10-K

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-K

x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE

SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2006

or

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE

SECURITIES EXCHANGE ACT OF 1934

Commission file number: 000-32261

ATP Oil & Gas Corporation

(Exact name of registrant as specified in its charter)

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

4600 Post Oak Place, Suite 200

Houston, Texas 77027

(Address of principal executive offices) (Zip Code)

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

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

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

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

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

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

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

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

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

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

Indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ Nox

The aggregate market value of the voting and non-voting common stock held by non-affiliates of the Registrant as of June 30, 2006 (the last business day of the Registrant’s most recently completed second fiscal quarter) was approximately $869,175,188. The number of shares of the Registrant’s common stock outstanding as of February 20, 2007 was 30,198,970.

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, 2006, are incorporated by reference in Part III of this Form 10-K.

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

2006 FORM 10-K ANNUAL REPORT

TABLE OF CONTENTS

	Page
Part I
Item 1. Business	6
Item 1A. Risk Factors	13
Item 1B. Unresolved Staff Comments	20
Item 2. Properties	20
Item 3. Legal Proceedings	24
Item 4. Submission of Matters to a Vote of Security Holders	24
Part II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	25
Item 6. Selected Financial Data	26
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations	27
Item 7A. Quantitative and Qualitative Disclosures about Market Risk	41
Item 8. Financial Statements and Supplementary Data	42
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	42
Item 9A. Controls and Procedures	42
Item 9B. Other Information	42
Part III
Item 10. Directors, Executive Officers and Corporate Governance	43
Item 11. Executive Compensation	44
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	44
Item 13. Certain Relationships and Related Transactions, and Director Independence.	44
Item 14. Principal Accounting Fees and Services	44
Part IV
Item 15. Exhibits, Financial Statement Schedules	45

2

Cautionary Statement About Forward-Looking Statements

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

This annual report includes assumptions, expectations, projections, intentions or beliefs about future events. These statements are intended as “forward-looking statements” under the Private Securities Litigation Reform Act of 1995, Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Act of 1934. We caution that assumptions, expectations, projections, intentions and beliefs about future events may and often do vary from actual results and the differences can be material.

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

• projected operating or financial results;

• timing and expectations of financing activities;

• budgeted or projected capital expenditures;

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

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

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

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

When used in this document, the words “anticipate,” “estimate,” “project,” “forecast,” “may,” “should,” and “expect” reflect forward-looking statements.

There can be no assurance that actual results will not differ materially from those expressed or implied in such forward looking statements. Some of the key factors which could cause actual results to vary from those expected include:

• the volatility in oil and natural gas prices;

• the timing of planned capital expenditures;

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

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

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

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

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

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

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

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

3

CERTAIN DEFINITIONS

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

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

Crude oil and other liquid hydrocarbons are converted into cubic feet of gas equivalent based on six Mcf of gas to one barrel of crude oil or other liquid hydrocarbons.

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

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

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

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

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

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

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

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

4

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

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

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

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

5

PART I

Item 1. Business.

General

ATP Oil & Gas Corporation was incorporated in Texas in 1991. We are engaged in the acquisition, development and production of oil and natural gas properties in the Gulf of Mexico and the U.K. and Dutch Sectors of the North Sea (the “North Sea”). We primarily focus our efforts on oil and natural gas properties where previous drilling has encountered reservoirs that appear to contain commercially productive quantities of oil and gas. Many of these properties contain proved undeveloped reserves that are economically attractive to us but are not strategic to major or exploration-oriented independent oil and natural gas companies. Occasionally we will acquire properties that are already producing or where previous drilling has encountered reservoirs that appear to us to contain commercially productive quantities of oil and gas even though the reservoirs do not meet the SEC definition of proved reserves. Our management team has extensive engineering, geological, geophysical, technical and operational expertise in successfully developing and operating properties in both our current and planned areas of operation.

At December 31, 2006, we had estimated net proved reserves of 636.9 Bcfe, of which approximately 359.4 Bcfe (56%) was in the Gulf of Mexico and 277.5 Bcfe (44%) was in the North Sea. Year-end reserves were comprised of 329.2 Bcf of natural gas (52%) and 51.3 MMBbls of oil (48%). The majority of our oil reserves (66%) are located in the Gulf of Mexico, with the balance located in the North Sea. The majority of our natural gas reserves (52%) are located in the North Sea, with the balance located in the Gulf of Mexico. Of our total proved reserves, 129.6 MMcfe (20%) were producing, 84.3 MMcfe (13%) were developed and not producing and 423.0 MMcfe (66%) were undeveloped. The estimated pre-tax PV-10 of our proved reserves at December 31, 2006 was $1.3 billion. See “Item 2. Properties—Oil and Natural Gas Reserves” for a reconciliation to after-tax PV-10.

At December 31, 2006, we had leasehold and other interests in 72 offshore blocks, 44 platforms and 112 wells, including 14 subsea wells, in the Gulf of Mexico. We operate 94 (84%) of these wells, including all of the subsea wells, and 86% of our offshore platforms. We also had interests in 11 blocks and 2 company-operated subsea wells in the North Sea. Our average working interest in our properties at December 31, 2006 was approximately 81%. For more information regarding our operations and assets in the Gulf of Mexico and North Sea, see Note 14, “Segment Information,” to the Notes to Consolidated Financial Statements.

Our Business Strategy

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

• significant undeveloped reserves or reservoirs;

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

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

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

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

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

6

company due to cost structure. Because of our cost structure, expertise in our areas of focus and our ability to develop projects efficiently, these properties may be economically attractive to us.

By focusing on properties that are not strategic to other companies, we are able to minimize up-front acquisition costs and concentrate available capital on the development phase of these properties. For the three year period ending December 31, 2006, we have added 243.5 Bcfe of proved oil and natural gas reserves through acquisitions at a total cost of $120.4 million. Development costs for this same period were approximately $978.8 million.

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

Our Strengths

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

• Technical Expertise and Significant Experience. We have assembled a technical staff with an average of over 24 years of industry experience. Our technical staff has specific expertise in the Gulf of Mexico and North Sea offshore property development, including the implementation of subsea completion technology.

• Operating Control. As the operator of a property, we are afforded greater control of the selection of completion and production equipment, the timing and amount of capital expenditures and the operating parameters and costs of the project. As of December 31, 2006, we operated all of our properties under development, all of our subsea wells and 87% of our offshore platforms.

• Employee Ownership. Through employee ownership, we have assembled a staff whose business decisions are aligned with the interests of our shareholders. As of February 28, 2007, our executive officers and directors own approximately 30% of our common stock.

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

Marketing and Delivery Commitments

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

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

7

Competition

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

Regulation

Gulf of Mexico

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

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

The Outer Continental Shelf Lands Act, which the FERC implements with regard to transportation and pipeline issues, requires that all pipelines operating on or across the Outer Continental Shelf provide open-access, non-discriminatory service. Previously the FERC enforced this provision pursuant to its authority under both the Natural Gas Act and the Outer Continental Shelf Lands Act. In 2003 the courts determined that the FERC had only limited authority to enforce its open access rules on the Outer Continental Shelf and decided, instead, that such authority primarily rested with others. There are currently no regulations implemented by FERC under its Outer Continental Shelf Lands Act authority on gatherers and other entities outside the reach of its Natural Gas Act jurisdiction. It should be noted, however, that the FERC has before it pending rulemaking to consider whether to reformulate the test it applies for defining whether an entity is engaged in non-jurisdictional gathering in the shallow waters of the Outer Continental Shelf. Further, the Minerals Management Service, or MMS, has asked for comments on whether it should implement regulations under its Outer Continental Shelf Lands Act authority on gatherers and other entities to ensure open and non-discriminatory access on gathering systems and production facilities on the Outer Continental Shelf. Although we have no way of knowing whether the MMS will proceed with implementing regulations of this nature, we do not believe that any FERC action taken under its Outer Continental Shelf Lands Act jurisdiction will affect us in a way that materially differs from the way it affects other natural gas producers, gatherers and marketers.

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

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

8

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

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

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

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

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

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

9

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

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

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

The OPA also requires a responsible party to submit proof of its financial responsibility to cover environmental cleanup and restoration costs that could be incurred in connection with an oil spill. Under this Act, parties responsible for offshore facilities must provide financial assurance of at least $35.0 million to address oil spills and associated damages, with this financial assurance amount increasing up to $150.0 million in certain limited circumstances if the MMS determines that a higher amount is warranted. The OPA also imposes other requirements, such as the preparation of an oil spill contingency plan, which we have in place.

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

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

10

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

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

North Sea

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

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

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

11

offshore production facilities. Health and safety offshore is further governed by the Health and Safety at Work Act 1974 and applicable regulations.

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

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

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

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

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

Employees

At December 31, 2006 we had 52 full-time employees in our Houston office, 5 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 is www.atpog.com and you may access, free of charge, through the Investor Relations portion of our website, our annual reports on Form 10-K, current reports on Form 8-K and amendments to such

12

reports filed or furnished pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934, as amended, as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC. Information contained on our website is not part of this report.

Item 1A. Risk Factors.

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

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

Estimates of our oil and natural gas reserves and the costs and timing associated with developing these reserves may not be accurate. Additionally, approximately 66% of our total proved reserves are undeveloped. Development of these reserves may not yield the expected results, or the development may be delayed or the development costs may exceed our estimates, any of which may materially affect our financial position and results of operations. Development activity may result in downward adjustments in reserves or higher than estimated costs.

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

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

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

The size of our operations and our capital expenditure budget limits the number of properties that we can develop in any given year. Complications in the development of any single material well may result in a material adverse effect on our financial condition and results of operations. For instance, during 2006, we experienced production delays and increased development costs in connection with the development of our Tors wells in the North Sea. In late 2005, we experienced delays and increased development costs in developing our Gomez project in the Gulf of Mexico as a result of hurricanes Katrina and Rita.

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

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

Shortages or an increase in cost of drilling rigs, equipment, supplies or personnel could delay or adversely affect our operations, which could have a material adverse effect on our business, financial condition and results of operations. In periods of increased drilling activity in the Gulf of Mexico and the North Sea, we may experience increases in associated costs, including those related to drilling rigs, equipment, supplies and personnel and the services and products of other vendors to the industry. Increased drilling activity in the Gulf of Mexico and the North Sea also decreases the availability of offshore rigs and associated equipment. These

13

costs may increase further and necessary equipment and services may not be available to us at economical prices.

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

We have historically needed and will continue to need substantial amounts of cash to fund our capital expenditure and working capital requirements. Our ongoing capital requirements consist primarily of funding acquisition, development and abandonment of oil and gas reserves and to meet our debt service obligations. Cash paid for capital expenditures for oil and gas properties was approximately $585.5 million, $420.5 million and $87.4 million for the years ended December 31, 2006, 2005 and 2004, respectively. Because we have experienced a negative working capital position in past years, we have been dependent on debt and equity financing to meet our working capital requirements that were not funded from operations.

For 2007, we plan to finance anticipated expenses, debt service and acquisition and development requirements with available cash, funds generated from cash provided by operating activities and net cash proceeds from the potential sale of assets, issuance of debt or new equity offerings. If these anticipated funds are less than our requirements, we may have to forego or reduce our capital program.

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

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

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

Historically, the markets for oil and natural gas have been volatile, and they are likely to continue to be volatile in the future. For example, oil and natural gas prices increased significantly in late 2000 and early 2001 and then steadily declined in 2001, only to climb again in recent years to near all-time highs before declining again in late 2006. Among the factors that can cause this volatility are:

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

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

• weather conditions;

• domestic and foreign governmental regulations;

• political conditions in natural gas or oil producing regions;

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

• price and availability of alternative fuels.

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

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

14

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

• production is less than expected for forward sales contracts;

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

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

Our results of operations may be negatively impacted in the future by our financial derivative instruments and fixed price forward sales contracts—our fixed forward sales are designated as normal sales under derivative accounting rules—and these instruments may limit any benefit we would receive from increases in the prices for oil and natural gas. For the years ended December 31, 2006, 2005 and 2004, we realized a loss on settled financial derivatives of $3.2 million, $0.7 million and $1.2 million, respectively.

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

In November 2006, we amended our Second Amended and Restated credit agreement, dated June 22, 2006 (the “Previous First Lien Credit Agreement”) and entered into a Second Lien Credit Agreement (the “Second Lien Credit Agreement”). In December 2006, we entered into the Third Amended and Restated Credit Agreement (the “First Lien Credit Agreement”) which amends and restates the Previous First Lien Credit Agreement and all prior amendments thereto. As amended, the First Lien Credit Agreement provides for aggregate outstanding borrowings of $900.0 million (the “First Lien Term Loans”) and up to $50.0 million under a Senior Secured Revolving Credit Facility (the “Revolver”). The Second Lien Credit Agreement provides for aggregate outstanding borrowings of $175.0 million (the “Second Lien Term Loans” and, together with the First Lien Term Loans, the “Term Loans”). The First Lien Term Loans mature in April 2010 and the Second Lien Term Loans mature in October 2010. The Revolver matures in October 2009. The Term Loans and the Revolver are secured by substantially all of our oil and gas assets in the Gulf of Mexico and a pledge of 65% of the capital stock of our subsidiaries, ATP (UK) and ATP Oil & Gas (Netherlands) B.V., and are guaranteed by our wholly owned subsidiary ATP Energy, Inc. As of December 31, 2006, we had an aggregate $1.071 billion principal outstanding under the Term Loans, and no amounts outstanding under the Revolver. The Term Loans contain customary restrictions, including covenants limiting our ability to incur additional debt, grant liens, make investments, consolidate, merge or acquire other businesses, sell assets, pay dividends and other distributions and enter into transactions with affiliates. We also must maintain specified financial requirements under the terms of our Term Loans and the Revolver including the following, as defined in the First Lien Credit Agreement and the Second Lien Credit Agreement:

• Minimum Current Ratio of 1.0 to 1.0;

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

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

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

• Ratio of pre-tax PV-10 of our Total Proved oil and gas reserves plus 50% of our pre-tax probable oil and gas reserves, both adjusted for current oil and gas price estimates, to Net Debt of at least 3.0 to 1.0 at June 30 or December 31 of any fiscal year;

• Maximum Commodity Hedging Agreements on no more than 80% of the forecasted production attributable to our proved producing reserves for the period for which such hedges are in effect;

• limit during any fiscal year Permitted Business Investments, as defined, to $150.0 million or 7.5% of PV-10 value of our total proved reserves.

These restrictions may make it difficult for us to successfully execute our business strategy or to compete in our industry with companies not similarly restricted. While we were in compliance with all of the financial covenants applicable to our Term Loans at December 31, 2006, 2005 and 2004, during 2003 and in February 2004, we were required to obtain waivers for certain of our financial covenants in our prior credit facility. If

15

we are unable to meet the requirements of our Term Loans or any new financial transaction that we may enter into, we may be required to seek waivers from our lenders and there is no assurance that such waivers would be granted.

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

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

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

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

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

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

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

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

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

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

Production of reserves from reservoirs in the Gulf of Mexico generally declines more rapidly than production from reservoirs in many other producing regions of the world. While this results in recovery of a relatively higher percentage of reserves from properties in the Gulf of Mexico during the initial years of production, we must incur significant capital expenditures to replace declining production.

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

We may incur substantial impairment write-downs.

If management’s estimates of the recoverable reserves on a property are revised downward, if development costs exceed previous estimates or if oil and natural gas prices decline, we may be required to record additional noncash impairment write-downs in the future, which would result in a negative impact to our financial position. We review our proved oil and gas properties for impairment on a depletable unit basis when circumstances suggest there is a need for such a review. To determine if a depletable unit is impaired, we compare the carrying value of the depletable unit to the undiscounted future net cash flows by applying

16

management’s estimates of future oil and gas prices to the estimated future production of oil and gas reserves over the economic life of the property. Future net cash flows are based upon our independent reservoir engineers’ estimates of proved reserves. In addition, other factors such as probable and possible reserves are taken into consideration when justified by economic conditions. For each property determined to be impaired, we recognize an impairment loss equal to the difference between the estimated fair value and the carrying value of the property on a depletable unit basis. Fair value is estimated to be the present value of the aforementioned expected future net cash flows. Any impairment charge incurred is recorded in accumulated depreciation, depletion, impairment and amortization to reduce our recorded basis in the asset. Each part of this calculation is subject to a large degree of judgment, including the determination of the depletable units’ estimated reserves, future cash flows and fair value. We recorded an impairment of $19.5 million for the year ended December 31, 2006 and no impairments in 2005 and 2004.

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

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

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

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

• fires;

• explosions;

• blow-outs and surface cratering;

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

• pipe, cement, subsea well or pipeline failures;

• casing collapses;

• embedded oil field drilling and service tools;

• abnormally pressured formations;

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

• hurricanes and other natural disasters.

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

• injury or loss of life;

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

• pollution and other environmental damage;

• clean-up responsibilities;

• regulatory investigation and penalties;

• suspension of our operations; and

• repairs to resume operations.

17

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

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

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

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

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

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

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

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

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

18

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

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

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

Our success will depend on our ability to retain and attract experienced geoscientists and other professional staff. As of December 31, 2006, we had 22 engineers, geologist/geophysicists and other technical personnel in our Houston office, two engineers, geologist/geophysicists and other technical personnel in our U.K. location and one engineer in our Netherlands office. We depend to a large extent on the efforts, technical expertise and continued employment of these personnel and members of our management team. If a significant number of them resign or become unable to continue in their present role and if they are not adequately replaced, our business operations could be adversely affected.

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

Members of our management team beneficially own approximately 30% of our outstanding shares of common stock as of February 20, 2007. As a result, these shareholders are in a position to significantly influence or control the outcome of matters requiring a shareholder vote, including the election of directors, the adoption of an amendment to our articles of incorporation or bylaws and the approval of mergers and other significant corporate transactions. Their control of ATP may delay or prevent a change of control of ATP and may adversely affect the voting and other rights of other shareholders.

Rapid growth may place significant demands on our resources.

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

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

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

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

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

If we have not made adequate allowances for the costs and risks associated with this expansion or if our systems, procedures or controls are not adequate to support our operations, our business could be adversely impacted.

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

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

• discharge permits for drilling operations;

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

19

• reports concerning operations; and

• taxation.

Under these laws and regulations, we could be liable for personal injuries, property damage, oil spills, discharge of hazardous materials, remediation and clean-up costs and other environmental damages. Failure to comply with these laws and regulations also may result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties. Moreover, these laws and regulations could change in ways that substantially increase our costs. Accordingly, any of these liabilities, penalties, suspensions, terminations or regulatory changes could materially adversely affect our financial condition and results of operations.

Item 1B. Unresolved Staff Comments.

None

Item 2. Properties.

General

We are engaged in the acquisition, development and production of oil and natural gas properties in the Gulf of Mexico and the North Sea. At December 31, 2006, we owned leasehold and other interests in 72 offshore blocks, 44 platforms and 112 wells, including 14 subsea wells, in the Gulf of Mexico. We operate 94 (84%) of these wells, including all of the subsea wells, and 86% of our offshore platforms. We also had interests in 11 blocks and 2 company-operated subsea wells in the North Sea. Our average working interest in our properties at December 31, 2006 was approximately 81%. As of December 31, 2006, we had leasehold interests located in the Gulf of Mexico and North Sea covering approximately 456,331 gross and 380,743 net acres, of which 257,102 gross acres were developed and 187,428 net acres were developed.

Gulf of Mexico

Acquisitions—We closed three transactions with companies for the purchase of minerals in place during 2006. These purchases, which total $30.0 million in acquisition costs, resulted in recording 136.3 Bcfe of proved reserves from acquisitions.

During the second and third quarter of 2006, we acquired in two separate transactions a 100% working interest in Mississippi Canyon Blocks 941, 942 and Atwater Valley Block 63, collectively called the Telemark Hub. At December 31, 2006, as noted above, our independent third party reservoir engineers estimated 134.9 Bcfe of proved undeveloped reserves at the Telemark Hub. In addition to the reservoirs with proved undeveloped reserves, we have identified other reservoirs which we believe could contain recoverable hydrocarbons based on previous drilling as well as selected exploratory opportunities. As of December 31, 2006, we had begun engineering and construction of a floating drilling and production facility for the Telemark Hub which is expected to be installed in mid-2008. Costs incurred, excluding acquisition costs, during 2006 at the Telemark Hub were approximately $11.0 million. We serve as operator of each of the blocks.

At Ship Shoal 351, we increased our ownership from 50% to 100% in exchange for the assumption of future abandonment liability. There are no proved reserves associated with this acquisition; however, previous drilling has indicated the presence of recoverable hydrocarbons. At December 31, 2006, we were installing a platform at Ship Shoal 351 and in February 2007 we began drilling the first of at least two planned wells. We hold a 100% working interest and serve as operator at Ship Shoal 351.

Additionally, we acquired three blocks for $4.3 million at the Gulf of Mexico Offshore Lease Sales held in 2006. Two of the blocks have been previously drilled and encountered logged hydrocarbons. We hold a 100% working interest and serve as operator of each of the blocks.

Development—On the Gulf of Mexico Shelf during 2006, five wells were drilled, all of which were successful. Four of the wells, located at West Cameron 663, High Island 74, South Marsh Island 233 and

20

West Cameron 237, were completed and placed on production in 2006. The remaining well at South Timbalier 77 is expected to be placed on production in the first half of 2007 upon completion of the platform and pipeline.

Mississippi Canyon 711 (“MC 711”) and the Gomez Hub—After delays experienced in 2005 due to Hurricanes Katrina and Rita, two wells in the southern portion of the block were placed on production late in the first quarter of 2006. A third well in the northern portion of the block was drilled and made ready for production. This well, along with another well to be drilled in the early part of 2007, is expected to be placed on production in the first half of 2007. Due to the performance of the two producing wells and the anticipated production from the new wells, plans were made in 2006 to expand the production capacity at the floating production facility that serves the Gomez Hub. This expansion is planned for mid-2007. During 2006, production from Gomez averaged approximately 70.8 MMcfe per day for its essentially nine months of production reaching a high of 117.4 MMcfe per day. We operate MC 711 with a 100% working interest.

Garden Banks 409 (“Ladybug”)—In the fourth quarter 2006, we completed a new well at Ladybug and moved up-hole to complete a behind-pipe zone in a second well. The wells at Ladybug were placed on production during February 2007.

North Sea

Acquisitions—Wenlock – During the fourth quarter of 2006, our wholly-owned subsidiary, ATP Oil & Gas (UK) Limited, or “ATP (UK),” acquired a 100% working interest in Block 49/12b in the Southern Gas Basin of the U.K. North Sea. Block 49/12b is an exploratory opportunity offsetting our Wenlock development. Wenlock is located in 75 feet of water and has been defined by two vertical wells that have tested at rates of 35 MMcf per day and 74 MMcf per day, respectively.

Development—Tors (Kilmar and Garrow) – During 2006, we drilled and placed on production two wells at Kilmar and at December 31, 2006 were drilling a third well at Tors in the Garrow reservoir. This well was completed and placed on production during February 2007. Previously in 2006, we completed the installation of the platform at Garrow and connected the 23-kilometer pipeline from Garrow to Kilmar. During 2006, we increased North Sea production by 10.9 Bcfe to 12.2 Bcfe, primarily due to the new production from Tors field, which we operate with an 85% working interest.

L-06d—On February 27, 2006, we announced first production at L-06d in the Dutch North Sea. With that achievement, ATP recorded flowing production in all three of its core areas: the U.S. Gulf of Mexico, the U.K. North Sea, and Dutch North Sea. ATP operates L-06d with a 50% working interest.

Significant Properties

The following table sets forth additional information on our most significant properties as of December 31, 2006:

Field	Development Location	Net Total Proved Reserves MMcfe	2006 Net Production MMcfe	Average WI%	Expected First Production
Cheviot	N. Sea	180,545	—	100.0	2009
King’s Peak(1)	GOM	30,839	2,661	55.0	Shut-in
Mississippi Canyon 711	GOM	116,515	21,019	100.0	Producing
South Timbalier 77	GOM	13,602	1,674	78.0	Producing
Telemark Hub	GOM	134,934	—	100.0	2008
Tors	N. Sea	64,959	7,364	85.0	Producing

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

Oil and Natural Gas Reserves

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

21

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

The following table presents our estimated net proved oil and natural gas reserves at December 31, 2006 based on reserve reports prepared by Ryder Scott Company, L.P., Collarini Associates and DeGolyer and MacNaughton for our Gulf of Mexico reserves, Ryder Scott Company, L.P. for our Netherlands reserves and RPS Energy for our U.K. reserves.

	Proved Reserves
	Developed	Undeveloped	Total
Gulf of Mexico
Natural gas (MMcf)	83,099	73,891	156,990
Oil and condensate (MBbls)	13,839	19,886	33,725
Total proved reserves (MMcfe)	166,135	193,204	359,339
North Sea
Natural gas (MMcf)	47,695	124,541	172,236
Oil and condensate (MBbls)	3	17,547	17,550
Total proved reserves (MMcfe)	47,711	229,823	277,534
Total
Natural gas (MMcf)	130,794	198,432	329,226
Oil and condensate (MBbls)	13,842	37,433	51,275
Total proved reserves (MMcfe)	213,846	423,027	636,873

At December 31, 2006 our standardized measure of discounted future net cash flows was $1.015 billion. The present value of future net 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, 2006. PV-10 may be considered a non-GAAP financial measure under the SEC’s regulations. We believe PV-10 to be an important measure for evaluating the relative significance of our natural gas and oil properties. PV-10 is computed on the same basis as the standardized measure of discounted future net cash flows but without deducting income taxes. We further believe investors and creditors may utilize our PV-10 as a basis for comparison of the relative size and value of our reserves to other companies. However, PV-10 is not a substitute for the standardized measure. Our PV-10 measure and the standardized measure of discounted future net cash flows (shown below in thousands) do not purport to present the fair value of our natural gas and oil reserves.

Net present value of future cash flows, before income taxes	$	1,278,607
Future income taxes, discounted at 10%		(263,529	)
Standardized measure of discounted future net cash flows	$	1,015,078

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

22

Drilling Activity

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

	Gulf of Mexico			North Sea
	2006	2005	2004	2006	2005	2004
Gross Development Wells:
Productive	3.0	4.0	10.0	2.0	1.0	—
Nonproductive	—	—	2.0	—	1.0	—
Total	3.0	4.0	12.0	2.0	2.0
Net Development Wells:
Productive	2.8	3.4	6.7	1.7	0.5	—
Nonproductive	—	—	1.5	—	0.8	—
Total	2.8	3.4	8.2	1.7	1.3
Gross Exploratory Wells:
Productive	4.0	3.0	3.0	—	—	—
Nonproductive	—	1.0	—	—	—	—
Total	4.0	4.0	3.0		—	—
Net Exploratory Wells:
Productive	2.2	3.0	1.3	—	—	—
Nonproductive	—	0.8	—	—	—	—
Total	2.2	3.8	1.3		—	—
Total Gross Wells:
Productive	7.0	7.0	13.0	2.0	1.0	—
Nonproductive	—	1.0	2.0	—	1.0	—
Total	7.0	8.0	15.0	2.0	2.0	—
Total Net Wells:
Productive	5.0	6.4	8.0	1.7	0.5	—
Nonproductive	—	0.8	1.5	—	0.8	—
Total	5.0	7.2	9.5	1.7	1.3	—

At December 31, 2006 we had 1.0 gross development well (0.9 net development well) in the North Sea and 1.0 gross exploratory well (1.0 net exploratory well) in the Gulf of Mexico in the process of being drilled. As noted above, these two wells came on production during February 2007.

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, 2006:

	Gulf of Mexico	North Sea	Total
Gross
Gas	30.0	5.0	35.0
Oil	9.0	—	9.0
Total	39.0	5.0	44.0
Net
Gas	19.3	3.7	23.0
Oil	4.8	—	4.8
Total	24.1	3.7	27.8

23

Acreage

The following table summarizes our developed and undeveloped acreage holdings at December 31, 2006. 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	213,728	156,171	126,469	123,877	340,197	280,048
North Sea	43,374	31,257	72,760	69,438	116,134	100,695
Total	257,102	187,428	199,229	193,315	456,331	380,743

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

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

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

Year Ended December 31:	Gulf of Mexico		North Sea		Total
	Gross	Net	Gross	Net	Gross	Net
2007	15,008	15,008	48,436	45,114	63,444	60,122
2008	14,414	14,414	—	—	14,414	14,414
2009	25,207	22,615	—	—	25,207	22,615
2010 & Beyond	71,840	71,840	24,324	24,324	96,164	96,164
Total	126,469	123,877	72,760	69,438	199,229	193,315

Production and Pricing Data

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

Item 3. Legal Proceedings.

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

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

No matters were submitted to a vote of security holders during the fourth quarter of 2006.

24

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 30,198,970 shares of common stock and no shares of preferred stock outstanding as of February 20, 2007. Our common stock is traded on the NASDAQ Global Select Market under the ticker symbol ATPG.

The following table sets forth the range of high and low sales prices for the common stock as reported on the NASDAQ National Market for the periods indicated below. Such over-the-counter market quotations reflect inter-dealer prices, without retail mark-up, mark-down or commission and may not necessarily represent actual transactions.

	High		Low
2006:
4th Quarter	$	47.29	$	34.16
3rd Quarter		43.30		35.35
2nd Quarter		49.70		35.04
1st Quarter		44.05		36.05
2005:
4th Quarter	$	39.20	$	27.91
3rd Quarter		34.00		23.51
2nd Quarter		24.62		17.86
1st Quarter		26.55		16.76

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

Shareholder Return Performance Presentation

The information set forth in the graph and table below compares the value of ATP’s Common Stock to the NASDAQ Market Index and to a “Peer Group Index”, which is comprised of the following eight independent oil and gas exploration and production companies with operations and assets focused in the Gulf of Mexico region: Energy Partners, Ltd., Houston Exploration Company, Newfield Exploration Company, Noble Energy Inc., Pogo Producing Company, Remington Oil and Gas Corporation (“Remington”) through 12/31/05, Helix Energy Solutions Group Inc. (successor to Remington) for 2006 only, Stone Energy Corporation and Callon Petroleum Company.

Each of the total cumulative returns presented assumes a $100 investment beginning February 6, 2001, the date ATP commenced trading, and ending December 31, 2006. 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	12/31/01	12/31/02	12/31/03	12/31/04	12/31/05	12/31/06
ATP Oil & Gas Corporation	100.00	136.58	210.74	623.83	1,241.95	1,327.85
Peer Group Index	100.00	106.16	132.26	170.34	214.82	218.41
NASDAQ Market Index	100.00	69.75	104.88	113.70	116.19	128.12

25

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,
	2006			2005			2004			2003			2002
Statement of Operations Data:
Revenues:
Oil and gas production	$	414,182		$	146,674		$	116,123		$	70,151		$	80,017
Other revenues (1)		5,639			—			—			—			—
		419,821			146,674			116,123			70,151			80,017
Cost and operating expenses:
Lease operating expenses		72,446			23,629			19,531			17,173			16,764
Exploration expenses		2,231			6,208			997			1,358			154
General and administrative		21,499			24,274			15,806			12,209			10,037
Stock-based compensation (2)		11,477			57			—			(39	)		595
Credit facility costs		—			—			1,850			1,990			250
Depreciation, depletion and amortization		169,704			64,069			55,637			29,378			43,390
Impairment of oil and gas properties		19,520			—			—			11,670			6,844
Accretion		8,076			3,238			2,069			2,752			—
(Gain) loss on abandonment		9,603			(732	)		(251	)		4,973			—
Loss on unsuccessful property acquisition (3)		—			—			—			8,192			—
Gain on disposition of properties		—			(2,743	)		(6,011	)		—			—
Other		—			—			400			—			—
Total operating expenses		314,556			118,000			90,028			89,656			78,034
Income (loss) from operations		105,265			28,674			26,095			(19,505	)		1,983
Other income (expense):
Interest income		4,532			4,064			627			52			73
Interest expense		(58,018	)		(35,720	)		(22,262	)		(9,678	)		(10,418	)
Loss on extinguishment of debt		(28,115	)		—			(3,326	)		(3,352	)		—
Other income		7			419			280			2,244			1,081
Income (loss) before income taxes and cumulative effect of change in accounting principle		23,671			(2,563	)		1,414			(30,239	)		(7,281	)
Income tax (expense) benefit		(16,794	)		(153	)		(58	)		(21,224	)		2,581
Income (loss) before cumulative effect of change in accounting principle		6,877			(2,716	)		1,356			(51,463	)		(4,700	)
Cumulative effect of change in accounting principle, net of tax (4)		—			—			—			662			—
Net income (loss)	$	6,877		$	(2,716	)	$	1,356		$	(50,801	)	$	(4,700	)
Preferred dividends		(46,225	)		(9,858	)		—			—			—
Net income (loss) available to common shareholders	$	(39,348	)	$	(12,574	)	$	1,356		$	(50,801	)	$	(4,700	)
Weighted average number of common shares outstanding:
Basic		29,693			29,080			24,944			22,975			20,315
Diluted		29,693			29,080			25,271			22,975			20,315
Basic and diluted net income (loss) per share available to common:
Income (loss) before cumulative effect of change in accounting principle	$	(1.33	)	$	(0.43	)	$	0.05		$	(2.24	)	$	(0.23	)
Cumulative effect of change in accounting principle, net of tax		—			—			—			0.03			—
Net income (loss) available to common shareholders		(1.33	)		(0.43	)		0.05			(2.21	)		(0.23	)

26

	Year Ended December 31,
	2006		2005		2004		2003			2002
Balance Sheet Data:
Cash and cash equivalents	$	182,592	$	65,566	$	102,774	$	4,564		$	6,944
Working capital (deficit)		77,504		567		68,330		(46,423	)		(13,699	)
Net oil and gas properties		1,095,645		627,421		213,206		189,125			119,036
Total assets		1,447,058		823,763		372,147		217,685			182,055
Long-term debt, including current maturities		1,071,441		340,989		210,309		115,409			86,387
Capital lease, including current maturities		23,699		43,116		—		—			—
Total liabilities		1,411,140		606,252		314,983		213,353			143,508
Shareholders’ equity		35,918		217,511		57,164		4,332			38,547

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

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

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

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

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

Executive Overview

General

ATP Oil & Gas Corporation is engaged in the acquisition, development and production of oil and natural gas properties in the Gulf of Mexico and the North Sea. We seek to acquire and develop properties with proved undeveloped reserves (“PUD”) that are economically attractive to us but are not strategic to major or large exploration-oriented independent oil and gas companies. Occasionally we will acquire properties that are already producing or where previous drilling has encountered reservoirs that appear to us to contain commercially productive quantities of oil and gas even though the reservoirs do not meet the SEC definition of proved reserves. We believe that our strategy provides assets for us to develop and produce without the risk, cost or time of traditional exploration.

