during 2011 (See Note 3, Risks and Uncertainties). The average prices used for this calculation for 2010 and 2009 are unweighted arithmetic averages of quoted market closing prices for the first day of each month, adjusted by property-specific differentials to those market prices based on product quality and transportation costs to market. The average prices used for this calculation for 2008 are quoted market closing prices for the last business day of the year, adjusted by property-specific differentials to those market prices based on product quality and transportation costs to market. Estimates of future development and operating costs are based on year-end costs and assume continuation of existing economic conditions. Estimated future income taxes are based on current laws and tax rates, projected into the future. We will incur significant capital expenditures in the development of our Gulf of Mexico and North Sea oil and gas properties. The estimated future net cash flows are then discounted using a rate of 10% per year to reflect the estimated timing of the future cash flows. The standardized measure of discounted future net cash flows is the future net cash flows less the computed discount.

F-37

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

SUPPLEMENTAL DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES

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

	Oil and Condensate ($/Bbl)						Natural Gas ($/Mcf)
	Gulf of Mexico		U.K. North Sea		Dutch North Sea		Gulf of Mexico		U.K. North Sea		Dutch North Sea
2008		44.60		45.59		32.14		5.71		8.77		12.60
2009		61.18		59.73		50.35		3.87		4.95		8.27
2010		79.43		79.71		—		4.38		6.58		—

F-38

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

SUPPLEMENTAL DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES

Changes in Standardized Measure

Changes in standardized measure of future net cash flows relating to proved oil and natural gas reserves are summarized below for the years ended December 31 (in thousands):

	Gulf of Mexico			North Sea			Total
2008
Beginning of year	$	2,025,557		$	614,410		$	2,639,967
Sales of oil and gas, net of production costs		(420,996	)		(80,910	)		(501,906	)
Net changes in income taxes		603,152			107,107			710,259
Net changes in price and production costs		(1,583,177	)		(104,474	)		(1,687,651	)
Revisions of quantity estimates		61,923			249,086			311,009
Extensions and discoveries		(5,529	)		—			(5,529	)
Accretion of discount		262,881			86,846			349,727
Development costs incurred		472,019			87,000			559,019
Changes in estimated future development costs		45,200			87			45,287
Purchases of minerals in place		(12,095	)		—			(12,095	)
Sales of minerals in place		(67,704	)		(462,375	)		(530,079	)
Changes in production rates, timing and other		(427,896	)		(322,030	)		(749,926	)
		(1,072,222	)		(439,663	)		(1,511,885	)
End of year	$	953,335		$	174,747		$	1,128,082
2009
Beginning of year	$	953,335		$	174,747		$	1,128,082
Sales of oil and gas, net of production costs		(208,396	)		(7,047	)		(215,443	)
Net changes in income taxes		(98,144	)		30,749			(67,395	)
Net changes in price and production costs		228,126			(24,901	)		203,225
Revisions of quantity estimates		368,227			(1,274	)		366,953
Extensions and discoveries		105,788			11,337			117,125
Accretion of discount		95,343			32,169			127,512
Development costs incurred		359,376			68,752			428,128
Changes in estimated future development costs		(280,689	)		(7,663	)		(288,352	)
Purchases of minerals in place		(1,639	)		—			(1,639	)
Sales of minerals in place		—			—			—
Changes in production rates, timing and other		1,958			(25,447	)		(23,489	)
		569,950			76,675			646,625
End of year	$	1,523,285		$	251,422		$	1,774,707
2010
Beginning of year	$	1,523,285		$	251,422		$	1,774,707
Sales of oil and gas, net of production costs		(290,443	)		(15,011	)		(305,454	)
Net changes in income taxes		(23,113	)		(13,953	)		(37,066	)
Net changes in price and production costs		499,596			260,311			759,907
Revisions of quantity estimates		(40,393	)		(17,872	)		(58,265	)
Extensions and discoveries		—			3,927			3,927
Accretion of discount		162,152			36,761			198,913
Development costs incurred		306,288			134,837			441,125
Changes in estimated future development costs		(73,339	)		(171,218	)		(244,557	)
Purchases of minerals in place		12,714			—			12,714
Sales of minerals in place		(36,043	)		—			(36,043	)
Changes in production rates, timing and other		(10,689	)		(150,459	)		(161,148	)
		506,730			67,323			574,053
End of year	$	2,030,015		$	318,745		$	2,348,760

F-39

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

SUPPLEMENTAL DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES

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

F-40

SCHEDULE I – PARENT COMPANY FINANCIAL STATEMENTS

ATP OIL & GAS CORPORATION

UNCONSOLIDATED BALANCE SHEETS OF REGISTRANT

(In Thousands, Except Share Amounts)