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

• significant undeveloped reserves and reservoirs;

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

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

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

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

We focus on developing projects in the shortest time possible between initial significant investment and first revenue generated in order to maximize our rate of return. Since we operate a significant number of the properties in which we acquire a working interest, we are able to significantly influence the development concept and timing of a project’s development. We typically initiate new development projects by

27

simultaneously obtaining the various required components such as the pipeline and the production platform or subsea well completion equipment. We believe this strategy, combined with our strong technical abilities to evaluate and implement a project’s requirements, allows us to efficiently complete the development project and commence production.

To enhance the economics and return on investment of a project, we sometimes develop the project to a value creation point and either sell an interest or bring in partners on a promoted basis during the high capital development phase. In 2004 we sold 25% of our interest in seven projects containing ten offshore blocks in the Gulf of Mexico for $19.5 million, approximately $1.85 per Mcfe for proved reserves, of which 93.5% were proved undeveloped reserves. In 2005 we sold a 15% interest on a promoted basis in our Tors project in the U.K. Sector of the North Sea after the field development plan was obtained.

Review of 2006

The year 2006 was another year of major growth in proved reserves and a step change in production rates for ATP. The growth in reserves was accomplished primarily through acquisitions (136.3 Bcfe) during a period of historically high oil and gas prices. Also of significance in 2006 was a marked increase in proved developed reserves, growing from 128.4 Bcfe at the end of 2005 to 213.8 Bcfe at December 31, 2006. Our growth in production from an average of 55 MMcfe per day during 2005 to an average of 139 MMcfe per day during 2006 was primarily a result of new production from our Mississippi Canyon 711 (Gomez) project in the Gulf of Mexico and our Tors project in the North Sea.

Reserves

At December 31, 2006, we had proved reserves of 636.9 Bcfe, of which 56% are located in the Gulf of Mexico and the remaining 44% are in the North Sea. The pre-tax PV-10 of our proved reserves at December 31, 2006 was $1.3 billion. See “Item 2. Properties—Oil and Natural Gas Reserves” for reconciliation to our after-tax PV-10 of $1.0 billion. In addition, we have scheduled for drilling or completion, properties where previous drilling into the targeted reservoirs indicates to the Company the presence of commercially productive quantities of hydrocarbons even though the reservoirs do not meet the SEC definition of proved reserves. Upon completion of drilling, completion or testing of wells on these blocks and similar properties in the Company’s portfolio, the Company anticipates that it may be able to record proved reserves associated with several of these properties.

Acquisitions—Gulf of Mexico

We closed three transactions with companies for the purchase of minerals in place during 2006. These purchases, which total $30.0 million in acquisition costs, resulted in recording 136.3 Bcfe of proved reserves from acquisitions.

During the second and third quarter of 2006, ATP acquired in two separate transactions a 100% working interest in Mississippi Canyon Blocks 941, 942 and Atwater Valley Block 63, collectively called the Telemark Hub. At December 31, 2006, as noted above, ATP’s independent third party reservoir engineers estimated 134.9 Bcfe of proved undeveloped reserves at the Telemark Hub. In addition to the reservoirs with proved undeveloped reserves, ATP has identified other reservoirs which it believes could contain recoverable hydrocarbons based on previous drilling as well as selected exploratory opportunities. As of December 31, 2006, ATP had begun engineering and construction of a floating drilling and production facility for the Telemark Hub which is expected to be installed in mid-2008. Costs incurred excluding acquisition costs during 2006 at the Telemark Hub were approximately $11.0 million. We serve as operator of each of the blocks.

At Ship Shoal 351, we increased our ownership from 50% to 100% in exchange for the assumption of future abandonment liability. There are no proved reserves associated with this acquisition; however, previous drilling has indicated the presence of recoverable hydrocarbons. At December 31, 2006, we were installing a platform at Ship Shoal 351 and in February 2007 we began drilling the first of at least two planned wells. We hold a 100% working interest and serve as operator at Ship Shoal 351.

28

Additionally, we acquired three blocks for $4.3 million at the Gulf of Mexico Offshore Lease Sales held in 2006. Two of the blocks have been previously drilled and encountered logged hydrocarbons. We hold a 100% working interest and serves as operator of each of the blocks.

Acquisitions—North Sea

Wenlock—During the fourth quarter of 2006, ATP (UK) acquired a 100% working interest in Block 49/12b in the Southern Gas Basin of the U.K. North Sea. Block 49/12b is an exploratory opportunity offsetting our Wenlock development. Wenlock is located in 75 feet of water and has been defined by two vertical wells that have tested at rates of 35 MMcf per day and 74 MMcf per day. During 2006 we designed and constructed a production platform at Wenlock and installed a pipeline to the host platform. Drilling and subsequent production is planned at Wenlock for the first half of 2007 with development at Block 49/12b scheduled for 2008.

Operations, Development and Production

Gulf of Mexico Shelf—On the Gulf of Mexico Shelf during 2006, five net wells were drilled and all were successful. Four of the wells at West Cameron 663, High Island 74, South Marsh Island 233 and West Cameron 237 were completed and placed on production in 2006. The remaining well at South Timbalier 77 is expected to be placed on production in the first half of 2007 upon completion of the platform and pipeline.

MC 711 and the Gomez Hub—After delays experienced in 2005 due to Hurricanes Katrina and Rita, two wells in the southern portion of the block were placed on production late in the first quarter of 2006. A third well in the northern portion of the block was drilled and made ready for production. This well, along with another well to be drilled in the early part of 2007, are expected to be placed on production in the first half of 2007. Due to the performance of the two producing wells and the anticipated production from the new wells, plans were made in 2006 to expand the production capacity at the ATP Innovator, the floating production facility that serves the Gomez Hub. This expansion is planned for 2007. During 2006, production from Gomez averaged approximately 70.8 MMcfe per day for its essentially nine months of production reaching a high of 117.4 MMcfe per day. ATP operates MC 711 with a 100% working interest.

Ladybug—In the fourth quarter 2006, we completed a new well at Ladybug and moved up hole to complete a behind pipe zone in a second well. During February 2007, the wells at Ladybug were placed on production.

Development—Tors (Kilmar and Garrow)—During 2006, we drilled and placed on production two wells at Kilmar and at December 31, 2006 were drilling a third well at Tors in the Garrow reservoir. This well was completed and placed on production during February 2007. Previously in 2006, we completed the installation of the platform at Garrow and connected the 23-kilometer pipeline from Garrow to Kilmar. During 2006, we increased North Sea production by 10.9 Bcfe to 12.2 Bcfe, primarily due to the new production from Tors field, which we operate with an 85% working interest.

L-06d—On February 27, 2006, we announced first production at L-06d in the Dutch North Sea. With that achievement, ATP recorded flowing production in all three of its core areas: the U.S. Gulf of Mexico, the U.K. North Sea, and Dutch North Sea. ATP operates L-06d with a 50% working interest.

Financings

The acquisitions, significant increase in proved reserves and proved developed reserves coupled with additional recoverable hydrocarbons identified by ATP and the increase in production allowed us to complete three new financings in 2006. During the first quarter, we issued $150.0 million of 12.5% non-convertible perpetual preferred stock, which raised net proceeds of $145.5 million. During the second quarter, we amended

29

and improved the terms of our Senior Secured Credit Facility by expanding it to $525.0 million and reducing the interest rate. Net of transaction costs, this amendment added $167.7 million in additional liquidity.

In the fourth quarter, we redeemed all of our outstanding preferred shares by expanding our first lien term loan by $375.0 million, adding a new revolving credit facility for up to $50.0 million and adding a new second lien facility of $175.0 million. Subsequent to the closings, ATP has first lien debt of $898.7 million at a rate of LIBOR plus 3.5% with a maturity of April 14, 2010, an additional $50.0 million revolving credit facility with a rate of LIBOR plus 3.5% with a maturity of October 14, 2009, and a new second lien tranche of $175.0 million at a rate of LIBOR plus 4.75% with a maturity of October 14, 2010. The collateral package for these facilities is similar to the previous first lien facility. The new financings added $155.5 million in additional liquidity and reduced the overall cost of capital (preferred dividends plus interest) by approximately 200 basis points.

Cash flow from operating activities was $258.5 million for the year ended December 31, 2006, compared to $43.6 million in 2005. We had working capital at December 31, 2006 of $77.5 million, an increase of approximately $76.9 million from December 31, 2005. This increase is primarily attributable to fourth quarter 2006 financings discussed in the previous paragraph.

We had $182.6 million in cash and cash equivalents on hand at December 31, 2006, compared to $65.6 million at December 31, 2005. Cash paid for acquisition and development activities for the year 2006 was $577.0 million, compared to $420.5 million in 2005.

2007 Operational and Financial Objectives

We will continue to pursue acquisitions that meet our criteria as well as devote considerable resources to our developments in 2007. In January 2007, we acquired additional blocks at our Gomez Hub and at our King’s Peak/Canyon Express Hub. The Gomez Hub addition is expected to add proved undeveloped reserves, an interest in two adjacent blocks and a commitment to process up to a designated amount of production from these two blocks beginning in 2009. The blocks at our King’s Peak/Canyon Express Hub included an increase in our ownership percentage in the Canyon Express Pipeline System and one producing property, which will add proved reserves. The technical evaluation of these properties is being refined and no reserves from these 2007 acquisitions were included in our year-end 2006 reserve report.

During 2007, efforts will be spent completing and bringing to production at least two more wells at Gomez, the wells at Ship Shoal 351 and South Timbalier 77. As noted earlier, the third well at Tors (the Garrow #1) and the two wells at Ladybug began producing during February 2007.

In addition to these developments, we have projects with proved undeveloped reserves at December 31, 2006 that are scheduled for 2007 development and production. We also have scheduled for drilling or completion properties in which previous drilling into targeted reservoirs indicates to the Company the presence of commercially productive quantities of hydrocarbons, although these reservoirs did not meet the SEC definition of proved reserves at the end of 2006. For example, the previously discussed Ship Shoal 351 is a property that the Company believes to have commercially productive hydrocarbons that is not included in our year-end 2006 reserve report.

We have commenced engineering and procurement activities on our Cheviot property in the U.K. North Sea. Cheviot, our largest property in terms of proved reserves, is a multi-year development with first production targeted in late 2009 or 2010. We have also begun engineering, procurement and construction at our Telemark Hub in the Gulf of Mexico. Installation of the floating drilling and production facility is planned for mid-2008 with first anticipated production in late 2008 or early 2009. Other potential developments for 2007 in the Gulf of Mexico and North Sea are currently being evaluated. We believe that 2007 production will exceed that of 2006 as a result of our recent development programs and projects scheduled for development in 2007.

30

Our production may command lower realized oil and gas prices in 2007 than in recent years as a result of current strip prices compared to recent years. Our 2007 hedge prices are currently in excess of many of the 2007 strip prices which should provide a realized price in excess of the strip prices for those volumes covered by hedges, if prices do not increase. Our revenues, profitability and cash flows are highly dependent upon many factors, particularly our production results and the price of oil and natural gas. To mitigate future price volatility, we may hedge additional production.

Results of Operations

For the years ended December 31, 2006 and 2005, we reported net loss available to common shareholders of $39.3 million and $12.6 million, or $1.33 and $0.43 per share, respectively, and for the year ended December 31, 2004 we reported net income available to common shareholders of $1.4 million or $0.05 per share.

Oil and Gas Revenues

Revenues presented in the table and the discussion below represent revenues from sales of our oil and natural gas production volumes. Production sold under fixed price delivery contracts, which have been designated for the normal purchase and sale exemption under SFAS 133, are also included in these amounts. Approximately 67%, 61% and 47% of our oil production was sold under these contracts for the years ended December 31, 2006, 2005 and 2004, respectively. Approximately 19%, 54% and 46% of our natural gas production was sold under these contracts for the comparable periods. The realized prices below may differ from the market prices in effect during the periods depending on when the fixed price delivery contract was executed.

	Year Ended December 31,								% Change from 2005 to 2006		% Change from 2004 to 2005
	2006			2005		2004
Production:
Natural gas (MMcf)		31,224			15,614		17,816		100	%	(12	%)
Oil and condensate (MBbls)		3,273			717		765		356	%	(6	%)
Total (MMcfe)		50,860			19,914		22,408		155	%	(11	%)
Revenues from production (in thousands):
Natural gas	$	234,035		$	116,404	$	91,251		101	%	28	%
Effects of cash flow hedges		2,479			40		(1,198	)	6098	%	103	%
Total	$	236,514		$	116,444	$	90,053		103	%	29	%
Oil and condensate	$	180,713		$	30,041	$	25,970		502	%	16	%
Effects of cash flow hedges		(3,155	)		—		—		(100	%)	—
Total	$	177,558		$	30,041	$	25,970		491	%	16	%
Natural gas, oil and condensate	$	414,748		$	146,445	$	117,221		183	%	25	%
Effects of cash flow hedges		(676	)		40		(1,198	)	(1790	%)	103	%
Total	$	414,072		$	146,485	$	116,023		183	%	26	%
Average realized sales price per unit:
Natural gas (per Mcf)	$	7.50		$	7.46	$	5.12		—		46	%
Effects of cash flow hedges (per Mcf)		0.07			—		(0.07	)	100	%	100	%
Average realized price (per Mcf)	$	7.57		$	7.46	$	5.05		1	%	48	%
Oil and condensate (per Bbl)	$	55.21		$	41.90	$	33.93		32	%	24	%
Effects of cash flow hedges (per Bbl)		(0.96	)		—		—		(100	%)	—
Average realized price (per Bbl)	$	54.25		$	41.90	$	33.93		29	%	24	%
Natural gas, oil and condensate (per Mcfe)	$	8.15		$	7.35	$	5.23		11	%	41	%
Effects of cash flow hedges (per Mcfe)		(0.01	)		—		(0.05	)	(100	%)	100	%
Average realized price (per Mcfe)	$	8.14		$	7.35	$	5.18		11	%	42	%

Oil and gas revenue increased 183% in 2006 compared to 2005 primarily as a result of increased production volumes and a stronger oil price. Natural gas volumes increased 100% and oil and condensate

31

volumes increased more than three-fold. Our realized sales price per Mcfe in 2006 was 11% higher as compared to 2005.

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

Other Revenues

Other revenues for the year ended December 31, 2006 are comprised of amounts realized under our Loss of Production Income insurance policy as a result of disruptions caused by the 2005 hurricanes.

Lease Operating

Lease operating expenses include costs incurred to operate and maintain wells and related equipment and facilities. These costs include, among others, workover expenses, operator fees, processing fees, insurance and transportation. Lease operating expense for the years ended December 31, 2006, 2005 and 2004 was as follows ($ in thousands):

	Year Ended December 31,						% Change from 2005 to 2006		% Change from 2004 to 2005
	2006		2005		2004
Lease operating	$	72,446	$	23,629	$	19,531	207	%	21	%
Per Mcfe	$	1.42	$	1.19	$	0.87	19	%	37	%

The 207% increase in 2006 compared to 2005 was primarily attributable to costs incurred in the Gulf of Mexico due to the increased production levels in 2006 compared to 2005. The 19% increase in such costs on a per unit basis reflects the price spikes we experienced for materials and labor in the Gulf of Mexico after the 2005 hurricanes.

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

Exploration

During 2006, exploration expense includes the costs of geological and geophysical studies totaling approximately $2.2 million. Exploration expense in 2005 included the dry hole costs of a step-out well at our producing Eugene Island 30/71 complex. This well found non-commercial quantities of hydrocarbons, resulting in exploration and dry hole expense of approximately $5.3 million in 2005.

General and Administrative

General and administrative expenses are overhead-related expenses, including among others, wages and benefits, legal and accounting fees, insurance, and investor relations expenses. General and administrative expense for the years ended December 31, 2006, 2005 and 2004 was as follows ($ in thousands):

	Year Ended December 31,						% Change from 2005 to 2006		% Change from 2004 to 2005
	2006		2005		2004
General and administrative	$	21,499	$	24,274	$	15,806	(11	%)	54	%
Per Mcfe	$	0.42	$	1.22	$	0.71	(66	%)	72	%

The decrease in 2006 compared to 2005 was primarily due to the prior year inclusion of the ATP Employee Volvo Challenge and other compensation related costs.

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

32

Credit Facility Cost

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

Depreciation, Depletion and Amortization

Depreciation, depletion and amortization expense (“DD&A”) for the years ended December 31, 2006, 2005 and 2004 was as follows ($ in thousands):

	Year Ended December 31,						% Change from 2005 to 2006		% Change from 2004 to 2005
	2006		2005		2004
DD&A	$	169,704	$	64,069	$	55,637	165	%	15	%
Per Mcfe	$	3.34	$	3.22	$	2.48	4	%	30	%

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

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

Impairments

We recorded an impairment of oil and gas properties for 2006 totaling $19.5 million related to certain producing properties acquired during 2005 and a few smaller end-of-life properties and one unproved property in the Gulf of Mexico. This amount represents the excess carrying costs over the discounted present values of the estimated future production from those properties. These impairments were the result of reductions in estimates of recoverable reserves. Restoration of a previously recognized impairment loss is prohibited.

(Gain) Loss on Abandonment

During 2006, we recognized an aggregate loss on abandonment of $9.6 million covering eighteen properties. The losses were the result of actual abandonment costs exceeding the previously accrued estimates, due to unforeseen circumstances that required additional work or the use of equipment more expensive than anticipated, and vendor price increases.

During 2005 and 2004, we recognized small net gains on the abandonment of certain properties which we were able to abandon at an aggregate cost less than the asset retirement obligation previously accrued.

(Gain) Loss on Disposition of Properties

During 2005 we recognized a net gain of $2.7 million on the sales of 15% of our interest in Tors fields in the Southern Gas Basin of the U.K. Sector—North Sea and one property in the Gulf of Mexico. In 2004, we sold 25% of our interest in seven projects containing ten offshore blocks in the Gulf of Mexico and recognized a gain of $6.0 million.

Interest Income

Interest income varies directly with the amount of temporary cash investments. The increase in interest income from period to period is the result of the increase in cash on hand from the Company’s aforementioned funding activities.

Interest Expense

Interest expense increased $22.3 million, to $58.0 million for 2006 from $35.7 million for 2005 as a result of an increase in outstanding borrowings under the Term Loans, partially offset by a lower average effective floating interest rate on such borrowings.

33

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

Loss on Extinguishment of Debt

In the fourth quarter of 2006, we recognized a noncash loss of $28.1 million on the extinguishment of debt related to our prior credit agreement, including deferred financing costs of $23.2 million and unamortized debt discount of $4.9 million.

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

Income Taxes

During 2006 we recognized current tax expense of $2.5 million primarily due to our Netherlands operations and alternative minimum tax on our U.S. net income before dividends. We recognized $14.3 million of deferred tax expense related to our U.K. and Netherlands operations.

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

Preferred Dividends

We recognized and paid $46.2 million of dividends during 2006 related to the Series A 13.5% and Series B 12.5% cumulative perpetual preferred stock, issued during August 2005 and March 2006, respectively. This amount included approximately $9.3 million of prepayment premium paid to the holders of such preferred stock when all of the shares were redeemed in November 2006.

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

Liquidity and Capital Resources

At December 31, 2006, we had working capital of approximately $77.5 million, an increase of approximately $76.9 million from December 31, 2005. This increase is primarily attributable to the increase in our cash flows from operations coupled with the success of our financing programs during 2006, partially offset by higher amounts spent on capital projects and the redemption of our Series A and Series B preferred stock. Historically, we have financed our acquisition and development activities through a combination of bank borrowings and proceeds from our equity offerings as well as cash from operations and by the sell-down of a portion of our interests in selected development projects. During 2006, we completed several major projects which required significant capital expenditures through the end of the year. In order to fund these development costs, we completed a private placement of preferred stock for net proceeds of $145.5 million, and expanded our Term Loan in June and in November 2006 for an additional $167.7 million and $536.3 million, respectively, net of related costs. As operator of all of our projects in development, we have the ability to significantly control the timing of most of our capital expenditures. We believe the cash flows from operating activities, new or amended debt or equity offerings combined with our ability to control the timing of substantially all of our future development and acquisition requirements will provide us with the flexibility and liquidity to meet our future planned capital requirements.

34

Cash Flows

	Year Ended December 31,
	2006		2005			2004
Cash provided by (used in):
Operating activities	258,514		$	43,588		$	41,218
Investing activities	(590,683	)		(414,072	)		(68,651	)
Financing activities	447,991			335,514			125,698

Operating activities. Net cash provided by operating activities was $258.5 million for the year ended December 31, 2006 compared to $43.6 million for the year ended December 31, 2005. Cash flow from operations increased primarily due to a 155% increase in equivalent production volumes and an overall 11% increase in average realized prices per Mcfe. Gas sales, including the effects of hedging, increased by $120.0 million, or 103%, due mainly to 100% higher production volumes. Oil sales, including the effects of hedging, increased by $147.5 million, or 491%, due to a 356% increase in production volumes and a 29% increase in the average price realized for oil.

Investing activities. Cash used in investing activities in 2006 and 2005 was $591.0 million and $414.1 million, respectively, and included increases in restricted cash of $13.3 million and $12.5 million, respectively. Cash paid for acquisition, development and exploration expenditures of oil and natural gas properties in the Gulf of Mexico and North Sea totaled approximately $356.0 million and $221.0 million, respectively, in 2006. Such expenditures in the Gulf of Mexico and North Sea were approximately $296.1 million and $124.4 million, respectively, in 2005, offset by the receipt of $19.8 million in proceeds for the sale of properties.

Financing activities. Cash provided by financing activities in 2006 consisted primarily of net proceeds of $703.9 million related to our Term Loans, after deducting deferred financing costs of approximately $24.6 million related to the First Lien Term Loans, and net proceeds of $145.5 million from the issuance of preferred stock, partially offset by $381.1 million paid to redeem our preferred stock. Cash provided by financing activities in 2005 consisted primarily of net proceeds of $121.7 million related to our amendment to the Term Loan, after deducting deferred financing costs of approximately $10.4 million related to the amendment and accrued interest and $169.4 million from the issuance of preferred stock, net of issuance costs.

The Company’s restricted cash represents time deposits denominated in Pounds Sterling which secures irrevocable stand-by letters of credit for our future abandonment obligations with respect to the Tors (Garrow) and Wenlock properties in the North Sea. The Letters of Credit and Reimbursement Agreements were entered into in July 2005 and August 2006, each with an initial term of one year, to be extended for successive one-year terms unless thirty days notice is given of the intention not to extend.

Term Loans

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

	Year Ended December 31,
	2006			2005
First Lien Term Loans, net of unamortized discount of $0 and $6,386	$	896,441		$	340,989
Second Lien Term Loan		175,000			—
Total		1,071,441			340,989
Less current maturities		(8,987	)		(3,500	)
Total long-term debt	$	1,062,454		$	337,489

On November 22, 2006, the Company, the lenders named therein and Credit Suisse (as Administrative Agent and Collateral Agent for such lenders) entered into Amendment No. 1 and Agreement (the “Amendment”) amending the Second Amended and Restated Credit Agreement dated as of June 22, 2006; the Company, the lenders named therein and Credit Suisse (as Administrative Agent and Collateral Agent for such lenders) entered into the Second Lien Credit Agreement; and the Company, ATP Energy, Inc. and Credit Suisse (as Collateral Agent under the Previous First Lien Credit Agreement and under the Second Lien Credit Agreement) entered into an Intercreditor Agreement. Under the Second Lien Credit Agreement, the Company has second lien term loans of $175.0 million. The Second Lien Term Loans bear interest at LIBOR plus 4.75% and mature in October 2010.

35

With the Amendment, we increased our aggregate borrowings under the Previous First Lien Credit Agreement by $375.0 million. We also borrowed $175.0 million under the Second Lien Credit Agreement. From this increase in borrowings, we received net proceeds of $536.3 million, after deducting $13.7 million for fees and expenses. The net proceeds were used by the Company: (a) to redeem the Series A Preferred Stock (as defined in Note 7 below), which had an original face amount of $175.0 million; (b) to redeem the Series B Preferred Stock (as defined in Note 7 below), which had an original face amount of $150.0 million; and (c) for general corporate purposes. Concurrent with the Amendment, we incurred a noncash charge of approximately $28.1 million related to the capitalized costs of the Previous First Lien Credit Agreement and approximately $9.3 million of costs related to calling and retiring all of the preferred shares.

On December 28, 2006, the Company, the lenders named therein and Credit Suisse (as Administrative Agent and Collateral Agent for such lenders) entered into the First Lien Credit Agreement. Under the First Lien Credit Agreement, the Company has first lien term loans for $900.0 million and a revolving credit and letter of credit facility in an amount not to exceed $50.0 million at any time outstanding. The First Lien Term Loans bear interest at LIBOR plus 3.5% and mature in April 2010. The Revolver, under which no amounts were outstanding as of December 31, 2006, bears interest at LIBOR plus 3.5% and matures in October 2009.

At December 31, 2006, our borrowings were secured by substantially all of our oil and gas assets in the Gulf of Mexico and a pledge of 65% of the common stock of our wholly owned subsidiaries, ATP (UK) and ATP Oil & Gas (Netherlands) B.V., were guaranteed by our wholly owned subsidiary ATP Energy, Inc., and bore interest at a weighted average rate of approximately 9.13%.

The terms of the Term Loans and the Revolver require us to maintain certain covenants. Capitalized terms are defined in the First Lien Credit Agreement and the Second Lien Credit Agreement. The covenants include:

• Minimum Current Ratio of 1.0 to 1.0;

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

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

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

• Ratio of pre-tax PV-10 of our Total Proved oil and gas reserves plus 50% of our pre-tax probable oil and gas reserves, both adjusted for current oil and gas price estimates, to Net Debt of at least 3.0 to 1.0 at June 30 or December 31 of any fiscal year;

• Maximum Commodity Hedging Agreements on no more than 80% of the forecasted production attributable to our proved producing reserves for the period for which such hedges are in effect;

• limit during any fiscal year Permitted Business Investments, as defined, to $150.0 million or 7.5% of PV-10 value of our total proved reserves.

As of December 31, 2006, we were in compliance with all of the financial covenants of our Term Loans. Significant adverse changes in our expected production levels, commodity prices and reserves or material delays or cost overruns could have a material adverse affect on our financial condition and results of operations and result in our non-compliance with these covenants. An event of non-compliance with any of the required covenants could result in a material mandatory repayment under the Term Loans.

The foregoing description of the First Lien Credit Agreement and the Second Lien Credit Agreement is qualified in its entirety by reference to the First Lien Credit Agreement and the Second Lien Credit Agreement filed as exhibits to this report and incorporated by reference herein. In addition, capitalized terms used but not defined in the foregoing description have the respective meanings assigned to such terms in the First Lien Credit Agreement and the Second Lien Credit Agreement.

In connection with the original issuance of the term loans during 2004, we granted warrants to purchase 2,452,336 shares of common stock of ATP for $7.25 per share, 525,499 of which remain outstanding at

36

December 31, 2006. The warrants have a term of six years and expire in March 2010. The fair value of the warrants, as determined by use of the Black-Scholes valuation model on March 29, 2004, was approximately $4.2 million and was accounted for as additional paid-in-capital and debt discount. The fair value was calculated with the following weighted-average assumptions: zero dividend yield; risk-free interest rate of 3.0%; volatility of 51.6% and an expected life of 6 years. The value was adjusted for liquidity issues associated with a potential sale of such a large volume of shares in relation to our public float. This amount and the unamortized portion of the original issue discount of $5.6 million were written off in connection with the Amendment.

Capital Lease

During October 2005, we acquired the ATP Innovator (formerly the Rowan Midland) for the net adjusted purchase price of $46.7 million, and paid $1.7 million toward this lease in 2005, $21.0 million in 2006 and the remaining balance of $24.0 million on January 31, 2007.

Rights Plan

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

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

	December 31,
	2006		2005
Series A 13.5% cumulative perpetual preferred stock; liquidation preference of $0 and $1,056 per share at December 31, 2006 and 2005; 175,000 shares issued and outstanding at December 31, 2005	$	—	$	184,858
Junior participating preferred stock pursuant to the Shareholders Rights Plan; none issued at December 31, 2006 and 2005		—		—

Recently Issued Accounting Pronouncements

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

Contractual Obligations

We have various commitments primarily related to leases for office space, other property and equipment and other agreements. The following table summarizes certain contractual obligations at December 31, 2006 (in thousands):

Contractual Obligations	Total		Less Than 1 Year		1-3 Years		4-5 Years		After 5 Years
Long-term debt	$	1,071,441	$	8,987	$	668,400	$	394,054	$	—
Interest on long-term debt (1)		296,923		97,533		178,118		21,272		—
Current portion of long-term capital lease		22,247		22,247		—		—		—
Interest on capital lease (1)		1,703		1,703		—		—		—
Non-cancelable operating leases		2,884		855		1,079		812		138
Total contractual obligations	$	1,395,198	$	131,325	$	847,597	$	416,138	$	138

(1) Interest is based on rates and quarterly principal payments in effect at December 31, 2006.

37

Our liabilities also include asset retirement obligations ($21.3 million current and $87.1 million long-term) that represent the estimated fair value at December 31, 2006 of our obligations with respect to the retirement/plugging and abandonment of our oil and gas properties. Each reporting period the liability is accreted to its then present value. The ultimate settlement amounts and the timing of the settlements of such obligations is unknown because they are subject to, among other things, federal, state and local regulation and economic factors. See Note 2 to the Consolidated Financial Statements.

Critical Accounting Policies and Estimates

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

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

Oil and Gas Property Accounting

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

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

We perform a review for impairment of proved oil and gas properties on a depletable unit basis when circumstances suggest there is a need for such a review. To determine if a depletable unit is impaired, we compare the carrying value of the depletable unit to the undiscounted future net cash flows by applying management’s estimates of future oil and gas prices to the estimated future production of oil and gas reserves over the economic life of the property. Future net cash flows are based upon our independent reservoir engineer’s estimate of proved reserves. In addition, other factors such as probable and possible reserves are taken into consideration when justified by economic conditions and actual or planned drilling or other

38

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. Restoration of a previously recognized impairment loss is prohibited. Fair value, on a depletable unit basis, is estimated to be the present value of the aforementioned expected future net cash flows. Any impairment charge incurred is recorded in accumulated depreciation, depletion, impairment and amortization to reduce our recorded basis in the asset. Each part of this calculation is subject to a large degree of judgment, including the determination of the depletable units’ reserves, future cash flows and fair value.

Costs directly associated with the acquisition and evaluation of unproved properties are excluded from the amortization base until the related properties are developed. Unproved properties are assessed quarterly and any impairment in value is charged to impairment expense. The costs of unproved properties which are determined to be productive are transferred to proved oil and gas properties and amortized on a unit-of-production basis.

Oil and Gas Reserves

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

Impairment Analysis

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

Asset Retirement Obligations

We have significant obligations related to the plugging and abandonment of our oil and gas wells, dismantling our offshore production platforms, and the removal of equipment and facilities from leased

39

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

Contingent Liabilities

In preparing financial statements at any point in time, management is periodically faced with uncertainties, the outcomes of which are not within its control and will not be known for prolonged periods of time. As discussed in Part I, Item 3. – “Legal Proceedings” and the Notes to Consolidated Financial Statements, we are involved in actions from time to time, which if determined adversely, could have a material negative impact on our financial position, results of operations and cash flows. Management, with the assistance of counsel makes estimates, if determinable, of ATP’s probable liabilities and records such amounts in the consolidated financial statements. Such estimates may be the minimum amount of a range of probable loss when no single best estimate is determinable. Disclosure is made, when determinable, of any additional possible amount of loss on these claims, or if such estimate cannot be made, that fact is disclosed. Along with our counsel, we monitor developments related to these legal matters and, when appropriate, we make adjustments to recorded liabilities to reflect current facts and circumstances. Although it is difficult to predict the ultimate outcome of these matters, management is not aware of any amounts that need to be recorded and believes that the recorded amounts, if any, are reasonable.