	December 31,
	2010			2009
Assets
Current assets:
Cash and cash equivalents	$	124,047		$	95,083
Accounts receivable (net of allowance of $225 and $291, respectively)		69,660			43,741
Accounts receivable – intercompany		—			2,066
Deferred tax asset		8,191			101,956
Derivative asset		1,688			—
Other current assets		22,735			6,662
Total current assets		226,321			249,508
Oil and gas properties (using the successful efforts method of accounting):
Proved properties		2,325,507			2,966,888
Unproved properties		9,249			12,219
		2,334,756			2,979,107
Less accumulated depletion, depreciation, impairment and amortization		(1,157,412	)		(956,860	)
Oil and gas properties, net		1,177,344			2,022,247
Deferred financing costs, net		38,897			16,378
Investment in and advance to subsidiaries		1,193,462			254,423
Notes receivable – intercompany		93,280			41,659
Other assets, net		12,504			13,934
Total assets	$	2,741,808		$	2,598,149
Liabilities and Equity
Current liabilities:
Accounts payable and accruals	$	176,843		$	201,993
Accounts payable – intercompany		3,119			—
Current maturities of long-term debt		1,500			16,838
Asset retirement obligation		40,472			43,418
Derivative liability		35,581			16,216
Other current liabilities		32,959			19,532
Total current liabilities		290,474			297,997
Long-term debt		1,639,036			1,199,847
Other long-term obligations		431,626			257,889
Asset retirement obligation		115,017			94,448
Deferred tax liability		8,191			125,055
Derivative liability		5,478			7,646
Deferred revenue		—			19,336
Total liabilities		2,489,822			2,002,218
Commitments and contingencies (Note 12, Notes to Consolidated Financial Statements in Part II, Item 8)
Shareholders’ equity:
8% convertible perpetual preferred stock: $0.001 par value, 10,000,000 shares authorized; 1,400,000 issued and outstanding at December 31, 2010 and 2009 at liquidation value		140,000			140,000
Common stock: $0.001 par value, 100,000,000 shares authorized; 51,271,323 issued and 51,267,573 outstanding at December 31, 2010; 50,755,310 issued and 50,679,470 outstanding at December 31, 2009		51			51
Additional paid-in capital		570,739			571,595
Accumulated deficit		(356,866	)		(19,317	)
Accumulated other comprehensive loss		(101,027	)		(95,487	)
Treasury stock, at cost		(911	)		(911	)
Total shareholders’ equity		251,986			595,931
Total liabilities and equity	$	2,741,808		$	2,598,149

See notes to unconsolidated financial statements of registrant.

S-1

ATP OIL & GAS CORPORATION

UNCONSOLIDATED STATEMENTS OF OPERATIONS OF REGISTRANT

(In Thousands)

	Year Ended December 31,
	2010			2009			2008
Revenues:
Oil and gas production	$	416,836		$	281,460		$	488,258
Other		—			13,664			33,206
		416,836			295,124			521,464
Costs, operating expenses and other:
Lease operating		126,394			74,973			67,262
Processing costs – intercompany		58,031			32,937			—
Exploration		1,165			233			100
General and administrative		42,085			41,397			38,100
Depreciation, depletion and amortization		179,042			121,125			152,246
Impairment of oil and gas properties		48,392			45,799			125,059
Accretion of asset retirement obligation		12,466			10,441			12,412
Drilling interruption costs		23,647			—			—
Loss on abandonment		4,829			2,872			13,290
Gain on exchange/disposal of properties		(26,720	)		(13,177	)		(160	)
Other, net		(948	)		(743	)		(99	)
		468,383			315,857			408,210
Income (loss) from operations		(51,547	)		(20,733	)		113,254
Other income (expense):
Interest income		236			16			1,344
Interest expense, net		(221,808	)		(45,955	)		(81,092	)
Derivative income (expense)		(16,253	)		(9,834	)		96,507
Loss on debt extinguishment		(75,316	)		—			(24,220	)
Equity in subsidiary earnings, net of tax		3,116			8,660			59,421
		(310,025	)		(47,113	)		51,960
Income (loss) before income taxes		(361,572	)		(67,846	)		165,214
Income tax (expense) benefit:
Current		924			(924	)		(1,326	)
Deferred		23,099			19,809			(42,183	)
		24,023			18,885			(43,509	)
Net income (loss)		(337,549	)		(48,961	)		121,705
Less convertible preferred stock dividends		(11,248	)		(2,856	)		—
Net income (loss) attributable to common shareholders	$	(348,797	)	$	(51,817	)	$	121,705

See notes to unconsolidated financial statements of registrant.