Price Risk Management Activities

We periodically enter into commodity derivative contracts and fixed-price physical contracts to manage our exposure to oil and natural gas price volatility. We primarily utilize fixed price physical contracts, price swaps and put options, which are generally placed with major financial institutions or with counterparties of high credit quality that we believe are minimal credit risks. The oil and natural gas reference prices of these commodity derivatives contracts are based upon oil and natural gas, which have a high degree of historical correlation with actual prices we receive. All derivative instruments, unless designated as normal purchases and sales, are recorded on the balance sheet at fair value. Changes in the derivative’s fair value are recognized currently in earnings unless specific hedge accounting criteria are met. For qualifying cash flow hedges, the gain or loss on the derivative is deferred in accumulated other comprehensive income (loss) to the extent the hedge is effective. For qualifying fair value hedges, the gain or loss on the derivative is offset by related results of the hedged item in the income statement. Gains and losses on hedging instruments included in accumulated other comprehensive income (loss) are reclassified to oil and natural gas sales revenue in the period that the related production is delivered. Derivative contracts that do not qualify for hedge accounting treatment are recorded as derivative assets and liabilities at market value in the consolidated balance sheet, and the associated unrealized gains and losses are recorded in oil and natural gas revenues. As of December 31, 2006, we had five derivative contracts in place that qualified as cash flow hedges and thirty-four gas and oil fixed price futures contracts designated as normal sales contracts.

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. We have incurred net operating losses in a number of prior years. Relevant accounting guidance suggests that cumulative losses in recent years constitute significant negative evidence, and that future expectations about income are overshadowed by such history of losses. Delays in bringing properties onto production and development cost overruns in 2003 were

40

also significant factors considered in evaluating our deferred tax asset valuation allowance. Accordingly, we established a valuation allowance of $33.6 million as of December 31, 2003. We achieved profitable operations in 2004; however the income generated in 2004 was not sufficient to overcome the negative evidence noted in the prior years. During 2005, we incurred a net loss before income taxes of $2.6 million, and in 2006 we recorded income before income taxes of $25.7 million. See Note 10 “Income Taxes” to the Consolidated Financial Statements.

Stock Based Compensation

Effective January 1, 2006, we adopted Statement of Financial Accounting Standards (“SFAS”) No. 123(R), “Accounting for Share-Based Payment,” as amended, using the modified prospective transition method which requires, among other things, current recognition of compensation expense for share-based compensation granted after January 1, 2006, and for that portion of prior period share-based compensation for which the requisite service has not been rendered that was outstanding as of January 1, 2006. For periods prior to January 1, 2006, we applied to our stock-based compensation awards the intrinsic method of accounting as set forth in Accounting Principles Board (“APB”) Opinion No. 25, “Accounting for Stock Issued to Employees,” and related interpretations.

Off-Balance Sheet Arrangements

The Company has no off-balance sheet arrangements at December 31, 2006.

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

Interest Rate Risk

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

Foreign Currency Risk

The net assets, net earnings and cash flows from our wholly owned subsidiaries in the U.K. and the Netherlands are based on the U.S. dollar equivalent of such amounts measured in the applicable functional currency. These foreign operations have the potential to impact our financial position due to fluctuations in the local currency arising from the process of re-measuring the local functional currency in the U.S. dollar. We have not utilized derivatives or other financial instruments to hedge the risk associated with the movement in foreign currencies.

Commodity Price Risk

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

41

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

Item 8. Financial Statements and Supplementary Data.

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

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

None

Item 9A. Controls and Procedures.

Evaluation of Disclosure Controls and Procedures

In order to ensure that the information we must disclose in our filings with the Securities and Exchange Commission is recorded, processed, summarized, and reported on a timely basis, we have formalized our disclosure controls and procedures. Our principal executive officer and principal financial officer have reviewed and evaluated the effectiveness of our disclosure controls and procedures, as defined in Exchange Act Rules 13a-15(e) and 15d-15(e), as of December 31, 2006. Based on such evaluation, such officers have concluded that, as of December 31, 2006, our disclosure controls and procedures were effective in timely alerting them to material information relating to us (and our consolidated subsidiaries) required to be included in our periodic SEC filings. There has been no change in our internal control over financial reporting during the quarter ended December 31, 2006 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

Management’s Report on Internal Control Over Financial Reporting

Management of ATP Oil & Gas Corporation (the “Company”) is responsible for establishing and maintaining adequate internal control over financial reporting for the Company, as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934. Under the supervision and with the participation of the Company’s management, including our principal executive and principal financial officers, the Company conducted an evaluation of the effectiveness of its internal control over financial reporting based on the framework in “Internal Control—Integrated Framework” issued by the Committee of Sponsoring Organizations of the Treadway Commission (the “COSO Framework”). Based on this evaluation under the COSO Framework which was completed on February 28, 2006, management concluded that its internal control over financial reporting was effective as of December 31, 2006.

Management’s assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2006 has been audited by the independent registered public accounting firm who audited the Company’s consolidated financial statements as of and for the year ended December 31, 2006, as stated in their report which is included herein.

Item 9B. Other Information.

None.

42

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, 2007) and titles of the persons currently serving as executive officers of the Company. All executive officers hold office until their successors are elected and qualified.

Name	Age	Position
T. Paul Bulmahn	63	Chairman and President
Gerald W. Schlief	59	Senior Vice President
Albert L. Reese, Jr.	57	Chief Financial Officer
Leland E. Tate	59	Chief Operations Officer
John E. Tschirhart	56	Senior Vice President, International, General Counsel
Isabel M. Plume	46	Chief Communications Officer
Keith R. Godwin	39	Chief Accounting Officer

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

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

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

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

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

43

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

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

Except for the information relating to Executive Officers of the Registrant set forth above, the information required by Item 10 of Form 10-K is incorporated herein by reference to the definitive proxy statement for the Company’s Annual Meeting of Shareholders to be held on June 8, 2007 (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.

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

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

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

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

The information required by Item 13 of Form 10-K is incorporated herein by reference to the Company’s Proxy Statement.

Item 14. Principal Accounting Fees and Services.

The information required by Item 14 of Form 10-K is incorporated by reference to the Company’s Proxy Statement.

44

PART IV

Item 15. Exhibits, Financial Statement Schedules.

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

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

(a) (3) Exhibits

3.1	Amended and Restated Articles of Incorporation, incorporated by reference to Exhibit 3.1 of Registration Statement No. 333-46034 on Form S-1 of ATP Oil & Gas Corporation (“ATP”).
3.2	Amended and Restated Bylaws of ATP, incorporated by reference to Exhibit 3.1 of ATP’s Report on Form 10-Q for the quarter ended September 30, 2006.
4.1	Warrant Shares Registration Rights Agreement dated as of March 29, 2004 between ATP and each of the Holders set forth on the execution pages thereof, incorporated by reference to Exhibit 4.5 of ATP’s Form 10-K for the year ended December 31, 2003.
4.2	Warrant Agreement dated as of March 29, 2004 by and among ATP and the Holders from time to time of the warrants issued hereunder, incorporated by reference to Exhibit 4.6 of ATP’s Form 10-K for the year ended December 31, 2003.
4.3	Rights Agreement dated October 11, 2005 between ATP and American Stock Transfer & Trust Company, as Rights Agent, specifying the terms of the Rights, which includes the form of Statement of Designations of Junior Participating Preferred Stock as Exhibit A, the form of Right Certificate as Exhibit B and the form of the Summary of Rights to Purchase Preferred Shares as Exhibit C, incorporated by reference to Exhibit 1 to the Company’s Registration Statement on Form 8-A filed with the Securities and Exchange Commission on October 14, 2005.
†10.1	ATP Oil & Gas Corporation 2000 Stock Plan, incorporated by reference to Exhibit 10.11 of ATP’s Form 10-K for the year ended December 31, 2000.
*10.2	Third Amended and Restated Credit Agreement dated December 28, 2006 among ATP, the Lenders named therein and Credit Suisse (“CS”), as administrative and collateral agent.
10.3	Second Lien Credit Agreement dated November 22, 2006, among ATP, the lenders from time to time party thereto and CS, as administrative and collateral agent for the Lenders, incorporated by reference to Exhibit 10.2 of ATP’s Current Report on Form 8-K filed on November 29, 2006.
10.4	Intercreditor Agreement dated as of November 22, 2006 among ATP and CS, as first and second lien collateral agents, incorporated by reference to Annex I to Exhibit 10.1 of ATP’s Current Report on Form 8-K filed on November 29, 2006.
†10.5	Employment Agreement between ATP and Pauline H. van der Sman-Archer, dated December 29, 2005, incorporated by reference to Exhibit 10.1 to ATP’s Form 8-K dated December 30, 2005.
†10.6	Employment Agreement between ATP and John E. Tschirhart, dated December 29, 2005, incorporated by reference to Exhibit 10.2 to ATP’s Form 8-K dated December 30, 2005.
†10.7	Employment Agreement between ATP and Leland E. Tate, dated December 29, 2005, incorporated by reference to Exhibit 10.3 to ATP’s Form 8-K dated December 30, 2005.
†10.8	Employment Agreement between ATP and Robert M. Shivers, III, dated December 29, 2005, incorporated by reference to Exhibit 10.4 to ATP’s Form 8-K dated December 30, 2005.
†10.9	Employment Agreement between ATP and Mickey W. Shaw, dated December 29, 2005, incorporated by reference to Exhibit 10.5 to ATP’s Form 8-K dated December 30, 2005.
†10.10	Employment Agreement between ATP and Gerald W. Schlief, dated December 29, 2005, incorporated by reference to Exhibit 10.6 to ATP’s Form 8-K dated December 30, 2005.
†10.11	Employment Agreement between ATP and Albert L. Reese, Jr., dated December 29, 2005, incorporated by reference to Exhibit 10.7 to ATP’s Form 8-K dated December 30, 2005.
†10.12	Employment Agreement between ATP and Isabel M. Plume, dated December 29, 2005, incorporated by reference to Exhibit 10.8 to ATP’s Form 8-K dated December 30, 2005.
†10.13	Employment Agreement between ATP and Scott D. Heflin, dated December 29, 2005, incorporated by reference to Exhibit 10.9 to ATP’s Form 8-K dated December 30, 2005.

45

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

* Filed herewith

† Management contract or compensatory plan or arrangement

46

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 1, 2007.

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

47

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, 2006 and 2005	F-4
Consolidated Statements of Operations for the years ended December 31, 2006, 2005 and 2004	F-5
Consolidated Statements of Cash Flows for the years ended December 31, 2006, 2005 and 2004	F-6
Consolidated Statements of Shareholders’ Equity for the years ended December 31, 2006, 2005 and 2004	F-7
Consolidated Statements of Comprehensive Income (Loss) for the years ended December 31, 2006, 2005 and 2004	F-8
Notes to Consolidated Financial Statements	F-9
Supplemental Information—Oil and Gas Reserves and Related Financial Data (Unaudited)	F-30
Schedule II—Valuation and Qualifying Accounts	S-1

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

F-1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of

ATP Oil & Gas Corporation

Houston, Texas

We have audited the accompanying consolidated balance sheets of ATP Oil & Gas Corporation and subsidiaries (the “Company”) as of December 31, 2006 and 2005, and the related consolidated statements of operations, shareholders’ equity, comprehensive income (loss), and cash flows for each of the three years in the period ended December 31, 2006. Our audits also included the financial statement schedule listed in the index at Item 15. We also have audited management’s assessment, included in Management’s Report on Internal Control Over Financial Reporting, that the Company maintained effective internal control over financial reporting as of December 31, 2006, based on criteria established in “Internal Control-Integrated Framework” issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for these financial statements and financial statement schedule, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on these financial statements and financial statement schedule, an opinion on management’s assessment, and an opinion on the effectiveness of the Company’s internal control over financial reporting based on our audits.

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

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

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

F-2

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of ATP Oil & Gas Corporation and subsidiaries as of December 31, 2006 and 2005, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2006, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein. Also, in our opinion, management’s assessment that the Company maintained effective internal control over financial reporting as of December 31, 2006, is fairly stated, in all material respects, based on the criteria established in “Internal Control-Integrated Framework” issued by the Committee of Sponsoring Organizations of the Treadway Commission. Furthermore, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2006, based on the criteria established in “Internal Control-Integrated Framework” issued by the Committee of Sponsoring Organizations of the Treadway Commission.

As discussed in Note 2 to the consolidated financial statements, on January 1, 2006, the Company adopted Statement of Financial Accounting Standards No. 123(R), “Share-Based Payment.”

DELOITTE & TOUCHE LLP

Houston, Texas

March 1, 2007

F-3

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(In Thousands, Except Share Amounts)

	December 31,			December 31,
	2006			2005
Assets
Current assets:
Cash and cash equivalents	$	182,592		$	65,566
Restricted cash		27,497			12,209
Accounts receivable (net of allowance of $409 and $367)		105,030			83,571
Deferred tax asset		1,113			—
Derivative asset		1,170			—
Other current assets		9,931			4,454
Total current assets		327,333			165,800
Oil and gas properties (using the successful efforts method of accounting)
Proved properties		1,483,163			890,402
Unproved properties		56,189			8,882
		1,539,352			899,284
Less: Accumulated depletion, impairment and amortization		(443,707	)		(271,863	)
Oil and gas properties, net		1,095,645			627,421
Furniture and fixtures (net of accumulated depreciation)		1,079			1,175
Deferred tax asset		—			4,025
Deferred financing costs, net		13,272			17,922
Other assets, net		9,729			7,420
Total assets	$	1,447,058		$	823,763
Liabilities and Shareholders’ Equity
Current liabilities:
Accounts payable and accruals	$	195,846		$	144,675
Current maturities of long-term debt		8,987			3,500
Current maturities of long-term capital lease		23,699			8,679
Asset retirement obligation		21,297			7,097
Derivative liability		—			1,282
Total current liabilities		249,829			165,233
Long-term debt		1,062,454			337,489
Long-term capital lease		—			34,437
Asset retirement obligation		87,092			60,267
Deferred tax liability		11,765			—
Other long-term liabilities and deferred obligations		—			8,826
Total liabilities		1,411,140			606,252
Commitments and contingencies (Note 11)		—			—
Shareholders’ equity:
Preferred stock: $0.001 par value, 10,000,000 shares authorized; none issued and outstanding at December 31, 2006; 175,000 issued and outstanding at December 31, 2005		—			184,858
Common stock: $0.001 par value, 100,000,000 shares authorized; 30,272,210 issued and 30,196,370 outstanding at December 31, 2006; 29,668,517 issued and 29,592,677 outstanding at December 31, 2005		30			29
Additional paid-in capital		151,467			149,267
Accumulated deficit		(140,681	)		(101,333	)
Accumulated other comprehensive income (loss)		26,013			(4,693	)
Unearned compensation		—			(9,706	)
Treasury stock		(911	)		(911	)
Total shareholders’ equity		35,918			217,511
Total liabilities and shareholders’ equity	$	1,447,058		$	823,763

See accompanying notes to the consolidated financial statements.

F-4

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(In Thousands, Except Per Share Amounts)

	Year Ended December 31,
	2006			2005			2004
Revenues:
Oil and gas production	$	414,182		$	146,674		$	116,123
Other revenues		5,639			—			—
		419,821			146,674			116,123
Costs and operating expenses:
Lease operating		72,446			23,629			19,531
Exploration		2,231			6,208			997
General and administrative		21,499			24,274			15,806
Stock-based compensation		11,477			57			—
Credit facility		—			—			1,850
Depreciation, depletion and amortization		169,704			64,069			55,637
Impairment of oil and gas properties		19,520			—			—
Accretion		8,076			3,238			2,069
(Gain) loss on abandonment		9,603			(732	)		(251	)
Gain on disposition of properties		—			(2,743	)		(6,011	)
Other		—			—			400
		314,556			118,000			90,028
Income from operations		105,265			28,674			26,095
Other income (expense):
Interest income		4,532			4,064			627
Interest expense		(58,018	)		(35,720	)		(22,262	)
Loss on extinguishment of debt		(28,115	)		—			(3,326	)
Other income		7			419			280
		(81,594	)		(31,237	)		(24,681	)
Income (loss) before income taxes		23,671			(2,563	)		1,414
Income tax expense:
Current		(2,528	)		—			—
Deferred		(14,266	)		(153	)		(58	)
		(16,794	)		(153	)		(58	)
Net income (loss)		6,877			(2,716	)		1,356
Preferred stock dividends		(46,225	)		(9,858	)		—
Net income (loss) available to common shareholders	$	(39,348	)	$	(12,574	)	$	1,356
Net income (loss) per common share—basic and diluted	$	(1.33	)	$	(0.43	)	$	0.05
Weighted average number of common shares:
Basic		29,693			29,080			24,944
Diluted		29,693			29,080			25,271

See accompanying notes to the consolidated financial statements.

F-5

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In Thousands)

	Year Ended December 31,
	2006			2005			2004
Cash flows from operating activities
Net income (loss)	$	6,877		$	(2,716	)	$	1,356
Adjustments to reconcile net income (loss) to net cash provided by operating activities—
Depreciation, depletion and amortization		169,704			64,069			55,637
Impairment of oil and gas properties		19,520			—			—
Gain on disposition of properties		—			(2,743	)		(6,011	)
Accretion		8,076			3,238			2,069
Deferred income taxes		14,266			(3,949	)		—
Dry hole costs		—			5,341			—
Amortization of deferred financing costs		5,985			4,173			2,471
Loss on extinguishment of debt		28,115			—			3,326
Stock-based compensation		11,477			57			—
Ineffectiveness of cash flow hedges		(110	)		(189	)		190
Noncash interest and credit facility expenses		3,054			1,742			1,709
Other noncash items		(643	)		(1,075	)		1,585
Changes in assets and liabilities—
Accounts receivable and other current assets		(24,904	)		(43,095	)		(22,355	)
Accounts payable and accruals		20,419			23,212			3,656
Other assets		(3,322	)		(3,781	)		36
Other long-term liabilities and deferred obligations		—			(696	)		(2,451	)
Net cash provided by operating activities		258,514			43,588			41,218
Cash flows from investing activities
Additions and acquisitions of oil and gas properties		(577,012	)		(420,516	)		(87,368	)
Proceeds from disposition of oil and gas properties		—			19,820			19,200
Increase in restricted cash		(13,290	)		(12,476	)		—
Additions to furniture and fixtures		(381	)		(900	)		(483	)
Net cash used in investing activities		(590,683	)		(414,072	)		(68,651	)
Cash flows from financing activities
Proceeds from long-term debt		728,500			132,113			262,000
Payments of long-term debt		(4,435	)		(3,175	)		(166,230	)
Deferred financing costs		(24,551	)		(10,416	)		(13,502	)
Issuance of preferred stock, net of issuance costs		145,463			169,437			—
Redemption of preferred stock		(381,083	)		—			—
Net proceeds from secondary offering		—			—			53,066
Proceeds from capital lease		—			44,774			—
Payments of capital lease		(20,869	)		(1,658	)		—
Repurchase of warrants		—			—			(12,311	)
Exercise of stock options		4,966			4,507			—
Other		—			(68	)		2,675
Net cash provided by financing activities		447,991			335,514			125,698
Effect of exchange rate changes on cash		1,204			(2,238	)		(55	)
Increase (decrease) in cash and cash equivalents		117,026			(37,208	)		98,210
Cash and cash equivalents, beginning of period		65,566			102,774			4,564
Cash and cash equivalents, end of period	$	182,592		$	65,566		$	102,774

See accompanying notes to the consolidated financial statements.

F-6

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY

(In Thousands)

	2006					2005				2004
	Shares			Amount		Shares		Amount		Shares		Amount
Preferred Stock
Balance, beginning of year	175		$	184,858		—	$	—		—	$	—
Issuance of preferred stock	150			150,000		175		175,000		—		—
Preferred dividends	—			46,225		—		9,858		—		—
Redemption of preferred stock	(325	)		(381,083	)	—		—		—		—
Balance, end of year	—		$	—		175	$	184,858		—	$	—
Common Stock
Balance, beginning of year	29,592		$	29		28,884	$	29		24,520	$	25
Issuances of common stock
Secondary offering	—			—		—		—		4,000		4
Exercise of stock options	503			1		443		—		364		—
Restricted stock	101			—		265		—		—		—
Balance, end of year	30,196		$	30		29,592	$	29		28,884	$	29
Paid-in Capital
Balance, beginning of year			$	139,561			$	140,628			$	92,277
Issuance of capital stock
Secondary offering				—				—				53,062
Exercise of stock options				4,966				4,504				2,675
Preferred stock offering costs				(4,537	)			(5,628	)			—
Value of warrants issued in connection with financings				—				—				4,925
Repurchase of warrants				—				—				(12,311	)
Stock-based compensation				11,477				57				—
Balance, end of year			$	151,467			$	139,561			$	140,628
Accumulated Deficit
Balance, beginning of year			$	(101,333	)		$	(88,759	)		$	(90,115	)
Net income (loss)				6,877				(2,716	)			1,356
Preferred dividends				(46,225	)			(9,858	)			—
Balance, end of year			$	(140,681	)		$	(101,333	)		$	(88,759	)
Accumulated Other Comprehensive Income (Loss)
Balance, beginning of year			$	(4,693	)		$	6,177			$	3,056
Other comprehensive income (loss)				30,706				(10,870	)			3,121
Balance, end of year			$	26,013			$	(4,693	)		$	6,177
Treasury Stock
Balance, beginning of year	76		$	(911	)	76	$	(911	)	76	$	(911	)
Balance, end of year	76		$	(911	)	76	$	(911	)	76	$	(911	)
Total Shareholders’ Equity			$	35,918			$	217,511			$	57,164

See accompanying notes to the consolidated financial statements.

F-7

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(In Thousands)

	Year Ended December 31,
	2006			2005			2004
Net income (loss)	$	6,877		$	(2,716	)	$	1,356
Other comprehensive income (loss):
Reclassification adjustment for settled contracts, net of tax of $0		4,391			5			1,055
Change in fair value of outstanding hedge positions, net of tax of $0		(4,080	)		(1,759	)		(532	)
Foreign currency translation adjustment, net of tax of $0		30,395			(9,116	)		2,598
Other comprehensive income (loss)		30,706			(10,870	)		3,121
Comprehensive income (loss)	$	37,583		$	(13,586	)	$	4,477

See accompanying notes to the consolidated financial statements.

F-8

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1 — Organization and Basis of Presentation

Organization

ATP Oil & Gas Corporation (“ATP”) was incorporated in Texas in 1991. We are engaged in the acquisition, development and production of oil and natural gas properties in the Gulf of Mexico and the U.K. and Dutch Sectors of the North Sea (the “North Sea”). We primarily focus our efforts on oil and natural gas properties with proved undeveloped reserves that are economically attractive to us but are not strategic to major or exploration-oriented independent oil and gas companies.

Basis of Presentation

The consolidated financial statements include our accounts and our wholly-owned subsidiaries, ATP Energy, Inc. (“ATP Energy”), ATP Oil & Gas (UK) Limited, or “ATP (UK),” and ATP Oil & Gas Netherlands (B.V.). All intercompany transactions are eliminated upon consolidation. Certain prior year amounts have been reclassified to conform to the current year presentation.

Note 2 — Summary of Significant Accounting Policies

Use of Estimates

The preparation of financial statements in accordance with generally accepted accounting principles and pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”) requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and disclosure of contingent assets and liabilities in the financial statements, including the use of estimates for oil and gas reserve information and the valuation allowance for deferred income taxes. Actual results could differ from those estimates.

Cash and Cash Equivalents.

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

Restricted Cash.

The Company’s restricted cash represents time deposits denominated in Pounds Sterling which secures irrevocable stand-by letters of credit for our future abandonment obligations with respect to the Tors (Garrow) and Wenlock properties in the North Sea. The Letters of Credit and Reimbursement Agreements were entered into in July 2005 and August 2006, each with an initial term of one year, to be extended for successive one-year terms unless thirty days notice is given of the intention not to extend.

Oil and Gas Producing Activities.

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

Capitalized proved property acquisition costs are depleted on the unit-of-production method on the basis of total estimated units of proved reserves. Capitalized costs relating to producing properties are depleted on the unit-of-production method on the basis of total estimated units of proved developed reserves. When significant development costs (such as the cost of an off-shore production platform) are incurred in connection with a planned group of development wells before all of the planned wells have been drilled, it is occasionally necessary to exclude a portion of those development costs in determining the unit-of-production amortization rate until the additional development wells are drilled. However, in no case are future development costs anticipated in computing our amortization rate. Estimated dismantlement, restoration and abandonment costs and estimated residual salvage values are taken into account in determining amortization and depletion provisions. Expenditures for geological and geophysical testing costs are generally charged to expense unless the costs can be specifically attributed to mapping a proved reservoir and determining the optimal placement for future developmental well locations. Expenditures for repairs and maintenance are charged to expense as

F-9

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

incurred; renewals and betterments are capitalized. The costs and related accumulated depreciation, depletion, and amortization of properties sold or otherwise retired are eliminated from the accounts, and gains or losses on disposition are reflected in the statements of operations.

We perform a review for impairment of proved oil and gas properties on a depletable unit basis when circumstances suggest there is a need for such a review. To determine if a depletable unit is impaired, we compare the carrying value of the depletable unit to the undiscounted future net cash flows by applying management’s estimates of future oil and gas prices to the estimated future production of oil and gas reserves over the economic life of the property. Future net cash flows are based upon our independent reservoir engineer’s estimate of proved reserves. In addition, other factors such as probable and possible reserves are taken into consideration when justified by economic conditions and actual or planned drilling or other development activities. For a property determined to be impaired, an impairment loss equal to the difference between the carrying value and the estimated fair value of the impaired property will be recognized. Restoration of a previously recognized impairment loss is prohibited. Fair value, on a depletable unit basis, is estimated to be the present value of the aforementioned expected future net cash flows. Any impairment charge incurred is recorded in accumulated depreciation, depletion, impairment and amortization to reduce our recorded basis in the asset. Each part of this calculation is subject to a large degree of judgment, including the determination of the depletable units’ reserves, future cash flows and fair value. We recorded impairments during the year ended December 31, 2006 totaling $18.5 million on certain proved properties, primarily due to lower than projected oil and natural gas prices, unfavorable operating performance or downward revisions of recoverable reserves or a combination of all of these factors, and no impairments during 2005 and 2004.

Costs directly associated with the acquisition and evaluation of unproved properties are excluded from the amortization base until the related properties are developed. Unproved properties are assessed quarterly and any impairment in value is charged to impairment expense. The costs of unproved properties which are determined to be productive are transferred to proved oil and gas properties and amortized on a unit-of-production basis. During the year ended December 31, 2006, we recorded an impairment of unproved properties in the amount of $1.0 million. No such impairments were required during 2005 and 2004.

Asset Retirement Obligations.

We recognize liabilities associated with the eventual retirement of tangible long-lived assets, upon the acquisition, construction and development of the assets, whenever law or regulation will eventually require that we abandon those 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.

Until all such assets are ultimately sold or abandoned, we will recognize (i) depletion expense on the additional capitalized costs; (ii) accretion expense as the present value of the future asset retirement obligation increases with the passage of time, and; (iii) the impact, if any, of changes in estimates of the liability. The following table sets forth a reconciliation of the beginning and ending asset retirement obligation for the periods ended December 31, 2006, 2005 and 2004 (in thousands):

	December 31,
	2006			2005			2004
Asset retirement obligation, beginning of year	$	67,364		$	24,923		$	21,107
Liabilities incurred		34,984			43,685			3,239
Liabilities settled		(2,998	)		(3,730	)		(1,185	)
Accretion expense		8,076			3,238			2,069
Foreign currency translation		2,570			(525	)		704
Changes in estimates		(1,607	)		217			—
Liabilities settled—assets sold		—			(444	)		(1,011	)
Asset retirement obligation, end of year	$	108,389		$	67,364		$	24,923

F-10

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Capitalized Interest.

Interest costs during the development phase of certain long-term assets are capitalized and amortized over the related assets’ estimated useful lives. No interest was capitalized during 2006, 2005 or 2004.

Furniture and Fixtures.

Furniture and fixtures consists of office furniture, computer hardware and software and leasehold improvements. Depreciation of furniture and fixtures is computed using the straight-line method over their estimated useful lives, which vary from three to five years.

Other Assets.

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

Environmental Liabilities.

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

Revenue Recognition

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

Concentration of Credit Risk.

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

Major Customers.

We sell a portion of our oil and gas to end users through various gas marketing companies. For the year ended December 31, 2006, revenues from two purchasers accounted for 43% and 32%, respectively, of oil and gas production revenues. For the year ended December 31, 2005, revenues from three purchasers accounted for 48%, 14% and 12%, respectively, of oil and gas production revenues. For the year ended December 31, 2004, revenues from four purchasers accounted for 35%, 21%, 17% and 15%, respectively, of oil and gas production revenues. Percentages are calculated on oil and gas revenues before any effects of price risk management activities.

Translation of Foreign Currencies.

The local currency is the functional currency for our foreign subsidiaries, and as such, assets and liabilities are translated into U.S. dollars at year-end exchange rates. Income and expense items are translated at average exchange rates during the year. The gains or losses resulting from such translations are deferred and included in accumulated other comprehensive income as a separate component of shareholders’ equity. Also included in income are gains and losses arising from transactions denominated in a currency other than the functional

F-11

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

currency of a particular entity. At December 31, 2006, accumulated other comprehensive income included $27.4 million of gain related to cumulative foreign currency translation adjustments.

Income Taxes.

Income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences or benefits attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases and operating loss and tax credit carry forwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes that enactment date.

Comprehensive Income (Loss).

Comprehensive income (loss) is net income or loss, plus certain other items that are recorded directly to shareholders’ equity. In 2006, comprehensive income was $37.6 million. In 2005, comprehensive loss was $13.6 million. In 2004, comprehensive income was $4.5 million.

Stock-based Compensation.

Effective January 1, 2006, we adopted Statement of Financial Accounting Standards (“SFAS”) No. 123(R), “Accounting for Share-Based Payment,” as amended, using the modified prospective transition method which requires, among other things, current recognition of compensation expense for share-based compensation granted after January 1, 2006, and for that portion of prior period share-based compensation for which the requisite service has not been rendered that was outstanding as of January 1, 2006. During the years ended December 31, 2006, 2005 and 2004, we recognized aggregate compensation expense of $1.8 million, $0 and $0, respectively, related to outstanding common stock options. During the years ended December 31, 2006, 2005 and 2004, we recognized aggregate compensation expense of $9.6 million, $0 million and $0, respectively, related to outstanding restricted stock grants.

For periods prior to January 1, 2006, we applied to our stock-based compensation awards the intrinsic method of accounting as set forth in Accounting Principles Board (“APB”) Opinion No. 25, “Accounting for Stock Issued to Employees,” and related interpretations. The following table illustrates the effect on net income (loss) and earnings per share if we had applied the fair value recognition provisions of SFAS 123(R), as amended, to stock-based employee compensation during 2005 and 2004 (in thousands, except for per-share data):

	Year Ended December 31,
	2005			2004
Net income (loss) available to common shareholders, as reported	$	(12,574	)	$	1,356
Total stock based employee compensation benefit determined under fair value for all awards, net of related tax effects		(350	)		(51	)
Pro forma net income (loss)	$	(12,924	)	$	1,305
Earnings per share:
Basic and diluted earnings per share—as reported	$	(0.43	)	$	0.05
Basic and diluted earnings per share—pro forma		(0.44	)		0.05

Fair Value of Financial Instruments.

For cash and cash equivalents, receivables and payables, the carrying amounts approximate fair value because of the short maturity of these instruments. Bank debt is variable rate debt and as such, approximates fair values, as interest rates are variable based on prevailing market rates.

Derivative Instruments.

From time to time, we utilize fixed price forward gas and oil sales contracts, options, swaps and collars to manage our commodity price risk. Our fixed price forward gas and oil sales contracts are designated normal sales under Statement of Financial Accounting Standards (“SFAS”) No. 133, “Accounting for Derivative

F-12

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

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

Note 3 — Recently Issued Accounting Pronouncements

During February 2007, the Financial Accounting Standards Board (“FASB”) issued FASB Statement of Accounting Standards (“SFAS”) No 159, “The Fair Value Option for Financial Assets and Financial Liabilities” (“SFAS No. 159”) which permits all entities to choose, at specified election dates, to measure eligible items at fair value. SFAS No. 159 permits entities to choose to measure many financial instruments and certain other items at fair value that are not currently required to be measured at fair value, and thereby mitigate volatility in reported earnings caused by measuring related assets and liabilities differently without having to apply complex hedge accounting provisions. This Statement also establishes presentation and disclosure requirements designed to facilitate comparisons between entities that choose different measurement attributes for similar types of assets and liabilities. SFAS No. 159 is effective as of the beginning of an entity’s first fiscal year that begins after November 15, 2007. We are evaluating the impact that this Statement will have on our financial statements.

During September 2006, the Securities and Exchange Commission (“SEC”) issued Staff Accounting Bulletin (“SAB”) No. 108. This Bulletin provides the Staff’s views on the consideration of the effects of prior year misstatements in quantifying current year misstatements for the purpose of a materiality assessment. The guidance in SAB No. 108 is effective for financial statements of fiscal years ending after November 15, 2006. Adoption of this guidance did not materially impact our financial statements.

During September 2006, the Financial Accounting Standards Board (“FASB”) issued FASB Statement of Accounting Standards (“SFAS”) No. 157. This Statement defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles, and expands disclosures about fair value measurements. This Statement applies under other accounting pronouncements that require or permit fair value measurements, where fair value has been determined to be the relevant measurement attribute. This statement is effective for financial statements of fiscal years beginning after November 15, 2007. Adoption of this guidance did not materially impact our financial statements.

In June 2006, the FASB issued Interpretation No. 48, “Accounting for Uncertainty in Income Taxes-an Interpretation of FASB Statement No. 109,” (“FIN 48”) which provides guidance for the recognition and measurement of a tax position taken or expected to be taken in a tax return. FIN 48 requires the evaluation of a tax position as a two-step process. First, we will be required to determine whether it is more likely than not that a tax position will be sustained upon examination, including resolution of any related appeals or litigation processes, based on the technical merits of the position. If the tax position meets the “more likely than not” recognition threshold, it is then measured and recorded at the largest amount of benefit that is greater than 50 percent likely of being realized upon ultimate settlement. We will be required to adopt FIN 48 in the first quarter of 2007. We are evaluating our tax positions and the impact that this guidance will have on our financial statements.

During November 2005, the FASB issued Staff Position (“FSP”) No. FAS 123(R)-3, “Transition Election Related to Accounting for the Tax Effects of Share-Based Payment Awards,” which provided a practical

F-13

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

transition election related to accounting for the tax effects of share-based payment awards to employees as an alternative to the method set forth in paragraph 81 of Statement of Financial Accounting Standards (“SFAS”) No. 123(R). An entity that adopts SFAS No. 123(R) using either the modified retrospective or the modified prospective application may make a one-time election to adopt the transition methodology described in this FSP up to one year after the later of its adoption of SFAS 123(R) or the effective date of this FSP. The Company adopted SFAS 123(R) and related guidance on January 1, 2006 for its outstanding unvested awards as well as for awards granted, modified, repurchased or canceled on or after that date. We have determined that we will not make the one-time election allowed by this FSP.

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

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

During April 2005, the FASB issued FSP No. FAS 19-1, “Accounting for Suspended Well Costs.” FSP No. 19-1 amends SFAS No. 19, “Financial Accounting and Reporting by Oil and Gas Producing Companies,” to allow continued capitalization of exploratory well costs beyond one year from the date drilling was completed under circumstances where the well has found a sufficient quantity of reserves to justify its completion as a producing well and the enterprise is making sufficient progress assessing the reserves and the economic and operating viability of the project. FSP No. 19-1 also amends SFAS No. 19 to require enhanced disclosures of suspended exploratory well costs in the notes to the financial statements for annual and interim periods when there has been a significant change from the previous disclosure. Adoption of this guidance did not have a material impact on our consolidated financial position, results of operations or cash flows.

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

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

F-14

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Note 4 — Supplemental Disclosures of Cash Flow Information

Supplemental disclosures of cash flow information (in thousands):

	Year Ended December 31,
	2006		2005		2004
Cash paid during the year for interest	$	42,748	$	28,085	$	17,879
Cash paid during the year for income taxes	$	5	$	—	$	150

Note 5 — Acquisitions and Dispositions

Gulf of Mexico

We closed three separate purchase transactions for minerals in-place during 2006. These purchases totaled $30.0 million in acquisition costs. Additionally, we acquired three blocks for $4.3 million at the Gulf of Mexico Offshore Lease Sales held in 2006. We hold a 100% working interest and serve as operator of each of the blocks.

During the second and third quarter of 2006, we acquired in two separate transactions a 100% working interest in Mississippi Canyon Blocks 941, 942 and Atwater Valley Block 63, collectively called the Telemark Hub. As of December 31, 2006, we had begun engineering and construction of a floating drilling and production facility for the Telemark Hub which is expected to be installed in mid-2008. Costs incurred, excluding acquisition costs, during 2006 at the Telemark Hub were approximately $11.0 million. We serve as operator of each of the blocks.

At Ship Shoal 351, we increased our ownership from 50% to 100% in exchange for the assumption of future abandonment liability. At December 31, 2006, we were installing a platform at Ship Shoal 351 and in February 2007 we began drilling the first of at least two planned wells. We hold a 100% working interest and serve as operator at Ship Shoal 351.

During March 2005, ATP was the apparent high bidder and was subsequently awarded seven blocks relating to its winning bids totaling $2.4 million at the Central Gulf of Mexico Offshore Lease Sale. ATP owns a 100% working interest in and is the operator of all seven blocks. Two of the blocks are adjacent to the Company’s wholly-owned Mississippi Canyon 711 development. Two additional blocks are contiguous to an existing ATP operated development in the West Cameron area and the remaining three blocks provide for new development area opportunities. Also, in the second quarter of 2005, ATP acquired 100% of the working interest in South Marsh Island 166.

During September 2005, ATP acquired a 55% working interest in four Federal oil and gas leases covering Mississippi Canyon Blocks 173/217 and Desoto Canyon Blocks 133/177, offshore Gulf of Mexico, in an oil and gas discovery area named “King’s Peak.” The acquisition also included a 19.25% working interest in the Canyon Express Pipeline System. The final adjusted purchase price for this acquisition was $16.9 million.

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

During October 2005, we acquired the ATP Innovator (formerly the Rowan Midland) for the net adjusted purchase price of $46.7 million, and paid $1.7 million toward this lease in 2005, $21.0 million in 2006 and the remaining balance of $24.0 million on January 31, 2007.

Also during October 2005, we acquired substantially all of the oil and gas assets of a privately held company, consisting of 19 blocks located on the Gulf of Mexico Outer Continental Shelf in less than 600 feet of water. The reserves are approximately 80% gas and 20% oil. The adjusted purchase price was $37.2 million

F-15

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

in cash, plus net liabilities assumed totaling an estimated $31.4 million for future property abandonment operations. The purchase price was allocated $68.1 million to proved oil and gas property, and $0.5 million to unproved property.

U.K. Sector—North Sea

During the fourth quarter of 2006, ATP (UK) acquired a 100% working interest in Block 49/12b in the Southern Gas Basin of the U.K. North Sea. Block 49/12b is an exploratory opportunity offsetting our Wenlock development. Wenlock is located in 75 feet of water and has two vertical wells that have tested at rates of 35 MMcf per day and 74 MMcf per day.

During June 2005, we increased our ownership in the Tors fields (Garrow and Kilmar) in the Southern Gas Basin of the U.K. North Sea to 100% by acquiring the remaining 25% interest pursuant to an agreement with our partner. The Secretary of State for Trade and Industry gave approval for ATP (UK) to own a 100% interest in the Tors fields and to act as the sole development and production operator. Subsequently, in December 2005, ATP (UK) sold 15% of its working interest in the Tors fields.

During December 2005, we announced that we had increased our ownership to 100% in the Wenlock (formerly Venture) field (Block 49/12a North) in the Southern Gas Basin of the U.K. North Sea. ATP (UK) acquired the 50% working interest owned by our partner pursuant to a Sale and Purchase Agreement. Control of this property will allow ATP to proceed with the field development plan approval process.

ATP (UK) recorded net acquisition costs of $7.0 million related to its 2005 acquisitions.

Note 6 — Debt and Leases

Long-term debt

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

	Year Ended December 31,
	2006			2005
First Lien Term Loans, net of unamortized discount of $0 and $6,386	$	896,441		$	340,989
Second Lien Term Loan		175,000			—
Total		1,071,441			340,989
Less current maturities		(8,987	)		(3,500	)
Total long-term debt	$	1,062,454		$	337,489

On November 22, 2006, the Company, the lenders named therein and Credit Suisse (as Administrative Agent and Collateral Agent for such lenders) entered into Amendment No. 1 and Agreement (the “Amendment”) amending the Second Amended and Restated Credit Agreement dated as of June 22, 2006; the Company, the lenders named therein and Credit Suisse (as Administrative Agent and Collateral Agent for such lenders) entered into the Second Lien Credit Agreement; and the Company, ATP Energy, Inc. and Credit Suisse (as Collateral Agent under the Previous First Lien Credit Agreement and under the Second Lien Credit Agreement) entered into an Intercreditor Agreement. Under the Second Lien Credit Agreement, the Company has second lien term loans of $175.0 million. The Second Lien Term Loans bear interest at LIBOR plus 4.75% and mature in October 2010.

With the Amendment, we increased our aggregate borrowings under the Previous First Lien Credit Agreement by $375.0 million. We also borrowed $175.0 million under the Second Lien Credit Agreement. From this increase in borrowings, we received net proceeds of $536.3 million, after deducting $13.7 million for fees and expenses. The net proceeds were used by the Company: (a) to redeem the Series A Preferred Stock (as defined in Note 7 below), which had an original face amount of $175.0 million; (b) to redeem the Series B Preferred Stock (as defined in Note 7 below), which had an original face amount of $150.0 million; and (c) for general corporate purposes. Concurrent with the Amendment, we incurred a noncash charge of approximately

F-16

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

$27.9 million related to the capitalized costs of the Previous First Lien Credit Agreement and approximately $9.3 million of costs related to calling and retiring all of the preferred shares.

On December 28, 2006, the Company, the lenders named therein and Credit Suisse (as Administrative Agent and Collateral Agent for such lenders) entered into the First Lien Credit Agreement. Under the First Lien Credit Agreement, the Company has first lien term loans for $900.0 million and a revolving credit and letter of credit facility in an amount not to exceed $50.0 million at any time outstanding. The First Lien Term Loans bear interest at LIBOR plus 3.5% and mature in April 2010. The Revolver, under which no amounts were outstanding as of December 31, 2006, bears interest at LIBOR plus 3.5% and matures in October 2009.

At December 31, 2006, our borrowings were secured by substantially all of our oil and gas assets in the Gulf of Mexico and a pledge of 65% of the common stock of our wholly owned subsidiaries, ATP (UK) and ATP Oil & Gas (Netherlands) B.V., were guaranteed by our wholly owned subsidiary ATP Energy, Inc., and bore interest at a weighted average rate of approximately 9.13%.

The terms of the Term Loans and the Revolver require us to maintain certain covenants. As of December 31, 2006, we were in compliance with all of the financial covenants of our Term Loans.

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

In connection with the original issuance of the term loans during 2004, we granted warrants to purchase 2,452,336 shares of common stock of ATP for $7.25 per share, 525,499 of which remain outstanding at December 31, 2006. The warrants have a term of six years and expire in March 2010. The fair value of the warrants, as determined by use of the Black-Scholes valuation model on March 29, 2004, was approximately $4.2 million and was accounted for as additional paid-in-capital and debt discount. The fair value was calculated with the following weighted-average assumptions: zero dividend yield; risk-free interest rate of 3.0%; volatility of 51.6% and an expected life of 6 years. The value was adjusted for liquidity issues associated with a potential sale of such a large volume of shares in relation to our public float. This amount and the unamortized portion of the original issue discount of $5.6 million were written off in connection with the Amendment.

Capital Lease

During October 2005, we agreed to acquire the Rowan Midland mobile offshore drilling unit (“Vessel”) from Rowandrill, Inc. for modification for use as a floating offshore production unit at our Mississippi Canyon 711 development. The Vessel was subsequently renamed the ATP Innovator. The net purchase price of $46.7 million, including certain prepayment credits, was payable over the succeeding 15-month period. We paid $1.7 million toward this lease in 2005, $21.0 million in 2006 and the remaining balance of $24.0 on January 31, 2007. At its inception, the company recorded this transaction as a capital lease and recorded an oil and gas asset and corresponding capital lease obligation in the amount of $44.8 million.

Operating Leases

We have commitments under an operating lease agreement for office space and various leases for office equipment. Total rent expense for the years ended December 31, 2006, 2005 and 2004 was approximately $0.7 million, $0.6 million and $0.7 million, respectively. At December 31, 2006, the future minimum rental payments due under operating leases are as follows (in thousands):

F-17

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Year Ending December 31:
2007		855
2008		683
2009		396
2010		399
2011		413
Thereafter		138
Total	$	2,884

Note 7 — Equity

Series A Preferred Stock

On August 2, 2005, ATP entered into a Subscription Agreement for the private placement of 175,000 shares of its 13.5% Series A cumulative perpetual preferred stock, par value, $0.001 per share (the “Series A Preferred Stock”), at a price of $1,000.00 per share. The Series A Preferred Stock was redeemed in its entirety with the proceeds of additional Term Loans, as discussed in Note 6. The Series A Preferred Stock was not convertible into the Company’s common stock. Aggregate gross proceeds to the Company were $175.0 million and the Company paid $5.25 million in placement agent commissions. The issuance of the Series A Preferred Stock was exempt from the registration requirements of the Securities Act of 1933, as amended, and was offered and issued only to institutional accredited investors.

The Statement of Resolutions establishing the Series A Preferred Stock provided for: (1) an initial liquidation preference of $1,000.00 per share; (2) cumulative quarterly dividends at an initial rate of 13.5%, subject to escalation in the applicable dividend rate under certain conditions; (3) no voting rights (except as required by law or after the occurrence of various extraordinary events); (4) special provisions in the event of a Fundamental Change (as defined in the Statement of Resolutions) in the Company or the satisfaction of the Company’s currently outstanding debt; (5) limitations on incurrence of additional debt; and (6) restrictions on transfer or sale of the Series A Preferred Stock.

The Company had the right to redeem the Series A Preferred Stock at its option at any time after a Fundamental Change or the later of February 3, 2006 or the specified debt satisfaction date at a premium that declined until February 3, 2009, at which time the Series A Preferred Stock could be redeemed at 100% of the liquidation preference plus accrued and unpaid dividends.

In the event of a Fundamental Change in the Company or the repayment of the then outstanding debt, the Company was required to notify the preferred stockholders whether it intended to offer to redeem the Series A Preferred Stock. If the Company chose not to offer to redeem the Series A Preferred Stock, then it was to be deemed a Fundamental Change offer default or a debt satisfaction offer default, as the case may be, and the applicable dividend rate was to escalate by 5% per quarter, to a maximum of 25%. Such escalation was to continue until either of such defaults was cured, unless the Company had previously exercised its optional redemption right with respect to all of the shares of Series A Preferred Stock then outstanding. The Company was under no obligation to offer to redeem the Series A Preferred Stock under any circumstances, but chose to redeem the Series A Preferred Stock and accrued dividends with the proceeds of additional Term Loans as described in Note 6.

Series B Preferred Stock

On March 20, 2006, ATP entered into a Subscription Agreement for the private placement of 150,000 shares of its 12.5% Series B cumulative perpetual preferred stock, par value, $0.001 per share (the “Series B Preferred Stock”), at a price of $1,000.00 per share. The Series B Preferred Stock was redeemed in its entirety with the proceeds of additional Term Loans, as discussed in Note 6. The Series B Preferred Stock was not convertible into the Company’s common stock. Aggregate gross proceeds to the Company were $150.0 million and the Company paid $4.5 million in placement agent commissions. The issuance of the Series B Preferred Stock was exempt from the registration requirements of the Securities Act of 1933, as amended, and was offered and issued only to institutional accredited investors.

F-18

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

The Statement of Resolutions establishing the Series B Preferred Stock provided for: (1) an initial liquidation preference of $1,000.00 per share; (2) cumulative quarterly dividends at an initial annual rate of 12.5%, subject to escalation in the applicable annual dividend rate under certain conditions; (3) no voting rights (except as required by law or after the occurrence of various extraordinary events); (4) special provisions in the event of a Fundamental Change in the Company or the satisfaction of the Company’s currently outstanding debt; (5) limitations on incurrence of additional debt; and (6) restrictions on transfer or sale of the Preferred Stock.

The Company had the right to redeem the Series B Preferred Stock at its option at any time at a premium that declined until February 3, 2009, at which time the preferred stock could be redeemed at 100% of the liquidation preference plus accrued and unpaid dividends.

In the event of a Fundamental Change in the Company or the repayment of the then outstanding debt, the Company was required to notify the preferred stockholders whether it intended to offer to redeem the Series B Preferred Stock. If the Company chose not to offer to redeem the Series B Preferred Stock, then it was to be deemed a Fundamental Change offer default or a debt satisfaction offer default, as the case may be, and the applicable dividend rate was to escalate by 5% per quarter, to a maximum of 25%. Such escalation was to continue until either of such defaults was cured, unless the Company had previously exercised its optional redemption right with respect to all of the shares of Series B Preferred Stock then outstanding. The Company was under no obligation to offer to redeem the Series B Preferred Stock under any circumstances, but chose to redeem the Series B Preferred Stock and accrued dividends with the proceeds of additional Term Loans as described in Note 6.

Rights Plan

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

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

	December 31,
	2006		2005
Series A 13.5% cumulative perpetual preferred stock; liquidation preference of $0 and $1,056 per share at December 31, 2006 and 2005; 175,000 shares issued and outstanding at December 31, 2005	$	—	$	184,858
Junior participating preferred stock pursuant to the Shareholders Rights Plan; none issued at December 31, 2006 and 2005		—		—

Common Stock

At December 31, 2006, we had 100,000,000 shares authorized, 30,272,210 shares issued, 30,196,370 shares outstanding and 75,840 shares in treasury. At December 31, 2005, we had 100,000,000 shares authorized, 29,688,517 shares issued, 29,592,677 shares outstanding and 75,840 shares in treasury.

Warrants

At December 31, 2006 and 2005, there were 525,499 warrants outstanding to purchase common stock at $7.25, which expire in March 2010.

F-19

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Note 8—Stock and Other Compensation Plans

In December 1998, the Board of Directors approved the 1998 Stock Option Plan (the “1998 Plan”) to provide increased incentive for its employees and directors. The 1998 Plan authorized the granting of incentive and nonqualified options for up to 2,678,571 shares of common stock to eligible participants, and expired five years after the closing date of our IPO. One third of the options were exercisable on April 10, 2001 with each remaining third exercisable on the first and second anniversaries of the IPO. As of December 31, 2006, there are no remaining options outstanding under this plan.

In January 2001, the Board of Directors approved the 2000 Stock Option Plan (the “2000 Plan”) to provide increased incentive for its employees and directors. The 2000 Plan authorizes the granting of options and restricted stock awards for up to 4,000,000 shares of common stock. Generally, options are granted at prices equal to at least 100% of the fair value of the stock at the date of grant, expire not later than five years from the date of grant and vest ratably over a four-year period following the date of grant. From time to time, as approved by the Board of Directors, options with differing terms have also been granted. We recognized stock option compensation expense of approximately $1.8 million for the year ended December 31, 2006.

The fair values of options granted during the years ended December 31, 2006, 2005 and 2004 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,
	2006		2005		2004
Weighted average volatility	51	%	49	%	57	%
Expected term (in years)	3.8		2.5		2.5
Risk-free rate	4.6	%	3.7	%	2.6	%

Volatilities are based on the historical volatility of our closing common stock price. Expected term of options granted is derived from output of the option valuation model and represents the period of time that options granted are expected to be outstanding. The 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 weighted average grant-date fair values of options granted during the years ended December 31, 2006, 2005 and 2004 were $16.21, $6.68 and $4.69, respectively. The aggregate intrinsic values of options exercised during the years ended December 31, 2006, 2005 and 2004 were $14.9 million, $11.9 million and $10.8 million, respectively. The following table sets forth a summary of option transactions for the year ended December 31, 2006:

	Number of Options		Weighted Average Grant Price		Aggregate Intrinsic Value (1) ($000)		Weighted Average Remaining Contractual Life
							(in years)
Outstanding at beginning of year	1,016,361		$	14.38
Granted	218,500			38.32
Exercised	(502,877	)		9.88
Forfeited	(38,133	)		22.11
Outstanding at end of year	693,851			24.76	$	14,932	3.51
Vested and expected to vest	641,354			24.76		9,558	3.45
Options exercisable at end of year	107,800			17.18		2,414	3.05

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

F-20

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

A summary of the status of ATP’s nonvested stock options as of December 31, 2006 and changes during the year ended December 31, 2006 is presented below:

	Number of Options		Weighted Average Grant-date Fair Value
Nonvested at beginning of year	540,864		$	6.28
Granted	210,000			11.76
Vested	(150,895	)		5.60
Forfeited	(13,918	)		8.36
Nonvested at end of year	586,051			8.37

At December 31, 2006, unrecognized compensation expense related to nonvested stock option grants totaled $2.5 million. Such unrecognized expense will be recognized as vesting occurs over a weighted average period of 2.7 years.

On September 25, 2006, we granted 3,000 shares of restricted stock with a weighted average grant date fair value of $36.61 per share to an employee. On June 14, 2006, we granted 21,816 shares of restricted stock with a weighted average grant date fair value of $36.68 per share to our non-employee directors. Such restricted stock grants vest over a three-year period. On April 4, 2006, we granted 31,500 shares of restricted stock with a weighted average grant date fair value of $44.63 per share to our non-employee directors. Such restricted stock grants vest on January 15, 2007. On February 9, 2006, we granted 44,500 shares of restricted stock with a weighted average grant date fair value of $37.82 per share to employees. Such restricted stock grants vest over a three-year period. Each of the above restricted stock grants is 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. We will recognize compensation expense over the vesting period of these shares. During the years ended December 31, 2006, 2005 and 2004, we recognized aggregate compensation expense of $9.6 million, $0 million and $0, respectively, related to outstanding restricted stock grants.

F-21

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

The following table sets forth the changes in nonvested restricted stock for the year ended December 31, 2006:

	Number of Shares		Weighted Average Grant-date Fair Value		Aggregate Intrinsic Value (1) ($000)
Nonvested at beginning of year	265,363		$	36.79
Granted	100,816			39.67
Vested	(132,677	)		36.79
Nonvested at end of year	233,502			38.03	$	9,240

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

At December 31, 2006, unrecognized compensation expense related to restricted stock totaled $4.1 million. Such unrecognized expense will be recognized as vesting occurs over a weighted average period of 1.8 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 $218,000, $190,000 and $157,000 for the years ended December 31, 2006, 2005 and 2004, 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, 2006, 2005 and 2004, we contributed approximately $22,100, $20,300 and $20,200, respectively.

Note 9—Earnings Per Share

Basic earnings per share is computed by dividing net income or loss by the weighted average number of shares of common stock (other than unvested restricted stock) outstanding during the period. Diluted earnings per share are determined on the assumption that outstanding stock options and warrants have been converted using the average price for the period. For purposes of computing earnings per share in a loss year, potential common shares are excluded from the computation of weighted average common shares outstanding if their effect is antidilutive. In the table below, potential common stock equivalents of 709,000 and 1,086,000 have been excluded from the calculations for 2006 and 2005, respectively, because their effect would be antidilutive.

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

	Year Ended December 31,
	2006			2005			2004
Income
Net income (loss)	$	6,877		$	(2,716	)	$	1,356
Less preferred dividends		(46,225	)		(9,858	)		—
Net income (loss) available to common shareholders	$	(39,348	)	$	(12,574	)	$	1,356
Shares outstanding
Weighted average shares outstanding—basic		29,693			29,080			24,944
Effect of potentially dilutive securities—stock options and warrants		—			—			327
Unvested restricted stock		—			—			—
Weighted average shares outstanding—diluted		29,693			29,080			25,271
Basic and diluted per share data:
Net income (loss) available to common shareholders	$	(1.33	)	$	(0.43	)	$	0.05

F-22

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Note 10—Income Taxes

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

	Year Ended December 31,
	2006			2005			2004
Current:
Federal	$	(570	)	$	(77	)	$	(29	)
Foreign		(1,958	)		(4,025	)		(29	)
		(2,528	)		(4,102	)		(58	)
Deferred:
Federal	$	(4,108	)	$	(517	)	$	(4,561	)
Foreign		(15,460	)		224			1,568
		(19,568	)		(293	)		(2,993	)
Valuation allowance		5,302			4,242			2,993
Total (expense) benefit	$	(16,794	)	$	(153	)	$	(58	)

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

	Year Ended December 31,
	2006		2005			2004
Domestic	$	1,506	$	(9,759	)	$	6,027
Foreign		22,165		7,196			(4,613	)
	$	23,671	$	(2,563	)		1,414

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,
	2006		2005		2004
Statutory federal income tax rate	35.00	%	(35.00	)%	35.00	%
Nondeductible and other	9.97		56.95		(3.45	)
Foreign operations	46.73		149.61		12.92
Valuation allowance	(20.75	)	(165.61	)	(40.37	)
	70.95	%	5.95	%	4.10	%

Significant components of our deferred tax assets (liabilities) as of December 31, 2006 and 2005 are as follows (in thousands):

	Year Ended December 31,
	2006			2005
Current deferred income tax asset:
Foreign operations	$	1,113		$	—
Net current deferred income tax asset	$	1,113		$	—
Non-current deferred:
Deferred income tax assets:
Net operating loss carry forwards	$	40,605		$	46,285
AMT credit		676			106
Stock based compensation expense		2,086			440
Foreign operations		164,498			48,803
Revenue recognition contingency		1,879			4,025
Other		895			1,541
Total deferred income tax assets		210,639			101,200
Less valuation allowance		(25,126	)		(30,262	)
Net non-current deferred income tax asset		185,513			70,938
Deferred income tax liabilities:
Fixed asset basis differences		(18,522	)		(16,916	)
Asset retirement obligations		(614	)		(1,944	)
Foreign operations		(178,142	)		(48,053	)
Net non-current deferred income tax asset (liability)	$	(11,765	)	$	(4,025	)

F-23

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

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 have recorded and continue to carry a valuation allowance to give effect to our judgment that it is more likely than not that some portion or all of our net U.S. deferred tax assets will not be realized at some point in the future. Relevant accounting guidance suggests that cumulative losses in recent years constitute significant negative evidence that such deferred tax assets are not recoverable, and that future expectations about income are overshadowed by such history of losses. As of December 31, 2006, we have a valuation allowance equal to the entire balance of our net U.S. deferred tax asset, and we have no valuation allowance recorded related to our foreign operations as a result of the taxable income generated by those entities.

Effective January 1, 2006, we adopted Statement of Financial Accounting Standards (“SFAS”) No. 123(R), “Accounting for Share-Based Payment,” as amended. The implementation guidance does not allow recognition of the excess tax benefit related to option exercises and vesting of restricted stock until realized by reducing current taxes payable. Accordingly, the deferred tax asset related to the U.S. net operating loss carry forwards as disclosed does not include an additional $15.9 million of net operating loss as we anticipate we will include this amount in our 2006 U. S. net operating loss carry forwards in relation to excess tax benefits on stock option exercises and restricted stock vested during the fiscal year ended December 31, 2006.

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

At the time of receipt, we determined the payment was not taxable at that time due to the obligation for substantial future performance. During a recent tax audit of our Dutch subsidiary, the tax authorities have concluded that receipt of the payment was a taxable event at the time of receipt and taxes and interest are currently due on this payment in the amount of approximately €3.4 million ($4.5 million). Accordingly, we have provided for this contingency and recorded a current liability in the amount of the taxes and interest. We recorded a deferred tax asset for this contingency, however we have not recorded a valuation allowance against this deferred tax asset as it resulted from a timing difference on the revenue recognition of the receipt of the payment. We do not agree with the position that has been asserted and, if necessary, we will defend our position vigorously.

At December 31, 2006 and 2005, we had net operating loss carry forwards (“NOLs”) for financial statement purposes of approximately $116.0 million and $132.2 million, respectively, which are available to offset future taxable income through 2026. ATP (UK) had NOL’s of $120.6 and $329.0 million available for corporate tax carry-back at December 31, 2006 and 2005 respectively which are presented in Foreign Operations above.

Note 11—Commitments and Contingencies

Contingencies

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

F-24

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

insurance for such physical damages and loss of production insurance to replace lost cash flows resulting from downtime in excess of ninety days after the event. The company has submitted claims for the insured damages and any recoveries available under the loss of production income (“LOPI”) insurance policy. At December 31, 2006, we had a receivable for expected recovery of repair costs incurred related to the 2005 storms in the amount of $12.1 million, net of $4.4 million already received through that date. Additionally, we recorded other revenues in the amount of $5.6 million realized under the LOPI insurance policy. We expect to receive additional amounts related to LOPI insurance; however no such amounts will be recorded to the financial statements until they are realized.

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

During 2005, we purchased additional interest in the Tors property in the U.K. sector of the North Sea, and agreed to pay the seller contingent consideration of £2.0 million 180 days after first production, interest on such amount if the payment date meets certain criteria, a second contingent payment of £1.0 million after a cumulative 40 Bcf of production is achieved from the property, and a third contingent payment of £1.0 million after a cumulative 80 Bcf of production. As of December 31, 2006, we have paid the U.S dollar equivalent of the £2.0 million contingent liability due to the commencement of production at Tors.

During the fourth quarter of 2006, ATP (UK) acquired a 100% working interest in Block 49/12b in the Southern Gas Basin of the U.K. North Sea, which is an exploratory opportunity offsetting our Wenlock development. We agreed to pay the seller contingent consideration of £3.5 million after a cumulative 20 Bcf of production is achieved from the property.

Litigation

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

Note 12—Derivative Instruments and Price Risk Management Activities

Derivative financial instruments are carried on the balance sheet at fair value. If the derivative is designated as a fair value hedge, the changes in the fair value of the derivative and of the hedged item attributable to the hedged risk are recognized in earnings. If the derivative is designated as a cash flow hedge, the effective portions of changes in the fair value of the derivative are recorded in other comprehensive income and are recognized in the consolidated statement of operations when the hedged item affects earnings. Ineffective portions of changes in the fair value of cash flow hedges are recognized in current earnings. Derivative contracts that do not qualify for hedge accounting are recorded at fair value on our consolidated balance sheet and the associated unrealized gains and losses are recorded as a component of revenues in the current period.

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

At December 31, 2006 and 2005, Accumulated Other Comprehensive Income (Loss) included $1.0 million and $1.3 million of unrealized losses on our cash flow hedges, respectively. Gains and losses are reclassified from Accumulated Other Comprehensive Income to the consolidated statement of operations as a component of oil and gas revenues in the period the hedged production occurs. If any ineffectiveness occurs, amounts are recorded directly to the consolidated statement of operations as a component of oil and gas revenues. All of this deferred loss will be reversed during the period in which the forecasted transactions actually occur.

F-25

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

At December 31, 2006, we had oil derivatives that qualified as cash flow hedges with respect to our future production as follows:

	Period	Type	Volumes	Floor Price	Net Fair Value Asset (Liability)
				$/Bbl	($000)
Oil (Bbl)
Gulf of Mexico	2007	Puts	860,000	58.56	1,170

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

At December 31, 2006, we had fixed-price contracts in place for the following oil and gas volumes:

	Volumes	Average Fixed Price (1)
Natural gas (MMBtu)
Gulf of Mexico:
2007	7,400,000	8.76
2008	6,050,000	8.18
North Sea:
2007	7,750,000	10.26
2008	8,680,000	8.28
Oil (Bbl) – Gulf of Mexico:
2007	1,434,000	70.60
2008	732,000	73.25

(1) Includes the effect of basis differentials.

Note 13—ATP Energy Gas Purchase Transaction

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

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

ATP Energy received $6.0 million in connection with these transactions, of which $2.0 million was recorded as deferred revenue and $4.0 million was recorded as deferred obligations. The deferred revenue

F-26

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

amount of $2.0 million was a non-refundable fee received by ATP Energy and was recognized into income as earned over the life of the contract. At December 31, 2004, the deferred revenue amount was $0.7 million. The deferred obligation amount of $4.0 million represented the difference between the premium we agreed to pay for natural gas under the American Citigas contract and the obligation of American Citigas to partially reimburse us for such premium. The transaction was structured with American Citigas such that there was no financial impact to ATP Energy associated with the premium paid and reimbursement received other than the $2.0 million realized by ATP Energy. ATP Energy entered into the transactions to earn the fee for agreeing to market the volumes of natural gas specified in the American Citigas contract.