S-2

ATP OIL & GAS CORPORATION

UNCONSOLIDATED STATEMENTS OF CASH FLOWS OF REGISTRANT

(In Thousands)

	Year Ended December 31,
	2010			2009			2008
Net cash provided by (used in) operating activities	$	(100,773	)	$	162,309		$	431,415
Cash flows from investing activities
Additions to oil and gas properties		(534,295	)		(551,555	)		(750,910	)
Proceeds from disposition of properties		17,053			13,000			82,644
Decrease in restricted cash		—			—			13,837
Distributions from subsidiaries		218,790			144,271			290
Net cash used in investing activities		(298,452	)		(394,284	)		(654,139	)
Cash flows from financing activities
Proceeds from senior second lien notes		1,492,965			—			—
Proceeds from first lien term loans		147,000			—			—
Proceeds from term loans		46,000			19,000			1,639,750
Payments of term loans		(1,263,360	)		(176,511	)		(1,680,190	)
Deferred financing costs		(53,017	)		(6,490	)		(15,523	)
Loans to subsidiaries		(68,116	)		(157,680	)		(119,076	)
Subsidiary loan payments		16,494			146,105			337,102
Issuance of common stock, net of costs		—			170,629			—
Issuance of preferred stock, net of costs		—			135,549			—
Proceeds from other long-term obligations		231,888			89,011			—
Payments of other long-term obligations		(102,818	)		(2,298	)		(13,397	)
Preferred stock dividends		(11,276	)		—			—
Payments of short-term notes		(11,180	)		—			—
Exercise of stock options		3,609			3			33
Net cash provided by financing activities		428,189			217,318			148,699
Increase (decrease) in cash and cash equivalents		28,964			(14,657	)		(74,025	)
Cash and cash equivalents, beginning of year		95,083			109,740			183,765
Cash and cash equivalents, end of year	$	124,047		$	95,083		$	109,740

See notes to unconsolidated financial statements of registrant.

S-3

ATP OIL & GAS CORPORATION

NOTES TO UNCONSOLIDATED FINANCIAL STATEMENTS OF REGISTRANT

Note 1 — Basis of Presentation

The financial statements of ATP Oil & Gas Corporation (the “Registrant” or “Parent Company”) have been prepared pursuant to Rule 5-04 of Regulation S-X of the Securities Exchange Act of 1934, as amended, because certain of ATP’s subsidiaries are contractually prohibited from making payments, loans or transferring assets to the Parent Company or other affiliated entities. Specifically, under the terms of our ATP Titan facility, ATP Titan, LLC is restricted from transferring assets or making dividends in excess of one quarter’s debt service plus $10.0 million at any time. Additionally, ATP-IP is prohibited from making distributions to ATP Oil & Gas Corporation other than those specifically provided for in the Partnership Agreement. The restricted net assets associated with each of these entities exceed 25% of the consolidated net assets of ATP Oil & Gas Corporation as of December 31, 2010.

For purposes of these financial statements, the Parent Company’s investments in wholly owned subsidiaries are accounted for under the equity method. Under this method, the accounts of the subsidiaries are not consolidated. The investments in and advances to subsidiaries are recorded in the unconsolidated balance sheets. The income (loss) from operations of subsidiaries is reported on an equity basis as equity in subsidiary earnings, net of tax, in the unconsolidated statements of operations of registrant. These statements should be read in conjunction with the consolidated financial statements and notes thereto, included in Part II, Item 8 of in this Annual Report on Form 10-K.

Note 2 — Notes Receivable – Intercompany

Notes receivable – intercompany represents cumulative net advances to ATP Oil & Gas (UK) Limited and ATP Oil & Gas (Netherlands) B.V. that are subject to intercompany loan agreements (the “Notes”). The Notes provide for borrowings to each subsidiary on a revolving basis of up to $800.0 million. Outstanding balances bear interest at the same rate of interest as the principal borrowings of ATP Oil & Gas Corporation, which at December 31, 2010 was 11.875%. The Notes mature on June 27, 2018.

S-4

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS

FOR EACH OF THE THREE YEARS ENDED DECEMBER 31, 2010

(In Thousands)

	Balance at Beginning of Period		Charged to Costs and Expenses		Charged  to Other Accounts			Deduction			Balance at End of Period
2008
Allowance for doubtful accounts	$	382	$	—	$	—		$	(30	)	$	352
Valuation allowance on deferred tax assets		3,025		—		—			—			3,025
2009
Allowance for doubtful accounts	$	352	$	86	$	—		$	(147	)	$	291
Valuation allowance on deferred tax assets		3,025		1,300		—			—			4,325
2010
Allowance for doubtful accounts	$	291	$	—	$	—		$	(66	)	$	225
Valuation allowance on deferred tax assets		4,325		94,835		(99	)		—			99,061

S-5