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

Note 14—Segment Information

The Company’s operations are focused in the Gulf of Mexico and in the North Sea. Management reviews and evaluates the operations separately of its Gulf of Mexico segment and its North Sea segment. Each segment is an aggregation of operations subject to similar economic and regulatory conditions such that they are likely to have similar long-term prospects for financial performance. The operations of both segments include natural gas and liquid hydrocarbon production and sales. The accounting policies of the reportable segments are the same as those described in Note 2 to the Consolidated Financial Statements. The Company evaluates the segments based on income (loss) from operations. Segment activity for the years ended December 31, 2006, 2005 and 2004 is as follows (in thousands):

	Gulf of Mexico		North Sea			Eliminations			Total
2006
Revenues	$	327,609	$	92,212			—		$	419,821
Depreciation, depletion and amortization		126,708		42,996			—			169,704
Impairment of oil and gas properties		19,520		—			—			19,520
Income from operations		80,361		24,904			—			105,265
Interest income		7,231		705			(3,404	)		4,532
Interest expense		57,978		3,444			(3,404	)		58,018
Loss on extinguishment of debt		28,115		—			—			28,115
Income tax expense (benefit)		570		16,224			—			16,794
Additions to oil and gas properties		379,712		281,639			—			661,351
Total assets		983,147		463,911			—			1,447,058
2005
Revenues	$	135,175	$	11,499		$	—		$	146,674
Depreciation, depletion and amortization		59,144		4,925			—			64,069
Income from operations		21,661		7,013			—			28,674
Interest income		3,879		185			—			4,064
Interest expense		35,718		2			—			35,720
Income tax expense (benefit)		78		75			—			153
Additions to oil and gas properties		296,060		124,456			—			420,516
Total assets		610,250		213,513			—			823,763
2004
Revenues	$	98,236	$	17,887		$	—		$	116,123
Depreciation, depletion and amortization		41,020		14,617			—			55,637
Income from operations		30,875		(4,780	)		—			26,095
Interest income		459		168			—			627
Interest expense		22,262		—			—			22,262
Loss on extinguishment of debt		3,326		—			—			3,326
Income tax expense (benefit)		29		29			—			58
Additions to oil and gas properties		78,521		8,847			—			87,368
Total assets		317,043		55,104			—			372,147

F-27

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Note 15—Summarized Quarterly Financial Data (Unaudited)

(In Thousands, Except Per Share Amounts)

	First			Second			Third			Fourth
	Quarter			Quarter			Quarter			Quarter
2006
Revenues	$	45,245		$	108,885		$	132,822		$	132,869
Costs and expenses		37,691			77,372			101,701			97,792
Income from operations		7,554			31,513			31,121			35,077
Net income (loss) available to common shareholders (1)(2)		(9,863	)		6,374			1,173			(37,032	)
Net income (loss) per common share:
Basic and diluted (3)	$	(0.34	)	$	0.21		$	0.04		$	(1.24	)
2005
Revenues	$	36,980		$	33,488		$	26,342		$	49,864
Costs and expenses		30,181			29,220			24,915			33,684
Income from operations		6,799			4,268			1,427			16,180
Net income (loss) available to common shareholders		1,000			(3,322	)		(10,577	)		325
Net income (loss) per common share:
Basic and diluted (3)	$	0.03		$	(0.11	)	$	(0.36	)	$	0.01

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

(2) Net income (loss) available to common shareholders is net of preferred dividends of $6.8 million in the first quarter, $11.0 million in the second quarter, $11.5 million in the third quarter and $7.6 million in the fourth quarter. The preferred stock was redeemed on or about November 22, 2006.

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

Note 16—Subsequent Event

On January 8, 2007, we completed the acquisition of a 50% working interest in Mississippi Canyon (“MC”) Block 305 (“Aconcagua”), a 16.67% working interest in MC Block 348 (“Camden Hills”), and an additional 25.834% interest in the Canyon Express Pipeline Common System (“Canyon Express”). Aconcagua is currently producing approximately 10 MMcfe per day net to our interest and Camden Hills produced previously, but is currently shut-in. Both Aconcagua (located in 6,820’ of water) and Camden Hills (located in 7,112’ of water), along with MC 217 (“King’s Peak”) produce through Canyon Express, in which we now owns a 45.084% interest as a result of this acquisition.

We received net cash of $4.7 million at closing, which consisted of the net proceeds from production since July 1, 2006 of $5.7 million, partially offset by the $1.0 million acquisition price at July 1, 2006. We assumed certain abandonment costs in conjunction with this acquisition and accordingly recorded a $9.8 million abandonment liability. At closing, the Seller agreed to provide continuing operations for the properties on our behalf until March 31, 2007, at which time we will assume the operations.

F-28

ATP OIL & GAS CORPORATION

SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES

Oil and Gas Reserves and Related Financial Data (Unaudited)

Costs Incurred

The following table sets forth certain information with respect to costs incurred in connection with our oil and gas producing activities during the year ended December 31, 2006, 2005 and 2004 (in thousands):

	Gulf of Mexico			North Sea		Total
2004
Property acquisition costs:
Unproved	$	1,192		$	—	$	1,192
Development costs		65,667			8,847		74,514
Exploratory costs		11,662			—		11,662
Oil and gas expenditures		78,521			8,847		87,368
Asset retirement costs		2,935			—		2,935
Gain on abandonment		(251	)		—		(251	)
	$	81,205		$	8,847	$	90,052
2005
Property acquisition costs:
Proved	$	62,117		$	7,034	$	69,151
Unproved		5,790			—		5,790
Development costs (1)		231,703			125,941		357,644
Exploratory costs		21,989			—		21,989
Oil and gas expenditures		321,599			132,975		454,574
Asset retirement costs		37,494			6,406		43,900
Gain on abandonment		(732	)		—		(732	)
	$	358,361		$	139,381	$	497,742
2006
Property acquisition costs:
Proved	$	39,136		$	—	$	39,136
Unproved		5,147			—		5,147
Development costs		282,095			264,525		546,620
Exploratory costs		40,449			—		40,449
Oil and gas expenditures		366,827			264,525		631,352
Asset retirement costs		18,966			26,112		45,078
Loss on abandonment		9,603			—		9,603
	$	395,396		$	290,637	$	686,033

(1) For 2005, the Gulf of Mexico total excludes $7.7 million of IDC-related and $3.9 million of facilities-related costs which are expected to be part of our accrued insurance recoveries.

Oil and Natural Gas Reserves

Proved reserves are estimated quantities of oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are proved reserves that can reasonably be expected to be recovered through existing wells with existing equipment and operating methods.

In all years presented, 100% of our reserves were prepared by independent petroleum engineers. Currently we use Ryder Scott Company, L.P., DeGolyer and MacNaughton, Collarini Associates and RPS Energy.

F-29

ATP OIL & GAS CORPORATION

SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES—(Continued)

The following table sets forth our net proved oil and gas reserves at December 31, 2003, 2004, 2005 and 2006 and the changes in net proved oil and gas reserves for the years ended December 31, 2004, 2005 and 2006:

	Natural Gas (MMcf)						Oil, Condensate and Natural Gas Liquids (MBbls)
	Gulf of		North				Gulf of		North
	Mexico		Sea		Total		Mexico		Sea		Total
Proved Reserves at December 31, 2003	130,033		101,032		231,065		11,943		2		11,945
Revisions of previous estimates	83		(2,062	)	(1,979	)	901		—		901
Extensions and discoveries	2,002		—		2,002		7		—		7
Sales of minerals in place	(8,044	)	—		(8,044	)	(419	)	—		(419	)
Production	(13,347	)	(4,468	)	(17,815	)	(766	)	—		(766	)
Proved Reserves at December 31, 2004	110,727		94,502		205,229		11,666		2		11,668
Revisions of previous estimates	(5,845	)	(309	)	(6,154	)	213		—		213
Purchases of minerals in place	71,504		33,094		104,598		437		—		437
Extensions and discoveries	2,119		76,383		78,502		15		17,650		17,665
Sales of minerals in place	(599	)	(12,860	)	(13,459	)	(200	)	—		(200	)
Production	(14,359	)	(1,255	)	(15,614	)	(717	)	—		(717	)
Proved Reserves at December 31, 2005	163,547		189,555		353,102		11,414		17,652		29,066
Revisions of previous estimates	(27,532	)	(5,290	)	(32,822	)	6,417		(79	)	6,338
Purchases of minerals in place	26,533		—		26,533		18,289		—		18,289
Extensions and discoveries	13,637		—		13,637		855		—		855
Production	(19,195	)	(12,029	)	(31,224	)	(3,250	)	(23	)	(3,273	)
Proved Reserves at December 31, 2006	156,990		172,236		329,226		33,725		17,550		51,275
	Natural Gas (MMcf)						Oil, Condensate and Natural Gas Liquids (MBbls)
	Gulf of		North				Gulf of		North
	Mexico		Sea		Total		Mexico		Sea		Total
Proved Developed Reserves at
December 31, 2004	37,876		9,210		47,086		2,222		—		2,222
December 31, 2005	78,833		13,979		92,812		5,924		2		5,926
December 31, 2006	83,099		47,695		130,794		13,839		3		13,842

F-30

ATP OIL & GAS CORPORATION

SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES—(Continued)

Standardized Measure

The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves for year ended December 31, 2006, 2005 and 2004 is shown below (in thousands):

	Gulf of Mexico			North Sea			Total
2004
Future cash inflows	$	1,142,853		$	500,755		$	1,643,608
Future operating expenses		(161,795	)		(91,477	)		(253,272	)
Future development costs		(272,317	)		(142,340	)		(414,657	)
Future net cash flows		708,741			266,938			975,679
Future income taxes		(200,084	)		(81,755	)		(281,839	)
Future net cash flows, after income taxes		508,657			185,183			693,840
10% annual discount per annum		(126,838	)		(46,719	)		(173,557	)
Standardized measure of discounted future net cash flows	$	381,819		$	138,464		$	520,283
2005
Future cash inflows	$	2,302,045		$	3,258,706		$	5,560,751
Future operating expenses		(218,912	)		(326,468	)		(545,380	)
Future development costs		(327,584	)		(836,394	)		(1,163,978	)
Future net cash flows		1,755,549			2,095,844			3,851,393
Future income taxes		(379,902	)		(877,744	)		(1,257,646	)
Future net cash flows, after income taxes		1,375,647			1,218,100			2,593,747
10% annual discount per annum		(274,793	)		(453,374	)		(728,167	)
Standardized measure of discounted future net cash flows	$	1,100,854		$	764,726		$	1,865,580
2006
Future cash inflows	$	2,713,100		$	1,811,271		$	4,524,371
Future operating expenses		(323,248	)		(340,167	)		(663,415	)
Future development costs		(959,078	)		(954,284	)		(1,913,362	)
Future net cash flows		1,430,774			516,820			1,947,594
Future income taxes		(296,080	)		(92,183	)		(388,263	)
Future net cash flows, after income taxes		1,134,694			424,637			1,559,331
10% annual discount per annum		(289,524	)		(254,729	)		(544,253	)
Standardized measure of discounted future net cash flows	$	845,170		$	169,908		$	1,015,078

Future cash inflows are computed by applying year-end prices of oil and gas to the year-end estimated future production of proved oil and gas reserves. The base prices used for the standardized measure calculation were public market prices on December 31, 2006 adjusted by differentials to those market prices. These price adjustments were done on a property-by-property basis for the quality of the oil and natural gas and for transportation to the appropriate location. Estimates of future development and production costs are based on year-end costs and assume continuation of existing economic conditions and year-end prices. We will incur significant capital in the development of our Gulf of Mexico and North Sea oil and gas properties. We believe with reasonable certainty that we will be able to obtain such capital in the normal course of business. The estimated future net cash flows are then discounted using a rate of 10 percent per year to reflect the estimated timing of the future cash flows. The standardized measure of discounted cash flows is the future net cash flows less the computed discount.

F-31

ATP OIL & GAS CORPORATION

SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES—(Continued)

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

	Natural Gas						Oil, Condensate and Natural Gas Liquids
			U.K.		Dutch				U.K.		Dutch
	Gulf of		North		North		Gulf of		North		North
	Mexico		Sea		Sea		Mexico		Sea		Sea
December 31, 2004		6.180		5.509		4.950		43.46		—		40.02
December 31, 2005		10.080		12.613		6.120		61.11		59.40		58.62
December 31, 2006	$	5.635	$	4.720	$	8.540	$	61.05	$	61.49	$	66.87

Changes in Standardized Measure

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

	Gulf of Mexico			North Sea			Total
2004
Beginning of year	$	409,390		$	137,662		$	547,052
Sales of oil and gas, net of production costs		(83,636	)		(14,156	)		(97,792	)
Net changes in income taxes		19,431			2,705			22,136
Net changes in price and production costs		63,623			13,937			77,560
Revisions of quantity estimates		22,068			(6,366	)		15,702
Extensions and discoveries		10,503			—			10,503
Accretion of discount		57,472			19,930			77,402
Development costs incurred		37,513			1,779			39,292
Changes in estimated future development costs		(43,302	)		(8,242	)		(51,544	)
Sales of minerals-in-place		(34,328	)		—			(34,328	)
Changes in production rates, timing and other		(76,915	)		(8,785	)		(85,700	)
		(27,571	)		802			(26,769	)
End of year	$	381,819		$	138,464		$	520,283
2005
Beginning of year	$	381,819		$	138,464		$	520,283
Sales of oil and gas, net of production costs		(114,938	)		(9,505	)		(124,443	)
Net changes in income taxes		(145,748	)		(468,180	)		(613,928	)
Net changes in price and production costs		436,929			592,277			1,029,206
Revisions of quantity estimates		(29,865	)		(4,345	)		(34,210	)
Extensions and discoveries		20,677			401,910			422,587
Accretion of discount		52,772			19,740			72,512
Development costs incurred		104,171			76,872			181,043
Changes in estimated future development costs		(29,273	)		(18,488	)		(47,761	)
Purchases of minerals-in-place		403,481			181,398			584,879
Sales of minerals-in-place		(8,472	)		(86,315	)		(94,787	)
Changes in production rates, timing and other		29,301			(59,102	)		(29,801	)
		719,035			626,262			1,345,297
End of year	$	1,100,854		$	764,726		$	1,865,580
2006
Beginning of year	$	1,100,854		$	764,726		$	1,865,580
Sales of oil and gas, net of production costs		(266,663	)		(74,541	)		(341,204	)
Net changes in income taxes		66,437			488,796			555,233
Net changes in price and production costs		(502,759	)		(835,690	)		(1,338,449	)
Revisions of quantity estimates		53,283			(18,842	)		34,441
Extensions and discoveries		86,468		$	—			86,468
Accretion of discount		139,250			129,184			268,434
Development costs incurred		67,750			344,158			411,908
Changes in estimated future development costs		(13,336	)		(186,158	)		(199,494	)
Purchases of minerals-in-place		168,595			—			168,595
Changes in production rates, timing and other		(54,709	)		(441,725	)		(496,434	)
		(255,684	)		(594,818	)		(850,502	)
End of year	$	845,170		$	169,908		$	1,015,078

F-32

ATP OIL & GAS CORPORATION

SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES—(Continued)

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

Capitalized Costs Related to Oil and Gas Producing Activities

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

	Gulf of Mexico			North Sea			Total
2004
Oil and gas properties:
Unproved	$	8,063		$	2,453		$	10,516
Proved		381,004			58,883			439,887
Accumulated depletion, impairment and amortization		(221,996	)		(15,201	)		(237,197	)
	$	167,071		$	46,135		$	213,206
2005
Oil and gas properties:
Unproved	$	8,607		$	275		$	8,882
Proved		706,301			184,101			890,402
Accumulated depletion, impairment and amortization		(253,831	)		(18,032	)		(271,863	)
	$	461,077		$	166,344		$	627,421
2006
Oil and gas properties:
Unproved	$	54,012		$	2,177		$	56,189
Proved		1,019,324			463,839			1,483,163
Accumulated depletion, impairment and amortization		(378,523	)		(65,184	)		(443,707	)
	$	694,813		$	400,832		$	1,095,645

Results of Operations for Oil and Gas Producing Activities

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

F-33

ATP OIL & GAS CORPORATION

SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES—(Continued)

	Gulf of Mexico			North Sea			Total
2004
Oil and gas production	$	98,236		$	17,887		$	116,123
Lease operating		15,772			3,759			19,531
Exploration		467			530			997
Depreciation, depletion and amortization		40,816			14,450			55,266
Accretion		1,572			497			2,069
Gain loss on abandonment		(251	)		—			(251	)
(Gain) loss on disposal of oil and gas properties		(6,011	)		—			(6,011	)
Income (loss) before income taxes		45,871			(1,349	)		44,522
Income tax (expense) benefit		(16,055	)		657			(15,398	)
Results of operations from producing activities (excluding corporate overhead and interest costs)	$	29,816		$	(692	)	$	29,124
2005
Oil and gas production	$	135,175		$	11,499		$	146,674
Lease operating		21,624			2,005			23,629
Exploration		6,075			133			6,208
Depreciation, depletion and amortization		58,857			4,768			63,625
Accretion		2,476			762			3,238
Gain loss on abandonment		(732	)		—			(732	)
(Gain) loss on disposal of oil and gas properties		4,681			(7,424	)		(2,743	)
Income (loss) before income taxes		42,194			11,255			53,449
Income tax (expense) benefit		(14,768	)		(5,648	)		(20,416	)
Results of operations from producing activities (excluding corporate overhead and interest costs)	$	27,426		$	5,607		$	33,033
2006
Oil and gas production	$	321,970		$	92,212		$	414,182
Other revenues		5,639			—			5,639
Total revenues		327,609			92,212			419,821
Lease operating		54,775			17,671			72,446
Exploration		1,465			766			2,231
Depreciation, depletion and amortization		126,365			42,781			169,146
Impairment of oil and gas properties		19,520			—			19,520
Accretion		6,067			2,008			8,075
(Gain) loss on abandonment		9,603			—			9,603
Income (loss) before income taxes		109,814			28,986			138,800
Income tax (expense) benefit		(38,435	)		(12,845	)		(51,280	)
Results of operations from producing activities (excluding corporate overhead and interest costs)	$	71,379		$	16,141		$	87,520

F-34

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

SCHEDULE II—VALUATION AND QUALIFYING ACCOUNTS

FOR EACH OF THE THREE YEARS ENDED DECEMBER 31, 2006

(In Thousands)

	Balance at Beginning of Period		Charged to Costs and Expenses			Charged to Other Accounts			Deduction		Balance at End of Period
2004
Allowance for doubtful accounts	$	1,266	$	233		$	—		$	—	$	1,499
Valuation allowance on deferred tax assets		33,646		(2,993	)		305			—		30,958
2005
Allowance for doubtful accounts	$	1,499	$	—		$	(1,132	)	$	—	$	367
Valuation allowance on deferred tax assets		30,958		(4,242	)		3,546			—		30,262
2006
Allowance for doubtful accounts	$	367	$	126		$	(84	)	$	—	$	409
Valuation allowance on deferred tax assets		30,262		(5,302	)		166					25,126

S-1

EX-10.2

Exhibit 10.2

EXHIBIT A TO ATP OIL & GAS

CORPORATION AMENDMENT

AGREEMENT DATED AS OF    

DECEMBER 28, 2006                   

THIRD AMENDED AND RESTATED CREDIT AGREEMENT

dated as of December 28, 2006,

among

ATP OIL & GAS CORPORATION,

THE LENDERS NAMED HEREIN,

and

CREDIT SUISSE,

as Administrative Agent and Collateral Agent

CREDIT SUISSE SECURITIES (USA) LLC,

as Sole Bookrunner, Sole Lead Arranger, Syndication Agent and Documentation Agent

[CS&M Ref No. 5865-238]

TABLE OF CONTENTS

ARTICLE I

DEFINITIONS

SECTION 1.01.	Defined Terms	2
SECTION 1.02.	Terms Generally	28
SECTION 1.03.	Pro Forma Calculations	28
SECTION 1.04.	Classification of Loans and Borrowings	29
ARTICLE II
THE CREDITS
SECTION 2.01.	Commitments	29
SECTION 2.02.	Loans	29
SECTION 2.03.	Borrowing Procedure	31
SECTION 2.04.	Evidence of Debt; Repayment of Loans	31
SECTION 2.05.	Fees	32
SECTION 2.06.	Interest on Loans	33
SECTION 2.07.	Default Interest	33
SECTION 2.08.	Alternate Rate of Interest	34
SECTION 2.09.	Termination and Reduction of Commitments	34
SECTION 2.10.	Conversion and Continuation of Borrowings	34
SECTION 2.11.	Repayment of Term Borrowings	36
SECTION 2.12.	Optional Prepayment	37
SECTION 2.13.	Mandatory Prepayments	37
SECTION 2.14.	Reserve Requirements; Change in Circumstances	39
SECTION 2.15.	Change in Legality	40
SECTION 2.16.	Indemnity	40
SECTION 2.17.	Pro Rata Treatment	41
SECTION 2.18.	Sharing of Setoffs	41
SECTION 2.19.	Payments	42
SECTION 2.20.	Taxes	42
SECTION 2.21.	Assignment of Commitments or Loans Under Certain Circumstances; Duty to Mitigate	43
SECTION 2.22.	Application of Prepayment by Type of Term Loans	44
SECTION 2.23.	Letters of Credit	45

ARTICLE III
REPRESENTATIONS AND WARRANTIES
SECTION 3.01.	Organization; Powers	49
SECTION 3.02.	Authorization	49
SECTION 3.03.	Enforceability	49
SECTION 3.04.	Governmental Approvals	49
SECTION 3.05.	Financial Statements	49
SECTION 3.06.	No Material Adverse Change	50
SECTION 3.07.	Title to Properties; Possession Under Leases	50
SECTION 3.08.	Subsidiaries	51
SECTION 3.09.	Litigation; Compliance with Laws	51
SECTION 3.10.	Agreements	51
SECTION 3.11.	Federal Reserve Regulations	52
SECTION 3.12.	Investment Company Act	52
SECTION 3.13.	Use of Proceeds	52
SECTION 3.14.	Tax Returns	52
SECTION 3.15.	No Material Misstatements	52
SECTION 3.16.	Employee Benefit Plans	52
SECTION 3.17.	Environmental Matters	53
SECTION 3.18.	Insurance	53
SECTION 3.19.	Security Documents	53
SECTION 3.20.	Location of Oil and Gas Properties, Real Property and Leased Premises	54
SECTION 3.21.	Future Commitments	54
SECTION 3.22.	Labor Matters	54
SECTION 3.23.	Solvency	55
ARTICLE IV
CONDITIONS OF LENDING
ARTICLE V
AFFIRMATIVE COVENANTS
SECTION 5.01.	Existence; Businesses; Oil and Gas Properties	56
SECTION 5.02.	Insurance	56
SECTION 5.03.	Obligations and Taxes	57
SECTION 5.04.	Financial Statements, Reserve Reports, etc	58
SECTION 5.05.	Litigation and Other Notices	60
SECTION 5.06.	Information Regarding Collateral	60
SECTION 5.07.	Maintaining Records; Access to Properties and Inspections	60
SECTION 5.08.	Use of Proceeds	61

ii

SECTION 5.09.	Further Assurances	61
SECTION 5.10.	Commodity Hedging Agreements	62

ARTICLE VI
NEGATIVE COVENANTS
SECTION 6.01.	Indebtedness	62
SECTION 6.02.	Liens	64
SECTION 6.03.	Sale and Lease-Back Transactions	66
SECTION 6.04.	Investments, Loans, Advances and Oil and Gas Property Acquisitions	66
SECTION 6.05.	Mergers, Consolidations, Sales of Assets and Acquisitions	67
SECTION 6.06.	Restricted Payments; Restrictive Agreements	68
SECTION 6.07.	Transactions with Affiliates	69
SECTION 6.08.	Business of the Borrower and Subsidiaries	69
SECTION 6.09.	Other Indebtedness and Agreements	69
SECTION 6.10.	Forward Sales	70
SECTION 6.11.	Limitation on Commodity Hedging	70
SECTION 6.12.	Interest Coverage Ratio	70
SECTION 6.13.	Maximum Leverage Ratio	70
SECTION 6.14.	Minimum Current Ratio	70
SECTION 6.15.	Minimum Asset Coverage Ratios	70
SECTION 6.16.	Designated Senior Debt	70
SECTION 6.17.	Fiscal Year	70
ARTICLE VII
EVENTS OF DEFAULT
ARTICLE VIII
THE ADMINISTRATIVE AGENT AND THE COLLATERAL AGENT
ARTICLE IX
MISCELLANEOUS
SECTION 9.01.	Notices	75
SECTION 9.02.	Survival of Agreement	76
SECTION 9.03.	Binding Effect	76
SECTION 9.04.	Successors and Assigns	76
SECTION 9.05.	Expenses; Indemnity	80

iii

SECTION 9.06.	Right of Setoff	81
SECTION 9.07.	Applicable Law	81
SECTION 9.08.	Waivers; Amendment	82
SECTION 9.09.	Interest Rate Limitation	83
SECTION 9.10.	Entire Agreement	83
SECTION 9.11.	WAIVER OF JURY TRIAL	83
SECTION 9.12.	Severability	83
SECTION 9.13.	[Intentionally Omitted].	84
SECTION 9.14.	Headings	84
SECTION 9.15.	Jurisdiction; Consent to Service of Process	84
SECTION 9.16.	Confidentiality	84
SECTION 9.17.	USA Patriot Act Notice	85
SECTION 9.18.	Parallel Debt	85
SECTION 9.19.	Effect of Restatement	86

Schedules
Schedule 1.01(a)	Approved Counterparties
Schedule 1.01(b)	Mortgaged Properties
Schedule 1.01(c)	Subsidiary Guarantors
Schedule 3.08	Subsidiaries
Schedule 3.09	Litigation
Schedule 3.10	Certain Agreements
Schedule 3.17	Environmental Matters
Schedule 3.18	Insurance
Schedule 3.19(a)	Domestic Filing Offices
Schedule 3.19(c)	Mortgage Filing Offices
Schedule 3.19(d)	Foreign Filing Offices
Schedule 3.20(a)	Oil and Gas Properties
Schedule 3.20(b)	Owned Property
Schedule 3.20(c)	Other Leased Property
Schedule 4(d)	Local Counsel
Schedule 6.01	Outstanding Indebtedness on Prior Restatement Date
Schedule 6.02	Liens Existing on Prior Restatement Date
Exhibits
EXHIBIT A	Form of Administrative Questionnaire
EXHIBIT B	Form of Assignment and Acceptance
EXHIBIT C	Form of Borrowing Request
EXHIBIT D	Form of UK Pledge Agreement
EXHIBIT E	Form of Dutch Pledge Agreement
EXHIBIT F-1	Form of Opinion of Jackson Walker L.L.P.
EXHIBIT F-2	Form of Local Counsel Opinions
EXHIBIT G	Form of Mortgage

iv

THIRD AMENDED AND RESTATED CREDIT AGREEMENT dated as of December 28, 2006, among ATP OIL & GAS CORPORATION, a Texas corporation (the “Borrower”), the Lenders (as defined in Article I), and CREDIT SUISSE, as administrative agent (in such capacity, the “Administrative Agent”) and as collateral agent (in such capacity, the “Collateral Agent”) for the Lenders.

The Borrower, the Administrative Agent, the Collateral Agent and the lenders party thereto (the “Existing Lenders”) previously entered into the Second Amended and Restated Credit Agreement dated as of June 22, 2006, as amended by Amendment No. 1 and Agreement dated as of November 22, 2006 (as so amended, the “Existing Credit Agreement”), under which the Existing Lenders extended credit to the Borrower in the form of term loans in an aggregate principal amount of $900,000,000 (of which $898,687,500 aggregate principal amount (the “Existing Term Loans”) is outstanding immediately prior to the Restatement Date (such term and each other capitalized term used but not defined in this introductory statement having the meaning given it in Article I)).

The Borrower has requested that the Revolving Credit Lenders agree to extend credit in the form of Revolving Loans at any time and from time to time prior to the Revolving Credit Maturity Date, in an aggregate principal amount at any time outstanding not in excess of $50,000,000. The Borrower has requested the Issuing Bank to issue Letters of Credit, in an aggregate face amount at any time outstanding not in excess of $50,000,000, to support payment obligations incurred in the ordinary course of business by the Borrower and its Subsidiaries. The proceeds of the Revolving Loans are to be used solely for general corporate purposes of the Borrower and its Subsidiaries.

The Revolving Credit Lenders are willing to extend such credit to the Borrower, and the Issuing Bank is willing to issue Letters of Credit for the account of the Borrower, in each case on the terms and subject to the conditions set forth herein.

The Borrower and the Lenders desire to amend and restate the Existing Credit Agreement in the form hereof to, among other things, set forth the terms and conditions under which the Revolving Credit Lenders and Issuing Bank will make Revolving Loans and issue Letters of Credit, respectively, to the Borrower.

The amendment and restatement of the Existing Credit Agreement evidenced by this Agreement shall become effective as provided in the Amendment Agreement.

Accordingly, the parties hereto agree as follows:

ARTICLE I

Definitions

SECTION 1.01. Defined Terms. As used in this Agreement, the following terms shall have the meanings specified below:

“ABR”, when used in reference to any Loan or Borrowing, refers to whether such Loan, or the Loans comprising such Borrowing, are bearing interest at a rate determined by reference to the Alternate Base Rate.

“Adjusted LIBO Rate” shall mean, with respect to any Eurodollar Borrowing for any Interest Period, an interest rate per annum equal to the product of (a) the LIBO Rate in effect for such Interest Period and (b) Statutory Reserves.

“Administrative Agent” shall have the meaning assigned to such term in the preamble to this Agreement.

“Administrative Agent Fees” shall have the meaning assigned to such term in Section 2.05(b).

“Administrative Questionnaire” shall mean an Administrative Questionnaire in the form of Exhibit A, or such other form as may be supplied from time to time by the Administrative Agent.

“Affiliate” shall mean, when used with respect to a specified person, another person that directly, or indirectly through one or more intermediaries, Controls or is Controlled by or is under common Control with the person specified; provided, however, that, for purposes of Section 6.07, the term “Affiliate” shall also include any person that directly or indirectly owns 5% or more of any class of Equity Interests of the person specified or that is an officer or director of the person specified.

“Agents” shall have the meaning assigned to such term in Article VIII.

“Aggregate Revolving Credit Exposure” shall mean the aggregate amount of the Revolving Credit Lenders’ Revolving Credit Exposures.

“Alternate Base Rate” shall mean, for any day, a rate per annum equal to the greater of (a) the Prime Rate in effect on such day and (b) the Federal Funds Effective Rate in effect on such day plus  ¹/2 of 1.00%. If the Administrative Agent shall have determined (which determination shall be conclusive absent manifest error) that it is unable to ascertain the Federal Funds Effective Rate for any reason, including the inability or failure of the Administrative Agent to obtain sufficient quotations in accordance with the terms of the definition thereof, the Alternate Base Rate shall be determined without regard to clause (b) of the preceding sentence until the circumstances giving rise to such inability no longer exist. Any change in the Alternate

2

Base Rate due to a change in the Prime Rate or the Federal Funds Effective Rate shall be effective on the effective date of such change in the Prime Rate or the Federal Funds Effective Rate, as the case may be.

“Amendment Agreement” shall mean the Amendment No. 2 and Agreement dated as of December 28, 2006, effecting, among other things, the amendment and restatement of the Existing Credit Agreement.

“Applicable Percentage” shall mean, for any day (a) with respect to any Eurodollar Loan, 3.50%, or (b) with respect to any ABR Loan, 2.50%.

“Approved Counterparty” shall mean, with respect to any Hedging Agreement, a counterparty that, at the time such Hedging Agreement is entered into, is (a) the Administrative Agent or any Lender or any Affiliate of the Administrative Agent or a Lender, (b) any person whose senior unsecured long-term debt is rated as Investment Grade, (c) those persons listed on Schedule 1.01(a) or (d) any other person that is reasonably acceptable to the Administrative Agent.

“Asset Coverage Ratios” shall mean the Reserve Coverage Ratio and the PDP Coverage Ratio.

“Asset Sale” shall mean the sale, transfer or other disposition (by way of merger, casualty, condemnation or otherwise) by the Borrower or any of the Subsidiaries to any person other than the Borrower or any Subsidiary Guarantor of (a) any Equity Interests of any of the Subsidiaries (other than directors’ qualifying shares) or (b) any other assets of the Borrower or any of the Subsidiaries (other than (i) Hydrocarbons and other inventory, damaged, obsolete or worn out assets, scrap and Permitted Investments, in each case disposed of or made in the ordinary course of business, or (ii) dispositions between or among Foreign Subsidiaries), provided that (x) any asset sale or series of related asset sales described in clause (b) above having a value not in excess of $500,000 and (y) any asset sale entered into by the Borrower or any Subsidiary in the good faith exercise of its business judgment, involving the sale, transfer or other disposition by the Borrower or such Subsidiary of Hydrocarbon Interests in exchange for a commitment of the transferee to bear a disproportionate share of the costs attributable to the Oil and Gas Properties to which such Hydrocarbon Interests relate, shall be deemed not to be an “Asset Sale” for purposes of this Agreement.

“Assignment and Acceptance” shall mean an assignment and acceptance entered into by a Lender and an assignee, and accepted by the Administrative Agent, in the form of Exhibit B or such other form as shall be approved by the Administrative Agent.

“Average Revolving Loan Utilization” means the average daily aggregate Revolving Credit Exposure during the preceding quarter (or other period commencing with the Restatement Date or ending with the Revolving Credit Maturity Date or the date on which the Commitments of a Revolving Credit Lender shall expire or be terminated), divided by the average daily aggregate Revolving Credit Commitments during the corresponding period.

3

“Bcfe” shall mean billion cubic feet equivalent, determined by using the ratio of six thousand cubic feet of natural gas to one stock tank barrel (or 42 U.S. gallons liquid volume) of crude oil, condensate or natural gas liquids.

“Board” shall mean the Board of Governors of the Federal Reserve System of the United States of America.

“Borrower” shall have the meaning assigned to such term in the preamble to this Agreement.

“Borrowing” shall mean Loans of the same Class and Type made, converted or continued on the same date and, in the case of Eurodollar Loans, as to which a single Interest Period is in effect.

“Borrowing Request” shall mean a request by the Borrower in accordance with the terms of Section 2.03 and substantially in the form of Exhibit C, or such other form as shall be approved by the Administrative Agent.

“Breakage Event” shall have the meaning assigned to such term in Section 2.16.

“Business Day” shall mean any day other than a Saturday, Sunday or day on which banks in New York City are authorized or required by law to close; provided, however, that when used in connection with a Eurodollar Loan, the term “Business Day” shall also exclude any day on which banks are not open for dealings in dollar deposits in the London interbank market.

“Capital Expenditures” shall mean, for any period, (a) the additions to property, plant and equipment and other capital expenditures of the Borrower and its consolidated Subsidiaries that are (or should be) set forth in a consolidated statement of cash flows of the Borrower for such period prepared in accordance with GAAP and (b) Capital Lease Obligations or Synthetic Lease Obligations incurred by the Borrower and its consolidated Subsidiaries during such period, but excluding in each case any such expenditure made to restore, replace or rebuild property to the condition of such property immediately prior to any damage, loss, destruction or condemnation of such property, to the extent such expenditure is made with insurance proceeds, condemnation awards or damage recovery proceeds relating to any such damage, loss, destruction or condemnation.

“Capital Lease Obligations” of any person shall mean the obligations of such person to pay rent or other amounts under any lease of (or other arrangement conveying the right to use) real or personal property, or a combination thereof, which obligations are required to be classified and accounted for as capital leases on a balance sheet of such person under GAAP, and the amount of such obligations shall be the capitalized amount thereof determined in accordance with GAAP.

A “Change in Control” shall be deemed to have occurred if (a) any “person” or “group” (within the meaning of Rule 13d-5 promulgated under the Securities Exchange Act of 1934, as amended, as such Rule is in effect on the date hereof) other than the Management Investors shall own, directly or indirectly, beneficially or of record, shares representing more than 40% of the aggregate ordinary voting power represented by the issued and outstanding capital stock of the

4

Borrower, and the percentage of the aggregate ordinary voting power represented by the shares of capital stock of the Borrower owned by such person or group exceeds the percentage of the aggregate ordinary voting power represented by the shares of capital stock of the Borrower owned by the Management Investors; (b) a majority of the seats (other than vacant seats) on the board of directors of the Borrower shall at any time be occupied by persons who were neither (i) nominated by the board of directors of the Borrower nor (ii) appointed by directors so nominated; or (c) any change in control (or similar event, however denominated) with respect to the Borrower or any Subsidiary shall occur under and as defined in any Junior Financing Documentation or any other indenture or agreement in respect of Material Indebtedness to which the Borrower or a Subsidiary is a party.

“Change in Law” shall mean (a) the adoption of any law, rule or regulation after the Prior Restatement Date, (b) any change in any law, rule or regulation or in the interpretation or application thereof by any Governmental Authority after the Prior Restatement Date or (c) compliance by any Lender or the Issuing Bank (or, for purposes of Section 2.14, by any lending office of such Lender or by such Lender’s or Issuing Bank’s holding company, if any) with any request, guideline or directive (whether or not having the force of law) of any Governmental Authority made or issued after the Prior Restatement Date; provided, however, that with respect to the Issuing Bank or any Revolving Credit Lender, all references in this definition to the Prior Restatement Date shall be deemed to be references to the Restatement Date.

“Charges” shall have the meaning assigned to such term in Section 9.09.

“Class”, when used in reference to any Loan or Borrowing, refers to whether such Loan, or the Loans comprising such Borrowing, are Revolving Loans or Term Loans and, when used in reference to any Commitment, refers to whether such Commitment is a Revolving Credit Commitment or Term Loan Commitment.

“CNI Growth Amount” shall mean, on any date of determination, (a) 50% of Cumulative Consolidated Net Income (or, in the case Cumulative Consolidated Net Income at the time of determination is a deficit, minus 100% of such deficit) minus (b) the aggregate amount at the time of determination of Restricted Payments made since the Prior Restatement Date pursuant to Section 6.06(a)(ii)(C)(y).

“Code” shall mean the Internal Revenue Code of 1986, as amended from time to time.

“Collateral” shall mean all the “Collateral” as defined in any Security Document, and shall also include the Mortgaged Properties and the Foreign Pledged Collateral.

“Collateral Agent” shall have the meaning assigned to such term in the preamble to this Agreement.

“Commitment” shall mean, with respect to any Lender, such Lender’s Revolving Credit Commitment and Term Loan Commitment.

“Commitment Fee” shall have the meaning assigned to such term in Section 2.05(a).

5

“Commodity Hedging Agreement” shall mean a commodity price risk management or purchase agreement or similar arrangement (including commodity price swap agreements, forward agreements or contracts of sale which provide for prepayment for deferred shipment or delivery of oil, gas or other commodities).

“Confidential Information Memorandum” shall mean the Confidential Information Memorandum of the Borrower dated November 2006.

“Consolidated EBITDAX” shall mean, for any period, Consolidated Net Income for such period plus (a) without duplication and to the extent deducted in determining such Consolidated Net Income, the sum of (i) Consolidated Interest Expense for such period, (ii) consolidated income tax expense for such period, (iii) all amounts attributable to depreciation, depletion and amortization for such period, (iv) geological and geophysical expense for such period, (v) all amounts attributable to impairment of oil and gas properties for such period, (vi) any non-cash compensation charges, including any arising from employee stock options, taken during such period, (vii) any extraordinary losses for such period and (viii) any other non-cash charges (other than the write-down of current assets) for such period, and minus (b) without duplication (i) all cash payments made during such period on account of non-cash charges added to Consolidated Net Income pursuant to clauses (a)(vi) or (viii) above in a previous period and (ii) to the extent included in determining such Consolidated Net Income, any extraordinary gains and all non-cash items of income for such period, all determined on a consolidated basis in accordance with GAAP.

“Consolidated Interest Expense” shall mean, for any period, the sum of (a) the interest expense (including imputed interest expense in respect of Capital Lease Obligations and Synthetic Lease Obligations) of the Borrower and the Subsidiaries for such period, determined on a consolidated basis in accordance with GAAP, (b) any interest accrued during such period in respect of Indebtedness of the Borrower or any Subsidiary that is required to be capitalized rather than included in consolidated interest expense for such period in accordance with GAAP and (c) the aggregate amount of all dividends in respect of Preferred Equity Interests paid in cash by the Borrower and the Subsidiaries during such period. For purposes of the foregoing, interest expense shall be determined after giving effect to any net payments made or received by the Borrower or any Subsidiary with respect to Interest Rate Hedging Agreements.

“Consolidated Net Income” shall mean, for any period, the net income or loss of the Borrower and the Subsidiaries for such period determined on a consolidated basis in accordance with GAAP; provided that there shall be excluded (a) the income of any Subsidiary to the extent that the declaration or payment of dividends or similar distributions by the Subsidiary of that income is not at the time permitted by operation of the terms of its charter or any agreement, instrument, judgment, decree, statute, rule or governmental regulation applicable to such Subsidiary, (b) the income or loss of any person accrued prior to the date it becomes a Subsidiary or is merged into or consolidated with the Borrower or any Subsidiary or the date that such person’s assets are acquired by the Borrower or any Subsidiary, (c) the income of any person in which any other person (other than the Borrower or a wholly owned Subsidiary or any director holding qualifying shares in accordance with applicable law) has a joint interest, except to the extent of the amount of dividends or other distributions actually paid to the Borrower or a wholly owned Subsidiary by such person during such period and (d) any gains attributable to sales of assets out of the ordinary course of business.

6

“Control” shall mean the possession, directly or indirectly, of the power to direct or cause the direction of the management or policies of a person, whether through the ownership of voting securities, by contract or otherwise, and the terms “Controlling” and “Controlled” shall have meanings correlative thereto.

“Credit Event” shall have the meaning assigned to such term in Article IV.

“Credit Facilities” shall mean the revolving credit, letter of credit and term loan facilities provided for by this Agreement.

“Cumulative Consolidated Net Income” shall mean, as of any date of determination, Consolidated Net Income of the Borrower and the Subsidiaries, less the aggregate amount of dividends on, or accretion of, Preferred Equity Interests, for the period (taken as one accounting period) commencing on January 1, 2006 and ending on the last day of the most recent fiscal quarter or fiscal year, as applicable, for which financial statements required to be delivered pursuant to Section 5.04(a) or (b), and the related certificate required to be delivered pursuant to Section 5.04(c), have been received by the Administrative Agent.

“Current Assets” shall mean, at any time, the consolidated current assets of the Borrower and the Subsidiaries.

“Current Liabilities” shall mean, at any time, the consolidated current liabilities of the Borrower and the Subsidiaries at such time, but excluding, without duplication, (a) the current portion of any long-term Indebtedness and (b) outstanding Revolving Loans.

“Current Ratio” shall mean, at any time, the ratio of Current Assets at such time to Current Liabilities at such time. For purposes of calculating the Current Ratio, (a) each of Current Assets and Current Liabilities shall exclude (i) gains and losses resulting from the mark-to-market of commodity price risk management transactions in accordance with FASB 133 and (ii) non-cash allocations to expense and other non-cash adjustments in accordance with FASB 143 and (b) Current Assets shall include the amount of unused and available Revolving Credit Commitments.

“Default” shall mean any event or condition which upon notice, lapse of time or both would constitute an Event of Default.

“Defaulting Lender” shall mean any Revolving Credit Lender that has (a) defaulted in its obligation to make a Revolving Loan or to fund its participation in a Letter of Credit required to be made or funded by it hereunder, (b) notified the Administrative Agent or a Loan Party in writing that it does not intend to satisfy any such obligation or (c) become insolvent or the assets or management of which has been taken over by any Governmental Authority.

“Disqualified Capital Stock” shall mean any Equity Interest which, by its terms (or by the terms of any security into which it is convertible or for which it is exchangeable), or upon the happening of any event, (a) matures (excluding any maturity as the result of an optional

7

redemption by the issuer thereof) or is mandatorily redeemable, pursuant to a sinking fund obligation or otherwise, or is redeemable at the option of the holder thereof, in whole or in part, or requires the payment of any cash dividend or any other scheduled payment constituting a return of capital, in each case at any time on or prior to the first anniversary of the Term Loan Maturity Date, or (b) is convertible into or exchangeable (unless at the sole option of the issuer thereof) for (i) debt securities or (ii) any Equity Interest referred to in clause (a) above, in each case prior to the first anniversary of the Term Loan Maturity Date.

“dollars” or “$” shall mean lawful money of the United States of America.

“Domestic Oil and Gas Properties” shall mean the Oil and Gas Properties of the Borrower and the Domestic Subsidiaries.

“Domestic Subsidiaries” shall mean all Subsidiaries incorporated or organized under the laws of the United States of America, any State thereof or the District of Columbia.

“Dutch Parallel Debt” shall mean, with respect to any Loan Party and in any given currency at any given time, an amount equal to the aggregate amount of such Loan Party’s Underlying Debt Obligations at such time expressed in the currency thereof.

“Dutch Sector” shall mean the jurisdiction of The Netherlands commonly referred to as the Dutch Sector—North Sea.

“Dutch Security Agreements” shall have the meaning assigned to such term in Section 9.18.

“Environmental Laws” shall mean all former, current and future Federal, state, local and foreign laws (including common law), treaties, regulations, rules, ordinances, codes, decrees, judgments, directives, orders (including consent orders), and agreements in each case, relating to protection of the environment, natural resources, human health and safety or the presence, Release of, or exposure to, Hazardous Materials, or the generation, manufacture, processing, distribution, use, treatment, storage, transport, recycling or handling of, or the arrangement for such activities with respect to, Hazardous Materials.

“Environmental Liability” shall mean all liabilities, obligations, damages, losses, claims, actions, suits, judgments, orders, fines, penalties, fees, expenses and costs (including administrative oversight costs, natural resource damages and remediation costs), whether contingent or otherwise, arising out of or relating to (a) compliance or non-compliance with any Environmental Law, (b) the generation, use, handling, transportation, storage, treatment or disposal of any Hazardous Materials, (c) exposure to any Hazardous Materials, (d) the Release of any Hazardous Materials or (e) any contract, agreement or other consensual arrangement pursuant to which liability is assumed or imposed with respect to any of the foregoing.

“Equity Interests” shall mean shares of capital stock, partnership interests, membership interests in a limited liability company, beneficial interests in a trust or other equity interests in any person.

8

“Equity Issuance” shall mean any issuance or sale by the Borrower or any Subsidiary of any Equity Interests of the Borrower or any such Subsidiary, as applicable, except in each case for (a) any issuance or sale to the Borrower or any Subsidiary, (b) any issuance of Disqualified Capital Stock, (c) any issuance of directors’ qualifying shares, (d) sales or issuances of common stock of the Borrower to management or employees of the Borrower or any Subsidiary under any employee stock option or stock purchase plan or employee benefit plan in existence from time to time and (e) issuances of common stock of the Borrower pursuant to the exercise from time to time of any warrants issued and outstanding on the Restatement Date.

“ERISA” shall mean the Employee Retirement Income Security Act of 1974, as the same may be amended from time to time.

“ERISA Affiliate” shall mean any trade or business (whether or not incorporated) that, together with the Borrower, is treated as a single employer under Section 414(b) or (c) of the Code, or solely for purposes of Section 302 of ERISA and Section 412 of the Code, is treated as a single employer under Section 414 of the Code.

“ERISA Event” shall mean (a) any “reportable event”, as defined in Section 4043 of ERISA or the regulations issued thereunder, with respect to a Plan (other than an event for which the 30-day notice period is waived); (b) the existence with respect to any Plan of an “accumulated funding deficiency” (as defined in Section 412 of the Code or Section 302 of ERISA), whether or not waived; (c) the filing pursuant to Section 412(d) of the Code or Section 303(d) of ERISA of an application for a waiver of the minimum funding standard with respect to any Plan; (d) the incurrence by the Borrower or any of its ERISA Affiliates of any liability under Title IV of ERISA with respect to the termination of any Plan or the withdrawal or partial withdrawal of the Borrower or any of its ERISA Affiliates from any Plan or Multiemployer Plan; (e) the receipt by the Borrower or any of its ERISA Affiliates from the PBGC or a plan administrator of any notice relating to the intention to terminate any Plan or Plans or to appoint a trustee to administer any Plan; (f) the adoption of any amendment to a Plan that would require the provision of security pursuant to Section 401(a)(29) of the Code or Section 307 of ERISA; (g) the receipt by the Borrower or any of its ERISA Affiliates of any notice, or the receipt by any Multiemployer Plan from the Borrower or any of its ERISA Affiliates of any notice, concerning the imposition of Withdrawal Liability or a determination that a Multiemployer Plan is, or is expected to be, insolvent or in reorganization, within the meaning of Title IV of ERISA; (h) the occurrence of a “prohibited transaction” with respect to which the Borrower or any of the Subsidiaries is a “disqualified person” (within the meaning of Section 4975 of the Code) or with respect to which the Borrower or any such Subsidiary could otherwise be liable; (i) any Foreign Benefit Event; or (j) any other event or condition with respect to a Plan or Multiemployer Plan that could result in liability of the Borrower or any Subsidiary.

“Eurodollar”, when used in reference to any Loan or Borrowing, refers to whether such Loan, or the Loans comprising such Borrowing, are bearing interest at a rate determined by reference to the Adjusted LIBO Rate.

“Event of Default” shall have the meaning assigned to such term in Article VII.

9

“Excess Cash Flow” shall mean, for any fiscal year of the Borrower, the excess of (a) the sum, without duplication, of (i) Consolidated EBITDAX for such fiscal year and (ii) reductions to noncash working capital of the Borrower and the Subsidiaries for such fiscal year (i.e., the decrease, if any, in Current Assets (other than cash and Permitted Investments) minus Current Liabilities from the beginning to the end of such fiscal year) over (b) the sum, without duplication, of (i) the amount of any Taxes payable in cash by the Borrower and the Subsidiaries with respect to such fiscal year, (ii) Consolidated Interest Expense for such fiscal year payable in cash, (iii) Capital Expenditures made in cash during such fiscal year, except to the extent financed with the proceeds of Indebtedness, equity issuances, casualty proceeds, condemnation proceeds or other proceeds that would not be included in Consolidated EBITDAX, (iv) permanent repayments of Indebtedness (other than mandatory prepayments of Loans under Section 2.13) made by the Borrower and the Subsidiaries during such fiscal year, but only to the extent that such prepayments by their terms cannot be reborrowed or redrawn and do not occur in connection with a refinancing of all or any portion of such Indebtedness and (v) additions to noncash working capital for such fiscal year (i.e., the increase, if any, in Current Assets (other than cash and Permitted Investments) minus Current Liabilities from the beginning to the end of such fiscal year).

“Exchange Rate” shall mean, on any day, with respect to any foreign currency, the noon buying rate in New York City for such foreign currency on such date for cable transfers as certified for customs purposes by the Federal Reserve Bank of New York.

“Excluded Taxes” shall mean, with respect to the Administrative Agent, any Lender, the Issuing Bank or any other recipient of any payment to be made by or on account of any obligation of the Borrower hereunder, (a) income or franchise taxes imposed on (or measured by) its net income by the United States of America, or by the jurisdiction under the laws of which such recipient is organized or in which its principal office is located or, in the case of any Lender, in which its applicable lending office is located, (b) any branch profits taxes imposed by the United States of America or any similar tax imposed by any other jurisdiction described in clause (a) above and (c) in the case of a Foreign Lender (other than an assignee pursuant to a request by the Borrower under Section 2.21(a)), any withholding tax that is imposed on amounts payable to such Foreign Lender at the time such Foreign Lender becomes a party to this Agreement (or designates a new lending office) or is attributable to such Foreign Lender’s failure to comply with Section 2.20(e), except to the extent that such Foreign Lender (or its assignor, if any) was entitled, at the time of designation of a new lending office (or assignment), to receive additional amounts from the Borrower with respect to such withholding tax pursuant to Section 2.20(a).

“Existing Credit Agreement” shall have the meaning assigned to such term in the preliminary statement to this Agreement.

“Existing Lenders” shall have the meaning assigned to such term in the preliminary statement to this Agreement.

“Existing Preferred Stock” shall mean the Series A Preferred Stock and the Series B Preferred Stock.

10

“Existing Term Loans” shall have the meaning assigned to such term in the preliminary statement to this Agreement.

“FASB 133” means Statement No. 133 of the Financial Accounting Standards Board, “Accounting for Derivative Instruments and Hedging Activities”, as amended or supplemented from time to time.

“FASB 143” means Statement No. 143 of the Financial Accounting Standards Board, “Accounting for Asset Retirement Obligations”, as amended or supplemented from time to time.

“Federal Funds Effective Rate” shall mean, for any day, the weighted average of the rates on overnight Federal funds transactions with members of the Federal Reserve System arranged by Federal funds brokers, as published on the next succeeding Business Day by the Federal Reserve Bank of New York, or, if such rate is not so published for any day that is a Business Day, the average (rounded upwards, if necessary, to the next 1/100 of 1%) of the quotations for the day for such transactions received by the Administrative Agent from three Federal funds brokers of recognized standing selected by it.

“Fee Letter” shall mean the Fee Letter dated March 23, 2004, between the Borrower and the Administrative Agent (it being acknowledged and agreed between the Borrower and the Administrative Agent that the “Facilities” referred to therein shall be deemed to refer to the Credit Facilities).

“Fees” shall mean the Commitment Fees, the Administrative Agent Fees, the L/C Participation Fees and the Issuing Bank Fees.

“Financial Officer” of any person shall mean the chief financial officer, principal accounting officer, treasurer or controller of such person.

“Foreign Benefit Event” shall mean, with respect to any Foreign Pension Plan, (a) the existence of unfunded liabilities in excess of the amount permitted under any applicable law, or in excess of the amount that would be permitted absent a waiver from a Governmental Authority, (b) the failure to make the required contributions or payments under any applicable law on or before the due date for such contributions or payments, (c) the receipt of a notice by a Governmental Authority relating to the intention to terminate any such Foreign Pension Plan or to appoint a trustee or similar official to administer any such Foreign Pension Plan, or alleging the insolvency of any such Foreign Pension Plan, (d) the incurrence of any liability in excess of $2,500,000 by the Borrower or any of the Subsidiaries under applicable law on account of the complete or partial termination of such Foreign Pension Plan or the complete or partial withdrawal of any participating employer therein or (e) the occurrence of any transaction that is prohibited under any applicable law and could reasonably be expected to result in the incurrence of any liability by the Borrower or any of the Subsidiaries, or the imposition on the Borrower or any of the Subsidiaries of any fine, excise tax or penalty resulting from any noncompliance with any applicable law, in each case in excess of $2,500,000.

“Foreign Lender” shall mean any Lender that is organized under the laws of a jurisdiction other than that in which the Borrower is located. For purposes of this definition, the United States of America, each State thereof and the District of Columbia shall be deemed to constitute a single jurisdiction.

11

“Foreign Pension Plan” shall mean any benefit plan that under applicable law is required to be funded through a trust or other funding vehicle other than a trust or funding vehicle maintained exclusively by a Governmental Authority.

“Foreign Pledge Agreements” shall mean the collective reference to (a) the Charge of Shares in ATP Oil & Gas (UK) Limited, substantially in the form of Exhibit D, between the Borrower and the Collateral Agent and (b) the Pledge of Shares in the capital of ATP Oil & Gas (Netherlands) B.V., substantially in the form of Exhibit E, among the Borrower, ATP Oil & Gas (Netherlands) B.V. and the Collateral Agent, each for the ratable benefit of the Secured Parties.

“Foreign Pledged Collateral” shall mean the Equity Interests pledged by the Borrower or any Subsidiary under the Foreign Pledge Agreements, for the ratable benefit of the Secured Parties, to secure the Obligations.

“Foreign Subsidiary” shall mean any Subsidiary that is not a Domestic Subsidiary.

“GAAP” shall mean United States generally accepted accounting principles applied on a consistent basis.

“Governmental Authority” shall mean any Federal, state, local or foreign court or governmental agency, authority, instrumentality or regulatory body.

“Granting Lender” shall have the meaning assigned to such term in Section 9.04(i).

“Guarantee” of or by any person shall mean any obligation, contingent or otherwise, of such person guaranteeing or having the economic effect of guaranteeing any Indebtedness or other obligation of any other person (the “primary obligor”) in any manner, whether directly or indirectly, and including any obligation of such person, direct or indirect, (a) to purchase or pay (or advance or supply funds for the purchase or payment of) such Indebtedness or other obligation or to purchase (or to advance or supply funds for the purchase of) any security for the payment of such Indebtedness or other obligation, (b) to purchase or lease property, securities or services for the purpose of assuring the owner of such Indebtedness or other obligation of the payment of such Indebtedness or other obligation or (c) to maintain working capital, equity capital or any other financial statement condition or liquidity of the primary obligor so as to enable the primary obligor to pay such Indebtedness or other obligation; provided, however, that the term “Guarantee” shall not include endorsements for collection or deposit in the ordinary course of business.

“Guarantee and Collateral Agreement” shall mean the Amended and Restated Guarantee and Collateral Agreement dated as of April 14, 2005, as amended, restated, supplemented or otherwise modified from time to time, among the Borrower, the Subsidiaries party thereto and the Collateral Agent for the ratable benefit of the Secured Parties.

“Hazardous Materials” shall mean (a) any petroleum products or byproducts and all other hydrocarbons, coal ash, radon gas, asbestos, urea formaldehyde foam insulation,

12

polychlorinated biphenyls, chlorofluorocarbons and all other ozone-depleting substances and (b) any chemical, material, substance or waste that is prohibited, limited or regulated by or pursuant to any Environmental Law.

“Hedging Agreement” shall mean any Commodity Hedging Agreement, Interest Rate Hedging Agreement or foreign currency exchange agreement or other currency exchange rate hedging arrangement.

“Hydrocarbons” shall mean oil, gas, casinghead gas, condensate, distillate, liquid hydrocarbons, gaseous hydrocarbons, all products directly or indirectly refined, separated, settled and dehydrated therefrom, including kerosene, liquefied petroleum gas, refined lubricating oils, diesel fuel, drip gasoline, natural gasoline, helium, sulfur and all other minerals.

“Hydrocarbon Interests” shall mean all rights, titles, interests and estates now owned or hereafter acquired in and to oil and gas leases, leasehold interests and licenses, oil, gas and mineral leases, leasehold interests and licenses, or other liquid or gaseous hydrocarbon licenses, leases, fee mineral interests, term mineral interests, subleases, farm-outs, royalties, overriding royalty and royalty interests, non-consent interests arising out of or pursuant to Oil and Gas Contracts, net profit interests, net revenue interests, oil payments, production payments, production payment interests and similar interests and estates, including all reserved or residual interest of whatever nature and all reversionary or carried interests relating to any of the foregoing.

“Indebtedness” of any person shall mean, without duplication, (a) all obligations of such person for borrowed money or with respect to deposits or advances of any kind, (b) all obligations of such person evidenced by bonds, debentures, notes or similar instruments, (c) all obligations of such person upon which interest charges are customarily paid, (d) all obligations of such person under conditional sale or other title retention agreements relating to property or assets purchased by such person, (e) all obligations of such person issued or assumed as the deferred purchase price of property or services (excluding trade accounts payable and accrued obligations incurred in the ordinary course of business), (f) all Indebtedness of others secured by (or for which the holder of such Indebtedness has an existing right, contingent or otherwise, to be secured by) any Lien on property owned or acquired by such person, whether or not the obligations secured thereby have been assumed, (g) all Guarantees by such person of Indebtedness of others, (h) all Capital Lease Obligations and Synthetic Lease Obligations of such person, (i) all obligations of such person as an account party in respect of letters of credit, (j) all obligations of such person in respect of bankers’ acceptances and (k) the liquidation preference of, and all other obligations of such person in respect of, Disqualified Capital Stock of such person. The Indebtedness of any person shall include the Indebtedness of any partnership in which such person is a general partner.

“Indemnified Taxes” shall mean Taxes other than Excluded Taxes.

“Indemnitee” shall have the meaning assigned to such term in Section 9.05.

“Independent Engineering Firm” shall mean Ryder Scott Company L.P., RPS Energy, DeGolyer and MacNaughton, Collarini Associates and/or one or more other independent engineering firms selected by the Borrower and reasonably acceptable to the Administrative Agent.

13

“Information” shall have the meaning assigned to such term in Section 9.16.

“Interest Coverage Ratio” shall mean, for any period, the ratio of (a) Consolidated EBITDAX for such period to (b) Consolidated Interest Expense for such period; provided that for purposes of determining the Interest Coverage Ratio for the period of four consecutive quarters ended December 31, 2006 and March 31, 2007, Consolidated EBITDAX shall be deemed to be equal to (y) Consolidated EBITDAX for the two consecutive fiscal quarters ended December 31, 2006, multiplied by 2 and (z) Consolidated EBITDAX for the three consecutive fiscal quarters ended March 31, 2007, multiplied by 4/3, respectively.

“Interest Payment Date” shall mean (a) with respect to any ABR Loan, the last Business Day of each March, June, September and December, and (b) with respect to any Eurodollar Loan, the last day of the Interest Period applicable to the Borrowing of which such Loan is a part and, in the case of a Eurodollar Borrowing with an Interest Period of more than three months’ duration, each day that would have been an Interest Payment Date had successive Interest Periods of three months’ duration been applicable to such Borrowing.

“Interest Period” shall mean, with respect to any Eurodollar Borrowing, the period commencing on the date of such Borrowing and ending on the numerically corresponding day (or, if there is no numerically corresponding day, on the last day) in the calendar month that is 1, 2, 3 or 6 months thereafter, as the Borrower may elect; provided, however, that if any Interest Period would end on a day other than a Business Day, such Interest Period shall be extended to the next succeeding Business Day unless such next succeeding Business Day would fall in the next calendar month, in which case such Interest Period shall end on the next preceding Business Day. Interest shall accrue from and including the first day of an Interest Period to but excluding the last day of such Interest Period. For purposes hereof, the date of a Borrowing initially shall be the date on which such Borrowing is made and thereafter shall be the effective date of the most recent conversion or continuation of such Borrowing.

“Interest Rate Hedging Agreement” shall mean any interest rate swap, cap or collar agreement or other interest rate protection agreement or interest rate hedging arrangement.

“Investment Grade” shall mean a rating of BBB- or higher by S&P or Baa3 or higher by Moody’s.

“Issuing Bank” shall mean, as the context may require, (a) Bayerische Hypo-Und Vereinsbank AG, acting through any of its Affiliates or branches, in its capacity as the issuer of Letters of Credit hereunder, and (b) any other Lender that may become an Issuing Bank pursuant to Section 2.23(i) or 2.23(k), with respect to Letters of Credit issued by such Lender. The Issuing Bank may, in its discretion, arrange for one or more Letters of Credit to be issued by Affiliates or branches of the Issuing Bank, in which case the term “Issuing Bank” shall include any such Affiliate or branch with respect to Letters of Credit issued by such Affiliate or branch.

“Issuing Bank Fees” shall have the meaning assigned to such term in Section 2.05(c).

14

“Junior Financing Documentation” shall mean (a) the Second Lien Facility Documents, and (b) any indenture or other documentation governing any Permitted Subordinated Indebtedness.

“L/C Commitment” shall mean the commitment of the Issuing Bank to issue Letters of Credit pursuant to Section 2.23.

“L/C Disbursement” shall mean a payment or disbursement made by the Issuing Bank pursuant to a Letter of Credit.

“L/C Exposure” shall mean at any time the sum of (a) the aggregate undrawn amount of all outstanding Letters of Credit at such time and (b) the aggregate amount of all L/C Disbursements that have not yet been reimbursed by or on behalf of the Borrower at such time. The L/C Exposure of any Revolving Credit Lender at any time shall equal its Pro Rata Percentage of the aggregate L/C Exposure at such time.

“L/C Participation Fee” shall have the meaning assigned to such term in Section 2.05(c).

“Lenders” shall mean (a) the Existing Lenders and the Revolving Credit Lenders (other than any such person that has ceased to be a party hereto pursuant to an Assignment and Acceptance) and (b) any person that has become a party hereto pursuant to an Assignment and Acceptance.

“Letter of Credit” shall mean any letter of credit issued pursuant to Section 2.23.

“Leverage Ratio” shall mean, on any date, the ratio of Total Net Debt on such date to Consolidated EBITDAX for the period of four consecutive fiscal quarters most recently ended on or prior to such date; provided that for purposes of determining the Leverage Ratio at December 31, 2006 and March 31, 2007, Consolidated EBITDAX for the period of four consecutive fiscal quarters most recently ended on or prior to such dates, shall be deemed to be equal to (y) Consolidated EBITDAX for the two consecutive fiscal quarters ended December 31, 2006, multiplied by 2 and (z) Consolidated EBITDAX for the three consecutive fiscal quarters ended March 31, 2007, multiplied by 4/3, respectively.

“LIBO Rate” shall mean, with respect to any Eurodollar Borrowing for any Interest Period, the rate per annum determined by the Administrative Agent at approximately 11:00 a.m., London time, on the date that is two Business Days prior to the commencement of such Interest Period by reference to the British Bankers’ Association Interest Settlement Rates for deposits in dollars (as set forth by any service selected by the Administrative Agent that has been nominated by the British Bankers’ Association as an authorized information vendor for the purpose of displaying such rates) for a period equal to such Interest Period; provided that, to the extent that an interest rate is not ascertainable pursuant to the foregoing provisions of this definition, the “LIBO Rate” shall be the interest rate per annum determined by the Administrative Agent to be the average of the rates per annum at which deposits in dollars are offered for such relevant Interest Period to major banks in the London interbank market in London, England by the Administrative Agent at approximately 11:00 a.m., London time, on the date that is two Business Days prior to the beginning of such Interest Period.

15

“Lien” shall mean, with respect to any asset, (a) any mortgage, deed of trust, lien, pledge, encumbrance, charge or security interest in or on such asset, (b) the interest of a vendor or a lessor under any conditional sale agreement, capital lease or title retention agreement (or any financing lease having substantially the same economic effect as any of the foregoing) relating to such asset and (c) in the case of securities, any purchase option, call or similar right of a third party with respect to such securities.

“Loan Documents” shall mean the Amendment Agreement, this Agreement, the Letters of Credit, the Security Documents and the promissory notes, if any, executed and delivered pursuant to Section 2.04(e).

“Loan Parties” shall mean the Borrower and the Subsidiary Guarantors.

“Loans” shall mean the Revolving Loans and the Term Loans.

“Management Investors” shall mean the directors, executive officers and other management employees of the Borrower on the Prior Restatement Date.

“Margin Stock” shall have the meaning assigned to such term in Regulation U.

“Material Adverse Effect” shall mean (a) a materially adverse effect on the business, assets, operations, condition (financial or otherwise) or prospects of the Borrower and the Subsidiaries, taken as a whole, (b) a material impairment of the ability of the Borrower or any other Loan Party to perform any of its obligations under any Loan Document to which it is or will be a party or (c) a material impairment of the rights of or benefits available to the Lenders under any Loan Document.

“Material Indebtedness” shall mean Indebtedness (other than the Loans and Letters of Credit), or obligations in respect of one or more Hedging Agreements, of any one or more of the Borrower and the Subsidiaries in an aggregate principal amount exceeding $10,000,000. For purposes of determining Material Indebtedness, the “principal amount” of the obligations of the Borrower or any Subsidiary in respect of any Hedging Agreement at any time shall be the maximum aggregate amount (giving effect to any netting agreements) that the Borrower or such Subsidiary would be required to pay if such Hedging Agreement were terminated at such time.

“Maximum Rate” shall have the meaning assigned to such term in Section 9.09.

“Moody’s” shall mean Moody’s Investors Service, Inc., or any successor thereto.

“Mortgaged Properties” shall mean, initially, the Domestic Oil and Gas Properties and other owned real properties and leasehold and subleasehold interests of the Loan Parties specified on Schedule 1.01(b), and shall include each Domestic Oil and Gas Property and each other parcel of real property and improvements thereto with respect to which a Mortgage is granted pursuant to Section 5.09.

“Mortgages” shall mean the mortgages, deeds of trust, leasehold mortgages, assignments of leases and rents, assignments of production, modifications and other security documents delivered pursuant to the Existing Credit Agreement or pursuant to Section 5.09, each substantially in the form of Exhibit G.

16

“Multiemployer Plan” shall mean a multiemployer plan as defined in Section 4001(a)(3) of ERISA.

“Net Cash Proceeds” shall mean (a) with respect to any Asset Sale, the cash proceeds (including cash proceeds subsequently received (as and when received) in respect of noncash consideration initially received), net of (i) selling expenses (including reasonable broker’s fees or commissions, legal fees, transfer and similar taxes and the Borrower’s good faith estimate of income taxes paid or payable in connection with such sale), (ii) amounts provided as a reserve, in accordance with GAAP, against any liabilities under any indemnification obligations or purchase price adjustment associated with such Asset Sale (provided that, to the extent and at the time any such amounts are released from such reserve, such amounts shall constitute Net Cash Proceeds) and (iii) the principal amount, premium or penalty, if any, interest and other amounts on any Indebtedness for borrowed money which is secured by the asset sold in such Asset Sale and which is required to be repaid with such proceeds (other than any such Indebtedness assumed by the purchaser of such asset); provided, however, that, if no Default or Event of Default shall have occurred and shall be continuing at the time of the receipt of such proceeds or at the proposed time of the application thereof, such proceeds shall not constitute Net Cash Proceeds to the extent reinvested or contractually committed to be reinvested in productive assets of a kind then used or usable in the business of the Borrower and the Subsidiaries within 180 days of such receipt; and (b) with respect to any issuance or incurrence of Indebtedness or any Equity Issuance, the cash proceeds thereof, net of all taxes and customary fees, commissions, costs and other expenses incurred in connection therewith.

“North Sea” shall mean, collectively, the Dutch Sector and the UK Sector, and surrounding areas of the North Sea.

“Obligations” shall mean all obligations defined as “Obligations” in the Guarantee and Collateral Agreement and the other Security Documents.

“Oil and Gas Business” shall mean (a) the acquisition, exploration, exploitation, development, operation and disposition of interests in Oil and Gas Properties and Hydrocarbons; (b) the gathering, treating, processing, storage and selling of any production from such interests or properties; and (c) any business directly relating to or arising directly from exploration for, or development, production, treatment, processing, storage or selling of, Hydrocarbons, or that is or necessary or desirable to facilitate the activities described in this definition.

“Oil and Gas Contracts” shall mean all contracts, agreements, operating agreements, farm-out or farm-in agreements, sharing agreements, mineral purchase agreements, contracts for the purchase, exchange, transportation, processing or sale of Hydrocarbons, rights-of-way, easements, surface leases, equipment leases, permits, franchises, licenses, pooling or unitization agreements, and unit or pooling designations and orders now or hereafter affecting any of the Oil and Gas Properties (or related oil and gas gathering assets) or Hydrocarbon Interests of the Borrower and the Subsidiaries, or which are useful or appropriate in drilling for, producing, treating, handling, storing, transporting or marketing oil, gas or other minerals produced from

17

any of the Oil and Gas Properties of the Borrower and the Subsidiaries, as any such contracts and agreements as they may be amended, restated, modified, substituted or supplemented from time to time.

“Oil and Gas Properties” shall mean (a) Hydrocarbon Interests; (b) the properties now or hereafter pooled or unitized with Hydrocarbon Interests; (c) all currently existing or future rights arising under (i) unitization agreements, orders or other arrangements, (ii) pooling orders, agreements or other arrangements and (iii) declarations of pooled units and the units created thereby (including all units created under orders, regulations and rules of any Governmental Authority having jurisdiction) which may affect all or any portion of the Hydrocarbon Interests; (d) all pipelines, gathering lines, compression facilities, tanks and processing plants; (e) all interests held in royalty trusts whether currently existing or hereafter created; (f) all Hydrocarbons in and under and which may be produced, saved, processed or attributable to the Hydrocarbon Interests, the lands covered thereby and all Hydrocarbons in pipelines, gathering lines, tanks and processing plants and all rents, issues, profits, proceeds, products, revenues and other incomes from or attributable to the Hydrocarbon Interests; (g) all tenements, hereditaments, appurtenances, interests and properties in any way appertaining, belonging, affixed or incidental to the Hydrocarbon Interests, and all rights, titles, interests and estates described or referred to above (including (i) any and all real property, now owned or hereafter acquired, used or held for use in connection with the operating, working or development of any of such Hydrocarbon Interests or property and (ii) any and all surface leases, rights-of-way, easements and servitudes together with all additions, substitutions, replacements, accessions and attachments to any and all of the foregoing); and (h) all production units, and drilling and spacing units (and the properties covered thereby) which may affect all or any portion of the other Oil and Gas Properties and any units created by agreement or designation or under orders, regulations, rules or other official acts of any Governmental Authority having jurisdiction.

“Original Closing Date” shall mean March 29, 2004.

“Other Taxes” shall mean any and all present or future stamp or documentary taxes or any other excise or property taxes, charges or similar levies arising from any payment made under any Loan Document or from the execution, delivery or enforcement of, or otherwise with respect to, any Loan Document.

“PBGC” shall mean the Pension Benefit Guaranty Corporation referred to and defined in ERISA.

“PDP” shall mean Proved Developed Reserves that are categorized as producing in accordance with the petroleum reserves definitions promulgated by the Society of Petroleum Engineers (SPE) Inc. from time to time.

“PDP Coverage Ratio” shall mean, on any date of determination, the ratio of PV-10 Value (determined by substituting the phrase “from PDP production on the Borrower’s and the Subsidiaries’ Oil and Gas Properties” for the phrase “from Proved Reserves on the Borrower’s and the Subsidiaries’ Oil and Gas Properties” appearing in the second line of the definition thereof) on such date to Total Net Debt on such date; provided that Total Net Debt for this purpose shall exclude any Permitted Subordinated Indebtedness incurred pursuant to Section 6.01(h).

18

“Perfection Certificate” shall mean the Perfection Certificate substantially in the form of Exhibit B to the Guarantee and Collateral Agreement.

“Permitted Business Investments” shall mean investments made in the ordinary course of, and of a nature that is or shall have become customary in, the Oil and Gas Business as a means of actively exploiting, exploring for, acquiring, developing, processing, gathering, marketing, storing, treating, selling or transporting oil and gas through agreements, transactions, interests or arrangements (including those that permit a person to share risks or costs, comply with regulatory requirements regarding local ownership or satisfy other objectives customarily achieved through the conduct of Oil and Gas Business jointly with third parties), including the entry into or acquisition of operating agreements, working interests, royalty interests, mineral leases, processing agreements, farm-out and farm-in agreements, division orders, contracts for the sale, transportation or exchange of oil or natural gas, unitization and pooling declarations and agreements and area of mutual interest agreements, production sharing agreements or other similar or customary agreements, transactions, properties, interests, and investments and expenditures in connection therewith (with the amount thereof measured at the time initially made); provided that an investment in Equity Interests in a person shall not constitute a Permitted Business Investment.

“Permitted Investments” shall mean:

(a) direct obligations of, or obligations the principal of and interest on which are unconditionally guaranteed by, the United States of America (or by any agency thereof to the extent such obligations are backed by the full faith and credit of the United States of America), in each case maturing within one year from the date of acquisition thereof;

(b) investments in commercial paper maturing within 270 days from the date of acquisition thereof and having, at such date of acquisition, the highest credit rating obtainable from S&P or from Moody’s;

(c) investments in certificates of deposit, banker’s acceptances and time deposits maturing within one year from the date of acquisition thereof issued or guaranteed by or placed with, and money market deposit accounts issued or offered by, the Administrative Agent or any domestic office of any commercial bank organized under the laws of the United States of America or any State thereof that has a combined capital and surplus and undivided profits of not less than $500,000,000;

(d) fully collateralized repurchase agreements with a term of not more than 30 days for securities described in clause (a) above and entered into with a financial institution satisfying the criteria of clause (c) above;

(e) investments in “money market funds” within the meaning of Rule 2a-7 of the Investment Company Act of 1940, as amended, substantially all of whose assets are invested in investments of the type described in clauses (a) through (d) above;

19

(f) investments in so-called “auction rate” securities rated AA or higher by S&P or Aa or higher by Moody’s and which have a reset date not more than 90 days from the date of acquisition thereof; and

(g) other short-term investments utilized by Foreign Subsidiaries in accordance with normal investment practices for cash management in investments of a type analogous to the foregoing.

“Permitted Refinancing Indebtedness” shall mean any Indebtedness issued in exchange for, or the Net Cash Proceeds of which are used to extend, refinance, renew, replace, defease or refund (collectively, to “Refinance”), the Indebtedness being Refinanced (or previous refinancings thereof constituting Permitted Refinancing Indebtedness); provided that (a) the principal amount (or accreted value, if applicable) of such Permitted Refinancing Indebtedness does not exceed the principal amount (or accreted value, if applicable) of the Indebtedness so Refinanced (plus unpaid accrued interest and premium thereon and underwriting discounts or commissions and other fees and expenses in connection therewith), (b) the maturity date of such Permitted Refinancing Indebtedness is no earlier than the first anniversary of the Term Loan Maturity Date, (c) the average life to maturity of such Permitted Refinancing Indebtedness is greater than or equal to that of the Indebtedness being Refinanced, (d) if the Indebtedness being Refinanced is subordinated in right of payment to the Obligations, such Permitted Refinancing Indebtedness shall be subordinated in right of payment to the Obligations on terms at least as favorable to the Lenders as those contained in the documentation governing the Indebtedness being Refinanced, (e) no Permitted Refinancing Indebtedness shall have obligors that are not Loan Parties hereunder, or greater guarantees or security, than the Indebtedness being Refinanced, (f) in the case of any Permitted Refinancing Indebtedness in respect of the Indebtedness under any Second Lien Facility, such Permitted Refinancing Indebtedness is secured only by all or any portion of the Collateral (but not by any other assets) pursuant to one or more security agreements subject to the Second Lien Intercreditor Agreement (or another intercreditor agreement that is no less favorable to the Secured Parties than the Second Lien Intercreditor Agreement) and (g) has no scheduled amortization, payments of principal, sinking fund payments or similar scheduled payments (other than regularly scheduled payments of interest), and shall have provisions relating to mandatory prepayment, repurchase, redemption and offers to purchase that are consistent with the Indebtedness so Refinanced.

“Permitted Subordinated Indebtedness” means any unsecured Indebtedness that (a) is expressly subordinated to the prior payment in full in cash of the Obligations on terms and conditions no less favorable to the Lenders than those customarily found in senior subordinated notes issued under Rule 144A of the Securities Act or in a public offering, as reasonably determined by the Administrative Agent, (b) will not mature prior to the first anniversary of the Term Loan Maturity Date, (c) has no scheduled amortization, payments of principal, sinking fund payments or similar scheduled payments (other than regularly scheduled payments of interest), (d) has covenant, default and remedy provisions no more restrictive or expansive in scope than those customarily found in senior subordinated notes issued under Rule 144A of the Securities Act or in a public offering, as reasonably determined by the Administrative Agent and (e) has provisions relating to mandatory prepayment, repurchase, redemption and offers to purchase that are consistent with those customarily found in senior subordinated notes issued under Rule 144A of the Securities Act or in a public offering, as reasonably determined by the Administrative Agent.

20

“person” shall mean any natural person, corporation, business trust, joint venture, association, company, limited liability company, partnership, Governmental Authority or other entity.

“Plan” shall mean any employee pension benefit plan (other than a Multiemployer Plan) subject to the provisions of Title IV of ERISA or Section 412 of the Code or Section 307 of ERISA, and in respect of which the Borrower or any ERISA Affiliate is (or, if such plan were terminated, would under Section 4069 of ERISA be deemed to be) an “employer” as defined in Section 3(5) of ERISA.

“Preferred Equity Interests” shall mean any class or series of Equity Interest the terms of which provide that dividends in respect thereof are payable at a specified rate or that has preference in the payment of dividends or in the liquidation of assets over any other class or series of Equity Interests of the issuer thereof.

“Prime Rate” shall mean the rate of interest per annum determined from time to time by Credit Suisse as its prime rate in effect at its principal office in New York City and notified to the Borrower.

“Prior Restatement Date” shall mean June 22, 2006.

“Probable Reserve Value” shall mean, as of any date of determination, 50% of the present value of future cash flows from probable reserves on the Borrower’s and the Subsidiaries’ Oil and Gas Properties as set forth in the most recent Reserve Report delivered pursuant to Section 5.04(d), utilizing (i) in the case of any Oil and Gas Properties located in the United States or any of its territories or possessions (including U.S. Federal waters in the Gulf of Mexico), the average of the Three-Year Strip Price for crude oil (WTI Cushing) and natural gas (Henry Hub), quoted on the New York Mercantile Exchange (or its successor), (ii) in the case of any Oil and Gas Properties located in the North Sea, the average of the Three-Year Strip Price for crude oil (North Sea Brent) and natural gas (UK National Balancing Point), in each case quoted on the International Petroleum Exchange (or its successor) and (iii) in the case of any Oil and Gas Properties located in any other jurisdiction, the average of the Three-Year Strip Price for crude oil and natural gas, in each case quoted on any commodities exchange or other price quotation source generally recognized in the oil and gas industry in such jurisdiction and reasonably acceptable to the Administrative Agent, in the case of each of clauses (i), (ii) and (iii), as of the date as of which the information set forth in such Reserve Report is provided (as adjusted for basis differentials) and utilizing a 10% discount rate. For purposes of calculating the Probable Reserve Value, any future cash flow calculations set forth in any Reserve Report and made in any currency other than dollars shall be converted into dollars based on the Exchange Rate on the date as of which the information set forth in such Reserve Report is provided.

“Pro Forma Basis” shall mean, with respect to compliance with any test or covenant hereunder, compliance with such covenant or test after giving effect to (a) any Permitted Business Investment in discrete Oil and Gas Properties or (b) any Asset Sale of a Subsidiary,

21

operating entity or discrete Oil and Gas Properties, in the case of each of clauses (a) and (b) for which historical financial statements for the relevant period are available (including pro forma adjustments arising out of events which are directly attributable to the Permitted Business Investment or Asset Sale, are factually supportable and are expected to have a continuing impact, in each case as determined on a basis consistent with Article 11 of Regulation S-X of the Securities Act of 1933, as amended, as interpreted by the Staff of the Securities and Exchange Commission, and as certified by a Financial Officer of the Borrower) using, for purposes of determining such compliance, the historical financial statements of all entities or assets so acquired or sold and the consolidated financial statements of the Borrower and its Subsidiaries which shall be reformulated as if such Permitted Business Investment or Asset Sale, and all such other Permitted Business Investments or Asset Sales that have been consummated during the period, and any Indebtedness or other liabilities incurred in connection with any such Permitted Business Investments had been consummated and incurred at the beginning of such period.

“Pro Forma Financial Covenant Compliance” shall mean, with respect to the incurrence of any Indebtedness pursuant to Section 6.01(h) or 6.01(i), that the Borrower shall be in pro forma compliance with each of the covenants set forth in Sections 6.12, 6.13, 6.14 and 6.15 (calculated as if such Indebtedness had been incurred at the beginning of the relevant four consecutive fiscal quarter period and, if such Indebtedness has a floating rate, calculated based on an implied rate of interest for the applicable period for purposes of this definition determined by utilizing the rate that is or would be in effect with respect to such Indebtedness as at the relevant date of determination).

“Pro Rata Percentage” of any Revolving Credit Lender at any time shall mean the percentage of the Total Revolving Credit Commitment represented by such Lender’s Revolving Credit Commitment. In the event the Revolving Credit Commitments shall have expired or been terminated, the Pro Rata Percentages shall be determined on the basis of the Revolving Credit Commitments most recently in effect, giving effect to any subsequent assignments.

“Proved Developed Reserves” shall mean oil and gas reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.

“Proved Reserves” shall mean the estimated quantities of crude oil, condensate, natural gas and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions (i.e., prices and costs as of the date the estimate is made).

“PV-10 Value” shall mean, as of any date of determination, the present value of future cash flows from Proved Reserves on the Borrower’s and the Subsidiaries’ Oil and Gas Properties as set forth in the most recent Reserve Report delivered pursuant to Section 5.04(d), utilizing (i) in the case of any Oil and Gas Properties located in the United States or any of its territories or possessions (including U.S. Federal waters in the Gulf of Mexico), the average of the Three-Year Strip Price for crude oil (WTI Cushing) and natural gas (Henry Hub), quoted on the New York Mercantile Exchange (or its successor), (ii) in the case of any Oil and Gas Properties located in the North Sea, the average of the Three-Year Strip Price for crude oil (North Sea Brent) and natural gas (UK National Balancing Point), in each case quoted on the International Petroleum Exchange (or its successor) and (iii) in the case of any Oil and Gas Properties located

22

in any other jurisdiction, the average of the Three-Year Strip Price for crude oil and natural gas, in each case quoted on any commodities exchange or other price quotation source generally recognized in the oil and gas industry in such jurisdiction and reasonably acceptable to the Administrative Agent, in the case of each of clauses (i), (ii) and (iii), as of the date as of which the information set forth in such Reserve Report is provided (as adjusted for basis differentials) and utilizing a 10% discount rate. PV-10 Value shall be adjusted to give effect to the Commodity Hedging Agreements of the Borrower and the Subsidiaries then in effect. For purposes of calculating PV-10 Value, any future cash flow calculations set forth in any Reserve Report and made in any currency other than dollars shall be converted into dollars based on the Exchange Rate on the date as of which the information set forth in such Reserve Report is provided.

“Register” shall have the meaning assigned to such term in Section 9.04(d).

“Regulation T” shall mean Regulation T of the Board as from time to time in effect and all official rulings and interpretations thereunder or thereof.

“Regulation U” shall mean Regulation U of the Board as from time to time in effect and all official rulings and interpretations thereunder or thereof.

“Regulation X” shall mean Regulation X of the Board as from time to time in effect and all official rulings and interpretations thereunder or thereof.

“Related Parties” shall mean, with respect to any specified person, such person’s Affiliates and the respective directors, officers, employees, agents and advisors of such person and such person’s Affiliates.

“Release” shall mean any release, spill, emission, leaking, dumping, injection, pouring, deposit, disposal, discharge, dispersal, leaching or migration into or through the environment or within or upon any building, structure, facility or fixture.

“Repayment Date” shall have the meaning assigned to such term in Section 2.11.

“Required Lenders” shall mean, at any time, Lenders having Loans, L/C Exposure, unused Revolving Credit Commitments and Term Loan Commitments representing more than 50% of the sum of all Loans outstanding, L/C Exposure, unused Revolving Credit Commitments and Term Loan Commitments at such time; provided that the Revolving Loans, L/C Exposure, and unused Revolving Credit Commitments of any Defaulting Lender shall be disregarded in the determination of the Required Lenders at any time.

“Reserve Coverage Ratio” shall mean, on any date of determination, the ratio of (a) the sum of (i) PV-10 Value on such date and (ii) Probable Reserve Value on such date to (b) Total Net Debt on such date; provided that Total Net Debt for this purpose shall exclude any Permitted Subordinated Indebtedness incurred pursuant to Section 6.01(h).

“Reserve Report” shall mean (a) each annual reserve report prepared by an Independent Engineering Firm, in form and detail reasonably acceptable to the Administrative Agent and (b) each semi-annual reserve report prepared by an Independent Engineering Firm (prepared on a “mechanical roll-forward” basis based on the most recent annual reserve report prepared by such

23

firm), in each case with respect to the Oil and Gas Properties of the Borrower and the Subsidiaries as of (x) December 31 of the year immediately preceding the year in which such report is delivered pursuant to Section 5.04(d), in the case of an annual reserve report or (y) June 30 of the year in which such report is delivered pursuant to Section 5.04(d), in the case of a semi-annual reserve report. Each Reserve Report prepared by the Borrower shall be certified by the chief engineering officer of the Borrower as being accurate in all material respects.

“Responsible Officer” of any person shall mean any executive officer or Financial Officer of such person and any other officer or similar official thereof responsible for the administration of the obligations of such person in respect of this Agreement.

“Restatement Date” shall mean the date on which the Amendment Agreement shall become effective in accordance with its terms.

“Restricted Indebtedness” shall mean Indebtedness of the Borrower or any Subsidiary, the payment, prepayment, repurchase or defeasance of which is restricted under Section 6.09(b).

“Restricted Payment” shall mean any dividend or other distribution (whether in cash, securities or other property) with respect to any Equity Interests in the Borrower or any Subsidiary, or any payment (whether in cash, securities or other property), including any sinking fund or similar deposit, on account of the purchase, redemption, retirement, acquisition, cancellation or termination of any Equity Interests in the Borrower or any Subsidiary or any option, warrant or other right to acquire any such Equity Interests in the Borrower or any Subsidiary.

“Revolving Credit Borrowing” shall mean a Borrowing comprised of Revolving Loans.

“Revolving Credit Commitment” shall mean, with respect to each Lender, the commitment of such Lender to make Revolving Loans hereunder (and to acquire participations in Letters of Credit as provided for herein) as set forth on Schedule I to the Amendment Agreement, or in the Assignment and Acceptance pursuant to which such Lender assumed its Revolving Credit Commitment, as applicable, as the same may be (a) reduced from time to time pursuant to Section 2.09 and (b) reduced or increased from time to time pursuant to assignments by or to such Lender pursuant to Section 9.04.

“Revolving Credit Exposure” shall mean, with respect to any Lender at any time, the aggregate principal amount at such time of all outstanding Revolving Loans of such Lender, plus the aggregate amount at such time of such Lender’s L/C Exposure.

“Revolving Credit Lender” shall mean a Lender with a Revolving Credit Commitment or an outstanding Revolving Loan.

“Revolving Credit Maturity Date” shall mean October 14, 2009.

“Revolving Loans” shall mean the revolving loans made by the Lenders to the Borrower pursuant to Section 2.01.

24

“S&P” shall mean Standard & Poor’s Ratings Service, or any successor thereto.

“Second Lien Credit Agreement” shall mean the Second Lien Credit Agreement dated as of November 22, 2006, among the Borrower, the lenders from time to time party thereto, and Credit Suisse, as administrative agent and as collateral agent for the Lenders.

“Second Lien Facility” shall mean a senior secured credit facility providing for the making of term loans to the Borrower, which credit facility may be secured by all or any portion of the Collateral (but not by any other assets) and may be guaranteed by each Subsidiary Guarantor; provided that (a) the Indebtedness under such credit facility will not mature prior to the six month anniversary of the Term Loan Maturity Date, (b) such credit facility provides for no scheduled amortization, payments of principal, sinking fund or similar scheduled payments (other than regularly scheduled payments of interest), (c) such credit facility has covenant, default and remedy provisions satisfactory to the Administrative Agent, (d) such credit facility has provisions relating to mandatory prepayment, repurchase, redemption and offers to purchase that are consistent with those customarily found in second lien financings, as reasonably determined by the Administrative Agent and (e) concurrently with the effectiveness of such credit facility, the Second Lien Intercreditor Agreement shall have been entered into and shall at all times thereafter be in full force and effect.

“Second Lien Facility Documents” shall mean the credit agreement or loan agreement evidencing the Second Lien Facility and all security agreements, guarantees, pledge agreements and other agreements or instruments executed in connection therewith.

“Second Lien Intercreditor Agreement” shall mean an intercreditor agreement among the Borrower, the Subsidiary Guarantors, the Administrative Agent and the agent under the Second Lien Facility, pursuant to which the Liens on the Collateral securing the obligations under the Second Lien Facility are subordinated to the Liens on the Collateral securing the Obligations on terms and conditions satisfactory to the Administrative Agent.

“Secured Parties” shall have the meaning assigned to such term in the Guarantee and Collateral Agreement.

“Security Documents” shall mean the Mortgages, the Guarantee and Collateral Agreement, the Foreign Pledge Agreements and each of the security agreements, mortgages and other instruments and documents executed and delivered pursuant to any of the foregoing or pursuant to Section 5.09.

“Series A Preferred Stock” shall mean the 13 ¹/2% Series A Cumulative Perpetual Preferred Stock issued by the Borrower on August 3, 2005.

“Series B Preferred Stock” shall mean the 12 ¹/2% Series B Cumulative Perpetual Preferred Stock issued by the Borrower on March 20, 2006.

“SPC” shall have the meaning assigned to such term in Section 9.04(i).

“Statutory Reserves” shall mean a fraction (expressed as a decimal), the numerator of which is the number one and the denominator of which is the number one minus the aggregate of

25

the maximum reserve percentages (including any marginal, special, emergency or supplemental reserves) expressed as a decimal established by the Board and any other banking authority, domestic or foreign, to which the Administrative Agent or any Lender (including any branch, Affiliate or other fronting office making or holding a Loan) is subject for Eurocurrency Liabilities (as defined in Regulation D of the Board). Eurodollar Loans shall be deemed to constitute Eurocurrency Liabilities (as defined in Regulation D of the Board) and to be subject to such reserve requirements without benefit of or credit for proration, exemptions or offsets that may be available from time to time to any Lender under such Regulation D. Statutory Reserves shall be adjusted automatically on and as of the effective date of any change in any reserve percentage.

“subsidiary” shall mean, with respect to any person (herein referred to as the “parent”), any corporation, partnership, limited liability company, association or other business entity (a) of which securities or other ownership interests representing more than 50% of the equity or more than 50% of the ordinary voting power or more than 50% of the general partnership interests are, at the time any determination is being made, owned, Controlled or held, or (b) that is, at the time any determination is made, otherwise Controlled, by the parent or one or more subsidiaries of the parent or by the parent and one or more subsidiaries of the parent.

“Subsidiary” shall mean any subsidiary of the Borrower.

“Subsidiary Guarantor” shall mean each Subsidiary listed on Schedule 1.01(c), and each other Subsidiary that is or becomes a party to the Guarantee and Collateral Agreement.

“Synthetic Lease” shall mean, as to any person, any lease (including leases that may be terminated by the lessee at any time) of any property (whether real, personal or mixed) (a) that is accounted for as an operating lease under GAAP and (b) in respect of which the lessee retains or obtains ownership of the property so leased for U.S. federal income tax purposes, other than any such lease under which such person is the lessor.

“Synthetic Lease Obligations” shall mean, as to any person, an amount equal to the capitalized amount of the remaining lease payments under any Synthetic Lease that would appear on a balance sheet of such person in accordance with GAAP if such obligations were accounted for as Capital Lease Obligations.

“Synthetic Purchase Agreement” shall mean any swap, derivative or other agreement or combination of agreements pursuant to which the Borrower or any Subsidiary is or may become obligated to make (a) any payment in connection with a purchase by any third party from a person other than the Borrower or any Subsidiary of any Equity Interest or Restricted Indebtedness or (b) any payment (other than on account of a permitted purchase by it of any Equity Interest or Restricted Indebtedness) the amount of which is determined by reference to the price or value at any time of any Equity Interest or Restricted Indebtedness; provided that no phantom stock or similar plan providing for payments only to current or former directors, officers or employees of the Borrower or the Subsidiaries (or to their heirs or estates) shall be deemed to be a Synthetic Purchase Agreement.

26

“Taxes” shall mean any and all present or future taxes, levies, imposts, duties, deductions, charges, liabilities or withholdings imposed by any Governmental Authority.

“Term Borrowing” shall mean a Borrowing comprised of Term Loans.

“Term Lender” shall mean a Lender with a Term Loan Commitment or an outstanding Term Loan.

“Term Loan Commitment” shall mean, with respect to each Lender, the commitment of such Lender to make Term Loans hereunder. As of the Restatement Date, there are no outstanding Term Loan Commitments.

“Term Loan Maturity Date” shall mean April 14, 2010.

“Term Loans” shall mean, unless the context otherwise requires, the Existing Term Loans. On the Restatement Date, the aggregate outstanding principal amount of the Term Loans is $898,687,500.

“Three-Year Strip Price” shall mean, as of any date of determination, (a) for the 36-month period commencing with the month immediately following the month in which the date of determination occurs, the monthly futures contract prices for crude oil and natural gas for the 36 succeeding months as quoted on the applicable commodities exchange or other price quotation source as contemplated in the definitions of “PV-10 Value” and “Probable Reserve Value” and (b) for periods after such 36-month period, the average of such quoted prices for the period from and including the 25th month in such 36-month period through the 36th month in such period.

“Total Net Debt” shall mean, at any time, (a) the total Indebtedness of the Borrower and the Subsidiaries at such time (excluding Indebtedness of the type described in clause (i) of the definition of such term, except to the extent of any unreimbursed drawings thereunder), less (b) the amount of unrestricted cash on hand at the Borrower and the Subsidiary Guarantors. The fact that the Collateral Agent holds a Lien against funds on deposit in accounts will not cause such funds to be considered restricted for purposes of this definition.

“Total Revolving Credit Commitment” shall mean, at any time, the aggregate amount of the Revolving Credit Commitments, as in effect at such time. The initial Total Revolving Credit Commitment is $50,000,000.

“Transactions” shall mean, collectively, (a) the execution, delivery and performance by the Loan Parties of the Loan Documents to which they are a party and, in the case of the Borrower, the making of the Borrowings hereunder and (b) the payment of related fees and expenses.

“Type”, when used in respect of any Loan or Borrowing, shall refer to the Rate by reference to which interest on such Loan or on the Loans comprising such Borrowing is determined. For purposes hereof, the term “Rate” shall include the Adjusted LIBO Rate and the Alternate Base Rate.

27

“UK Sector” shall mean the jurisdiction of the United Kingdom commonly referred to as the UK Sector—North Sea.

“Underlying Debt Obligations” shall mean, with respect to any Loan Party at any given time, the aggregate amount (whether matured or not) owing by such Loan Party at such time under the Loan Documents (other than the amount of such Loan Party’s Dutch Parallel Debt).

“USA Patriot Act” shall mean The Uniting and Strengthening America by Providing Appropriate Tools Required to Intercept and Obstruct Terrorism Act of 2001 (Title III of Pub. L. No. 107-56 (signed into law October 26, 2001)), as amended from time to time.

“wholly owned Subsidiary” of any person shall mean a subsidiary of such person of which securities (except for directors’ qualifying shares) or other ownership interests representing 100% of the Equity Interests are, at the time any determination is being made, owned, Controlled or held by such person or one or more wholly owned Subsidiaries of such person or by such person and one or more wholly owned Subsidiaries of such person.

“Withdrawal Liability” shall mean liability to a Multiemployer Plan as a result of a complete or partial withdrawal from such Multiemployer Plan, as such terms are defined in Part I of Subtitle E of Title IV of ERISA.

SECTION 1.02. Terms Generally. The definitions in Section 1.01 shall apply equally to both the singular and plural forms of the terms defined. Whenever the context may require, any pronoun shall include the corresponding masculine, feminine and neuter forms. The words “include”, “includes” and “including” shall be deemed to be followed by the phrase “without limitation”. The word “will” shall be construed to have the same meaning and effect as the word “shall”; and the words “asset” and “property” shall be construed as having the same meaning and effect and to refer to any and all tangible and intangible assets and properties, including cash, securities, accounts and contract rights. All references herein to Articles, Sections, Exhibits and Schedules shall be deemed references to Articles and Sections of, and Exhibits and Schedules to, this Agreement unless the context shall otherwise require. Except as otherwise expressly provided herein, (a) any reference in this Agreement to any Loan Document shall mean such document as amended, restated, supplemented or otherwise modified from time to time and (b) all terms of an accounting or financial nature shall be construed in accordance with GAAP, as in effect from time to time; provided, however, that if the Borrower notifies the Administrative Agent that the Borrower wishes to amend any covenant in Article VI or any related definition to eliminate the effect of any change in GAAP occurring after the date of this Agreement on the operation of such covenant (or if the Administrative Agent notifies the Borrower that the Required Lenders wish to amend Article VI or any related definition for such purpose), then the Borrower’s compliance with such covenant shall be determined on the basis of GAAP in effect immediately before the relevant change in GAAP became effective, until either such notice is withdrawn or such covenant is amended in a manner satisfactory to the Borrower and the Required Lenders.

SECTION 1.03. Pro Forma Calculations. With respect to any period during which any Permitted Business Investment of the type described in clause (a) of the definition of the term “Pro Forma Basis” or Asset Sale of the type described in clause (b) of such definition occurs as

28

permitted pursuant to the terms hereof, the Leverage Ratio, the Interest Coverage Ratio, the Current Ratio and each of the Asset Coverage Ratios shall be calculated with respect to such period and such Permitted Business Investment or Asset Sale on a Pro Forma Basis.

SECTION 1.04. Classification of Loans and Borrowings. For purposes of this Agreement, Loans may be classified and referred to by Class (e.g., a “Revolving Loan”) or by Type (e.g., a “Eurocurrency Loan”) or by Class and Type (e.g., a “Eurocurrency Revolving Loan”). Borrowings also may be classified and referred to by Class (e.g., a “Revolving Borrowing”) or by Type (e.g., a “Eurocurrency Borrowing”) or by Class and Type (e.g., a “Eurocurrency Revolving Borrowing”).

ARTICLE II

The Credits

SECTION 2.01. Commitments. Subject to the terms and conditions and relying upon the representations and warranties set forth herein and in the other Loan Documents, each Revolving Credit Lender agrees, severally and not jointly, to make Revolving Loans to the Borrower, at any time and from time to time on or after the Restatement Date, and until the earlier of the Revolving Credit Maturity Date and the termination of the Revolving Credit Commitment of such Lender in accordance with the terms hereof, in an aggregate principal amount at any time outstanding that will not result in such Lender’s Revolving Credit Exposure exceeding such Lender’s Revolving Credit Commitment. Within the limits set forth in the preceding sentence and subject to the terms, conditions and limitations set forth herein, the Borrower may borrow, pay or prepay and reborrow Revolving Loans. Amounts paid or prepaid in respect of Term Loans may not be reborrowed.

SECTION 2.02. Loans. (a) Each Loan has been or shall be made as part of a Borrowing consisting of Loans made by the Lenders ratably in accordance with their applicable Commitments; provided, however, that the failure of any Lender to make any Loan shall not in itself relieve any other Lender of its obligation to lend hereunder (it being understood, however, that no Lender shall be responsible for the failure of any other Lender to make any Loan required to be made by such other Lender). Except for Loans deemed made pursuant to Section 2.02(f), the Loans comprising any Borrowing shall be in an aggregate principal amount that is (i) an integral multiple of $1,000,000 and not less than $5,000,000 or (ii) equal to the remaining available balance of the applicable Commitments.

(b) Subject to Sections 2.02(f), 2.08 and 2.15, each Borrowing shall be comprised entirely of ABR Loans or Eurodollar Loans as the Borrower may request pursuant to Section 2.03. Each Lender may at its option make any Eurodollar Loan by causing any domestic or foreign branch or Affiliate of such Lender to make such Loan; provided that any exercise of such option shall not affect the obligation of the Borrower to repay such Loan in accordance with the terms of this Agreement. Borrowings of more than one Type may be outstanding at the same time; provided, however, that the Borrower shall not be entitled to request any Borrowing that, if made, would result in more than six Eurodollar Borrowings outstanding hereunder at any time. For purposes of the foregoing, Borrowings having different Interest Periods, regardless of whether they commence on the same date, shall be considered separate Borrowings.

29

(c) Except with respect to Loans made pursuant to Section 2.02(f), each Lender shall make each Loan to be made by it hereunder on the proposed date thereof by wire transfer of immediately available funds to such account in New York City as the Administrative Agent may designate not later than 1:00 p.m., New York City time, on such date, and the Administrative Agent shall promptly credit the amounts so received to an account designated by the Borrower in the applicable Borrowing Request or, if a Borrowing shall not occur on such date because any condition precedent herein specified shall not have been met, return the amounts so received to the respective Lenders.

(d) Unless the Administrative Agent shall have received notice from a Lender prior to the date of any Borrowing that such Lender will not make available to the Administrative Agent such Lender’s portion of such Borrowing, the Administrative Agent may assume that such Lender has made such portion available to the Administrative Agent on the date of such Borrowing in accordance with paragraph (c) above and the Administrative Agent may, in reliance upon such assumption, make available to the Borrower on such date a corresponding amount. If the Administrative Agent shall have so made funds available then, to the extent that such Lender shall not have made such portion available to the Administrative Agent, such Lender and the Borrower severally agree to repay to the Administrative Agent forthwith on demand such corresponding amount together with interest thereon, for each day from the date such amount is made available to the Borrower until the date such amount is repaid to the Administrative Agent at (i) in the case of the Borrower, the interest rate applicable at the time to the Loans comprising such Borrowing and (ii) in the case of such Lender, (A) for the first two days following the date such amount is made available to the Borrower, a rate determined by the Administrative Agent to represent its cost of overnight or short-term funds (which determination shall be conclusive absent manifest error) and (B) thereafter, at the Alternate Base Rate. If such Lender shall repay to the Administrative Agent such corresponding amount, such amount shall constitute such Lender’s Loan as part of such Borrowing for purposes of this Agreement.

(e) Notwithstanding any other provision of this Agreement, the Borrower shall not be entitled to request any Revolving Credit Borrowing if the Interest Period requested with respect thereto would end after the Revolving Credit Maturity Date.

(f) If the Issuing Bank shall not have received from the Borrower the payment required to be made by Section 2.23(e) within the time specified in such Section, the Issuing Bank will promptly notify the Administrative Agent of the L/C Disbursement and the Administrative Agent will promptly notify each Revolving Credit Lender of such L/C Disbursement and its Pro Rata Percentage thereof. Each Revolving Credit Lender shall pay by wire transfer of immediately available funds to the Administrative Agent not later than 2:00 p.m., New York City time, on such date (or, if such Revolving Credit Lender shall have received such notice later than 12:00 (noon), New York City time, on any day, not later than 10:00 a.m., New York City time, on the immediately following Business Day), an amount equal to such Lender’s Pro Rata Percentage of such L/C Disbursement (it being understood that (i) if the conditions precedent to borrowing set forth in paragraphs (b) and (c) of Article IV have been satisfied, such amount shall be deemed to constitute an ABR Revolving Loan of such Lender and, to the extent of such payment, the obligations of the Borrower in respect of such L/C Disbursement shall be discharged and replaced with the resulting ABR Revolving Credit Borrowing, and (ii) if such conditions precedent to borrowing have not been satisfied, then any such amount paid by any

30

Revolving Credit Lender shall not constitute a Loan and shall not relieve the Borrower from its obligation to reimburse such L/C Disbursement), and the Administrative Agent will promptly pay to the Issuing Bank amounts so received by it from the Revolving Credit Lenders. The Administrative Agent will promptly pay to the Issuing Bank any amounts received by it from the Borrower pursuant to Section 2.23(e) prior to the time that any Revolving Credit Lender makes any payment pursuant to this paragraph (f); any such amounts received by the Administrative Agent thereafter will be promptly remitted by the Administrative Agent to the Revolving Credit Lenders that shall have made such payments and to the Issuing Bank, as their interests may appear. If any Revolving Credit Lender shall not have made its Pro Rata Percentage of such L/C Disbursement available to the Administrative Agent as provided above, such Lender and the Borrower severally agree to pay interest on such amount, for each day from and including the date such amount is required to be paid in accordance with this paragraph to but excluding the date such amount is paid, to the Administrative Agent for the account of the Issuing Bank at (i) in the case of the Borrower, a rate per annum equal to the interest rate applicable to Revolving Loans pursuant to Section 2.06(a), and (ii) in the case of such Lender, for the first such day, the Federal Funds Effective Rate, and for each day thereafter, the Alternate Base Rate.

SECTION 2.03. Borrowing Procedure. In order to request a Borrowing (other than a deemed Borrowing pursuant to Section 2.02(f), as to which this Section 2.03 shall not apply), the Borrower shall notify the Administrative Agent of such request by telephone (a) in the case of a Eurodollar Borrowing, not later than 11:00 a.m., New York City time, three Business Days before a proposed Borrowing, and (b) in the case of an ABR Borrowing, not later than 12:00 noon, New York City time, one Business Day before a proposed Borrowing. Each such telephonic Borrowing Request shall be irrevocable, and shall be confirmed promptly by hand delivery or fax to the Administrative Agent of a written Borrowing Request and shall specify the following information: (i) whether the Borrowing then being requested is to be a Term Borrowing or a Revolving Credit Borrowing, and whether such Borrowing is to be a Eurodollar Borrowing or an ABR Borrowing; (ii) the date of such Borrowing (which shall be a Business Day); (iii) the number and location of the account to which funds are to be disbursed; (iv) the amount of such Borrowing; and (v) if such Borrowing is to be a Eurodollar Borrowing, the Interest Period with respect thereto; provided, however, that, notwithstanding any contrary specification in any Borrowing Request, each requested Borrowing shall comply with the requirements set forth in Section 2.02. If no election as to the Type of Borrowing is specified in any such notice, then the requested Borrowing shall be an ABR Borrowing. If no Interest Period with respect to any Eurodollar Borrowing is specified in any such notice, then the Borrower shall be deemed to have selected an Interest Period of one month’s duration. The Administrative Agent shall promptly advise the applicable Lenders of any notice given pursuant to this Section 2.03 (and the contents thereof), and of each Lender’s portion of the requested Borrowing.

SECTION 2.04. Evidence of Debt; Repayment of Loans. (a) The Borrower hereby unconditionally promises to pay to the Administrative Agent for the account of each Lender (i) the principal amount of each Term Loan of such Lender as provided in Section 2.11 and (ii) the then unpaid principal amount of each Revolving Loan of such Lender on the Revolving Credit Maturity Date.

31

(b) Each Lender shall maintain in accordance with its usual practice an account or accounts evidencing the indebtedness of the Borrower to such Lender resulting from each Loan made by such Lender from time to time, including the amounts of principal and interest payable and paid to such Lender from time to time under this Agreement.

(c) The Administrative Agent shall maintain accounts in which it will record (i) the amount of each Loan made hereunder, the Class and Type thereof and, if applicable, the Interest Period applicable thereto, (ii) the amount of any principal or interest due and payable or to become due and payable from the Borrower to each Lender hereunder and (iii) the amount of any sum received by the Administrative Agent hereunder from the Borrower or any Subsidiary Guarantor and each Lender’s share thereof.

(d) The entries made in the accounts maintained pursuant to paragraphs (b) and (c) above shall be prima facie evidence of the existence and amounts of the obligations therein recorded; provided, however, that the failure of any Lender or the Administrative Agent to maintain such accounts or any error therein shall not in any manner affect the obligations of the Borrower to repay the Loans in accordance with their terms.

(e) Any Lender may request that Loans made by it hereunder be evidenced by a promissory note. In such event, the Borrower shall execute and deliver to such Lender a promissory note payable to such Lender and its registered assigns and in a form and substance reasonably acceptable to the Administrative Agent and the Borrower. Notwithstanding any other provision of this Agreement, in the event any Lender shall request and receive such a promissory note, the interests represented by such note shall at all times (including after any assignment of all or part of such interests pursuant to Section 9.04) be represented by one or more promissory notes payable to the payee named therein or its registered assigns.

SECTION 2.05. Fees. (a) The Borrower agrees to pay to each Revolving Credit Lender, through the Administrative Agent, on the last Business Day of March, June, September and December in each year and on each date on which any Revolving Credit Commitment of such Lender shall expire or be terminated as provided herein, a commitment fee (a “Commitment Fee”) equal to the amount shown in the table below per annum on the daily unused amount of the Revolving Credit Commitment of such Lender during the preceding quarter (or other period commencing with the Restatement Date or ending with the Revolving Credit Maturity Date or the date on which the Commitments of such Lender shall expire or be terminated). All Commitment Fees shall be computed on the basis of the actual number of days elapsed in a year of 360 days.

Average Revolving Loan Utilization	Commitment Fee
0 - < 25%	1.0000%
25% - < 50%	0.8333%
50% - < 75%	0.6667%
75% - 100%	0.5000%

32

(b) The Borrower agrees to pay to the Administrative Agent, for its own account, the non-refundable administration fees set forth in the Fee Letter at the times and in the amounts specified therein (the “Administrative Agent Fees”).

(c) The Borrower agrees to pay (i) to each Revolving Credit Lender, through the Administrative Agent, on the last Business Day of March, June, September and December of each year and on the date on which the Revolving Credit Commitment of such Lender shall be terminated as provided herein, a fee (an “L/C Participation Fee”) calculated on such Lender’s Pro Rata Percentage of the daily aggregate L/C Exposure (excluding the portion thereof attributable to unreimbursed L/C Disbursements) during the preceding quarter (or shorter period commencing with the date hereof or ending with the Revolving Credit Maturity Date or the date on which all Letters of Credit have been canceled or have expired and the Revolving Credit Commitments of all Lenders shall have been terminated) at a rate per annum equal to the Applicable Percentage from time to time used to determine the interest rate on Revolving Credit Borrowings comprised of Eurodollar Loans pursuant to Section 2.06, and (ii) to the Issuing Bank with respect to each Letter of Credit the fronting, issuance and drawing fees customary with respect to letters of credit specified from time to time by the Issuing Bank (the “Issuing Bank Fees”). All L/C Participation Fees and Issuing Bank Fees shall be computed on the basis of the actual number of days elapsed in a year of 360 days.

(d) All Fees shall be paid on the dates due, in immediately available funds, to the Administrative Agent for distribution, if and as appropriate, among the Lenders, except that the Issuing Bank Fees shall be paid directly to the Issuing Bank. Absent manifest error in the calculation of any Fee paid, once paid, none of the Fees shall be refundable under any circumstances.

SECTION 2.06. Interest on Loans. (a) Subject to the provisions of Section 2.07, the Loans comprising each ABR Borrowing shall bear interest (computed on the basis of the actual number of days elapsed over a year of 365 or 366 days, as the case may be, when the Alternate Base Rate is determined by reference to the Prime Rate and over a year of 360 days at all other times and calculated from and including the date of such Borrowing to but excluding the date of repayment thereof) at a rate per annum equal to the Alternate Base Rate plus the Applicable Percentage.

(b) Subject to the provisions of Section 2.07, the Loans comprising each Eurodollar Borrowing shall bear interest (computed on the basis of the actual number of days elapsed over a year of 360 days) at a rate per annum equal to the Adjusted LIBO Rate for the Interest Period in effect for such Borrowing plus the Applicable Percentage.

(c) Interest on each Loan shall be payable on the Interest Payment Dates applicable to such Loan except as otherwise provided in this Agreement. The applicable Alternate Base Rate or Adjusted LIBO Rate for each Interest Period or day within an Interest Period, as the case may be, shall be determined by the Administrative Agent, and such determination shall be conclusive absent manifest error.

SECTION 2.07. Default Interest. If the Borrower shall default in the payment of any principal of or interest on any Loan or any other amount due hereunder, by acceleration or

33

otherwise, or under any other Loan Document, then, until such defaulted amount shall have been paid in full, to the extent permitted by law, all amounts outstanding under this Agreement and the other Loan Documents shall bear interest (after as well as before judgment), payable on demand, (a) in the case of principal, at the rate otherwise applicable to such Loan pursuant to Section 2.06 plus 2.00% per annum and (b) in all other cases, at a rate per annum (computed on the basis of the actual number of days elapsed over a year of 365 or 366 days, as the case may be, when determined by reference to the Prime Rate and over a year of 360 days at all other times) equal to the rate that would be applicable to an ABR Loan plus 2.00% per annum.

SECTION 2.08. Alternate Rate of Interest. In the event, and on each occasion, that on the day two Business Days prior to the commencement of any Interest Period for a Eurodollar Borrowing the Administrative Agent shall have determined that dollar deposits in the principal amounts of the Loans comprising such Borrowing are not generally available in the London interbank market, or that the rates at which such dollar deposits are being offered will not adequately and fairly reflect the cost to any Lender of making or maintaining its Eurodollar Loan during such Interest Period, or that reasonable means do not exist for ascertaining the Adjusted LIBO Rate, the Administrative Agent shall, as soon as practicable thereafter, give written or fax notice of such determination to the Borrower and the Lenders. In the event of any such determination, until the Administrative Agent shall have advised the Borrower and the Lenders that the circumstances giving rise to such notice no longer exist, any request by the Borrower for a Eurodollar Borrowing pursuant to Section 2.03 or 2.10 shall be deemed to be a request for an ABR Borrowing. Each determination by the Administrative Agent under this Section 2.08 shall be conclusive absent manifest error.

SECTION 2.09. Termination and Reduction of Commitments. (a) The Revolving Credit Commitments shall automatically terminate on the Revolving Credit Maturity Date. The L/C Commitment shall automatically terminate on the earlier to occur of (i) the termination of the Revolving Credit Commitments and (ii) the date 30 days prior to the Revolving Credit Maturity Date.

(b) Upon at least three Business Days’ prior irrevocable written or fax notice to the Administrative Agent, the Borrower may at any time in whole permanently terminate, or from time to time in part permanently reduce, the Revolving Credit Commitments; provided, however, that (i) each partial reduction of the Revolving Credit Commitments shall be in an integral multiple of $1,000,000 and in a minimum amount of $5,000,000 and (ii) the Total Revolving Credit Commitment shall not be reduced to an amount that is less than the Aggregate Revolving Credit Exposure at the time.

(c) Each reduction in the Revolving Credit Commitments hereunder shall be made ratably among the Revolving Credit Lenders in accordance with their respective Revolving Credit Commitments. The Borrower shall pay to the Administrative Agent for the account of the Revolving Credit Lenders, on the date of each termination or reduction, the Commitment Fees on the amount of the Revolving Credit Commitments so terminated or reduced accrued to but excluding the date of such termination or reduction.

SECTION 2.10. Conversion and Continuation of Borrowings. The Borrower shall have the right at any time upon prior irrevocable notice to the Administrative Agent not later than

34

12:00 (noon), New York City time, (a) one Business Day prior thereto, to convert any Eurodollar Borrowing into an ABR Borrowing, (b) three Business Days prior thereto, to convert any ABR Borrowing into a Eurodollar Borrowing or to continue any Eurodollar Borrowing as a Eurodollar Borrowing for an additional Interest Period, and (c) three Business Days prior thereto, to convert the Interest Period with respect to any Eurodollar Borrowing to another permissible Interest Period, subject in each case to the following:

(i) each conversion or continuation shall be made pro rata among the Lenders in accordance with the respective principal amounts of the Loans comprising the converted or continued Borrowing;

(ii) if less than all the outstanding principal amount of any Borrowing shall be converted or continued, then each resulting Borrowing shall satisfy the limitations specified in Sections 2.02(a) and 2.02(b) regarding the principal amount and maximum number of Borrowings of the relevant Type;

(iii) each conversion shall be effected by each Lender and the Administrative Agent by recording for the account of such Lender the new Loan of such Lender resulting from such conversion and reducing the Loan (or portion thereof) of such Lender being converted by an equivalent principal amount; accrued interest on any Eurodollar Loan (or portion thereof) being converted shall be paid by the Borrower at the time of conversion;

(iv) if any Eurodollar Borrowing is converted at a time other than the end of the Interest Period applicable thereto, the Borrower shall pay, upon demand, any amounts due to the Lenders pursuant to Section 2.16;

(v) any portion of a Borrowing maturing or required to be repaid in less than one month may not be converted into or continued as a Eurodollar Borrowing;

(vi) any portion of a Eurodollar Borrowing that cannot be converted into or continued as a Eurodollar Borrowing by reason of the immediately preceding clause shall be automatically converted at the end of the Interest Period in effect for such Borrowing into an ABR Borrowing;

(vii) no Interest Period may be selected for any Eurodollar Term Borrowing that would end later than a Repayment Date occurring on or after the first day of such Interest Period if, after giving effect to such selection, the aggregate outstanding amount of (A) the Eurodollar Term Borrowings with Interest Periods ending on or prior to such Repayment Date and (B) the ABR Term Borrowings would not be at least equal to the principal amount of Term Borrowings to be paid on such Repayment Date; and

(viii) upon notice to the Borrower from the Administrative Agent given at the request of the Required Lenders, after the occurrence and during the continuance of a Default or Event of Default, no outstanding Loan may be converted into, or continued as, a Eurodollar Loan.

Each notice pursuant to this Section 2.10 shall be irrevocable and shall refer to this Agreement and specify (i) the identity and amount of the Borrowing that the Borrower requests

35

be converted or continued, (ii) whether such Borrowing is to be converted to or continued as a Eurodollar Borrowing or an ABR Borrowing, (iii) if such notice requests a conversion, the date of such conversion (which shall be a Business Day) and (iv) if such Borrowing is to be converted to or continued as a Eurodollar Borrowing, the Interest Period with respect thereto. If no Interest Period is specified in any such notice with respect to any conversion to or continuation as a Eurodollar Borrowing, the Borrower shall be deemed to have selected an Interest Period of one month’s duration. The Administrative Agent shall advise the Lenders of any notice given pursuant to this Section 2.10 and of each Lender’s portion of any converted or continued Borrowing. If the Borrower shall not have given notice in accordance with this Section 2.10 to continue any Borrowing into a subsequent Interest Period (and shall not otherwise have given notice in accordance with this Section 2.10 to convert such Borrowing), such Borrowing shall, at the end of the Interest Period applicable thereto (unless repaid pursuant to the terms hereof), automatically be continued into an ABR Borrowing.

SECTION 2.11. Repayment of Term Borrowings. (a) The Borrower shall pay to the Administrative Agent, for the account of the Lenders, on the dates set forth below, or if any such date is not a Business Day, on the next preceding Business Day (each such date being called a “Repayment Date”), a principal amount of the Term Loans (as adjusted from time to time pursuant to Sections 2.11(b), 2.12 and 2.13(f)) equal to the amount set forth below for such date, together in each case with accrued and unpaid interest on the principal amount to be paid to but excluding the date of such payment:

Repayment Date	Amount
December 31, 2006	$	2,246,719
March 31, 2007	$	2,246,719
June 30, 2007	$	2,246,719
September 30, 2007	$	2,246,719
December 31, 2007	$	2,246,719
March 31, 2008	$	2,246,719
June 30, 2008	$	2,246,719
September 30, 2008	$	2,246,719
December 31, 2008	$	2,246,719
March 31, 2009	$	2,246,719
June 30, 2009	$	219,055,077
September 30, 2009	$	219,055,078
December 31, 2009	$	219,055,077
Term Loan Maturity Date	$	219,055,078

(b) In the event and on each occasion that the Term Loan Commitments shall be reduced or shall expire or terminate other than as a result of the making of a Term Loan, the installments payable on each Repayment Date shall be reduced pro rata by an aggregate amount equal to the amount of such reduction, expiration or termination.

(c) To the extent not previously paid, all Term Loans shall be due and payable on the Term Loan Maturity Date, together with accrued and unpaid interest on the principal amount to be paid to but excluding the date of payment.

36

(d) All repayments pursuant to this Section 2.11 shall be subject to Section 2.16, but shall otherwise be without premium or penalty.

SECTION 2.12. Optional Prepayment. (a) The Borrower shall have the right at any time and from time to time to prepay any Borrowing, in whole or in part, upon written or fax notice (or telephone notice promptly confirmed by written or fax notice) at least one Business Day prior to the date of prepayment to the Administrative Agent before 12:00 (noon), New York City time; provided, however, that each partial prepayment shall be in an amount that is an integral multiple of $1,000,000 and not less than $5,000,000.

(b) Optional prepayments of Term Loans at any time during the applicable periods set forth in this Section 2.12(b) shall be accompanied by a payment of a prepayment fee in an amount (expressed as a percentage of the principal amount of the Loans to be repaid) equal to (i) 1.00%, if such prepayment occurs on or prior to the date that is six months after the Prior Restatement Date, and (ii) 0.50%, if such prepayment occurs after the date that is six months after the Prior Restatement Date, but on or prior to the first anniversary of the Prior Restatement Date.

(c) Optional prepayments of Term Loans shall be applied pro rata against the remaining scheduled installments of principal due in respect of the Term Loans under Section 2.11.

(d) Each notice of prepayment shall specify the prepayment date and the principal amount of each Borrowing (or portion thereof) to be prepaid, shall be irrevocable and shall commit the Borrower to prepay such Borrowing by the amount stated therein on the date stated therein. All prepayments under this Section 2.12 shall be subject to Section 2.16 but otherwise without premium or penalty, except as provided in Section 2.12(b). All prepayments under this Section 2.12 (other than prepayments of ABR Revolving Loans that are not made in connection with the termination or permanent reduction of the Revolving Credit Commitments) shall be accompanied by accrued and unpaid interest on the principal amount to be prepaid to but excluding the date of payment.

SECTION 2.13. Mandatory Prepayments. (a) In the event of any termination of all the Revolving Credit Commitments, the Borrower shall, on the date of such termination, repay or prepay all its outstanding Revolving Credit Borrowings and replace or cause to be canceled (or make other arrangements satisfactory to the Administrative Agent and the Issuing Bank with respect to) all outstanding Letters of Credit. If, after giving effect to any partial reduction of the Revolving Credit Commitments or at any other time, the Aggregate Revolving Credit Exposure would exceed the Total Revolving Credit Commitment, then the Borrower shall, on the date of such reduction or at such other time, repay or prepay Revolving Credit Borrowings and, after the Revolving Credit Borrowings shall have been repaid or prepaid in full, replace or cause to be canceled (or make other arrangements satisfactory to the Administrative Agent and the Issuing Bank with respect to) Letters of Credit in an amount sufficient to eliminate such excess.

(b) Not later than the third Business Day following the receipt of Net Cash Proceeds in respect of any Asset Sale, the Borrower shall apply 100% of the Net Cash Proceeds received with respect thereto to prepay outstanding Term Loans in accordance with Section 2.13(f).

37

(c) In the event and on each occasion that an Equity Issuance occurs, the Borrower shall, substantially simultaneously with (and in any event not later than the third Business Day next following) the occurrence of such Equity Issuance, apply 50% of the Net Cash Proceeds therefrom to prepay outstanding Term Loans in accordance with Section 2.13(f); provided, however, that if at the time of such Equity Issuance the Leverage Ratio (after giving effect to such Equity Issuance and the proposed use of the proceeds thereof) would be less than 2.5 to 1.0, then the amount required to be so applied shall be reduced to 25% of such Net Cash Proceeds.

(d) No later than the earlier of (i) 90 days after the end of each fiscal year of the Borrower, commencing with the fiscal year ending on December 31, 2006, and (ii) the date on which the financial statements with respect to such period are delivered pursuant to Section 5.04(a), the Borrower shall prepay outstanding Term Loans in accordance with Section 2.13(f) in an aggregate principal amount equal to 75% of Excess Cash Flow in excess of $5,000,000 for the fiscal year then ended; provided, however, that in the event the Leverage Ratio at the end of such fiscal year was less than 2.5 to 1.0, then such amount shall be reduced to 50% of such Excess Cash Flow in excess of $5,000,000.

(e) In the event that any Loan Party or any subsidiary of a Loan Party shall receive Net Cash Proceeds from the issuance of Indebtedness for money borrowed or consisting of Disqualified Capital Stock of any Loan Party or any subsidiary of a Loan Party (other than Indebtedness for money borrowed or consisting of Disqualified Capital Stock permitted pursuant to Section 6.01), the Borrower shall, substantially simultaneously with (and in any event not later than the third Business Day next following) the receipt of such Net Cash Proceeds by such Loan Party or such subsidiary, apply an amount equal to 100% of such Net Cash Proceeds to prepay outstanding Term Loans in accordance with Section 2.13(f).

(f) Mandatory prepayments of outstanding Term Loans under this Agreement shall be applied pro rata against the remaining scheduled installments of principal due in respect of the Term Loans under Section 2.11. All such mandatory prepayments shall be applied to all Term Loans outstanding on the date of prepayment on a pro rata basis.

(g) The Borrower shall deliver to the Administrative Agent, at the time of each prepayment required under this Section 2.13, (i) a certificate signed by a Financial Officer of the Borrower setting forth in reasonable detail the calculation of the amount of such prepayment and (ii) to the extent practicable, at least three days prior written notice of such prepayment. Each notice of prepayment shall specify the prepayment date, the Type of each Loan being prepaid and the principal amount of each Loan (or portion thereof) to be prepaid. All prepayments of Borrowings under this Section 2.13 shall be subject to Section 2.16, but shall otherwise be without premium or penalty.

(h) Notwithstanding the foregoing, any Lender may elect, by written notice to the Administrative Agent at least two Business Days prior to the applicable prepayment date (or such shorter period as may be acceptable to the Administrative Agent), to decline all (but not less than all) of any mandatory prepayment of its Loans pursuant to this Section 2.13 (such declined amounts, the “Declined Proceeds”). Any Declined Proceeds shall be offered to the Lenders not so declining such prepayment (with such Lenders having the right to decline any prepayment with Declined Proceeds in the same manner provided for in the previous sentence). To the

38

extent such Lenders elect to decline their pro rata shares of such Declined Proceeds, such remaining Declined Proceeds shall be applied in accordance with the mandatory prepayment provisions of the Second Lien Facility Documents. Notwithstanding any provision herein to the contrary, nothing herein shall limit the Borrower’s ability to make optional prepayments in accordance with Section 2.12.

SECTION 2.14. Reserve Requirements; Change in Circumstances. (a) Notwithstanding any other provision of this Agreement, if any Change in Law shall impose, modify or deem applicable any reserve, special deposit or similar requirement against assets of, deposits with or for the account of or credit extended by any Lender or the Issuing Bank (except any such reserve requirement which is reflected in the Adjusted LIBO Rate) or shall impose on such Lender or the Issuing Bank or the London interbank market any other condition affecting this Agreement or Eurodollar Loans made by such Lender or any Letter of Credit or participation therein, and the result of any of the foregoing shall be to increase the cost to such Lender or the Issuing Bank of making or maintaining any Eurodollar Loan or increase the cost to any Lender of issuing or maintaining any Letter of Credit or purchasing or maintaining a participation therein or to reduce the amount of any sum received or receivable by such Lender or the Issuing Bank hereunder (whether of principal, interest or otherwise), in each case, by an amount deemed by such Lender or the Issuing Bank to be material, then the Borrower will pay to such Lender or the Issuing Bank, as the case may be, upon demand such additional amount or amounts as will compensate such Lender or the Issuing Bank, as the case may be, for such additional costs incurred or reduction suffered.

(b) If any Lender or the Issuing Bank shall have determined that any Change in Law regarding capital adequacy has or would have the effect of reducing the rate of return on such Lender’s or the Issuing Bank’s capital or on the capital of such Lender’s or the Issuing Bank’s holding company, if any, as a consequence of this Agreement or the Loans made or participations in Letters of Credit purchased by such Lender pursuant hereto or the Letters of Credit issued by the Issuing Bank pursuant hereto to a level below that which such Lender or the Issuing Bank or such Lender’s or the Issuing Bank’s holding company could have achieved but for such Change in Law (taking into consideration such Lender’s or the Issuing Bank’s policies and the policies of such Lender’s or the Issuing Bank’s holding company with respect to capital adequacy) by an amount deemed by such Lender or the Issuing Bank to be material, then from time to time the Borrower shall pay to such Lender or the Issuing Bank, as the case may be, such additional amount or amounts as will compensate such Lender or the Issuing Bank or such Lender’s or the Issuing Bank’s holding company for any such reduction suffered.

(c) A certificate of a Lender or the Issuing Bank setting forth the amount or amounts necessary to compensate such Lender or the Issuing Bank or its holding company, as applicable, as specified in paragraph (a) or (b) above shall be delivered to the Borrower and shall be conclusive absent manifest error. The Borrower shall pay such Lender or the Issuing Bank the amount shown as due on any such certificate delivered by it within 10 days after its receipt of the same.

(d) Failure or delay on the part of any Lender or the Issuing Bank to demand compensation for any increased costs or reduction in amounts received or receivable or reduction in return on capital shall not constitute a waiver of such Lender’s or the Issuing Bank’s right to

39

demand such compensation; provided that the Borrower shall not be under any obligation to compensate any Lender or the Issuing Bank under paragraph (a) or (b) above with respect to increased costs or reductions with respect to any period prior to the date that is 120 days prior to such request if such Lender or the Issuing Bank knew or could reasonably have been expected to know of the circumstances giving rise to such increased costs or reductions and of the fact that such circumstances would result in a claim for increased compensation by reason of such increased costs or reductions; provided further that the foregoing limitation shall not apply to any increased costs or reductions arising out of the retroactive application of any Change in Law within such 120-day period. The protection of this Section shall be available to each Lender and the Issuing Bank regardless of any possible contention of the invalidity or inapplicability of the Change in Law that shall have occurred or been imposed.

SECTION 2.15. Change in Legality. (a) Notwithstanding any other provision of this Agreement, if any Change in Law shall make it unlawful for any Lender to make or maintain any Eurodollar Loan or to give effect to its obligations as contemplated hereby with respect to any Eurodollar Loan, then, by written notice to the Borrower and to the Administrative Agent:

(i) such Lender may declare that Eurodollar Loans will not thereafter (for the duration of such unlawfulness) be made by such Lender hereunder (or be continued for additional Interest Periods and ABR Loans will not thereafter (for such duration) be converted into Eurodollar Loans), whereupon any request for a Eurodollar Borrowing (or to convert an ABR Borrowing to a Eurodollar Borrowing or to continue a Eurodollar Borrowing for an additional Interest Period) shall, as to such Lender only, be deemed a request for an ABR Loan (or a request to continue an ABR Loan as such for an additional Interest Period or to convert a Eurodollar Loan into an ABR Loan, as the case may be), unless such declaration shall be subsequently withdrawn; and

(ii) such Lender may require that all outstanding Eurodollar Loans made by it be converted to ABR Loans, in which event all such Eurodollar Loans shall be automatically converted to ABR Loans as of the effective date of such notice as provided in paragraph (b) below.

In the event any Lender shall exercise its rights under (i) or (ii) above, all payments and prepayments of principal that would otherwise have been applied to repay the Eurodollar Loans that would have been made by such Lender or the converted Eurodollar Loans of such Lender shall instead be applied to repay the ABR Loans made by such Lender in lieu of, or resulting from the conversion of, such Eurodollar Loans.

(b) For purposes of this Section 2.15, a notice to the Borrower by any Lender shall be effective as to each Eurodollar Loan made by such Lender, if lawful, on the last day of the Interest Period then applicable to such Eurodollar Loan; in all other cases such notice shall be effective on the date of receipt by the Borrower.

SECTION 2.16. Indemnity. The Borrower shall indemnify each Lender against any loss or expense that such Lender sustains or incurs as a consequence of (a) any event, other than a default by such Lender in the performance of its obligations hereunder, which results in (i) such Lender receiving or being deemed to receive any amount on account of the principal of any

40

Eurodollar Loan prior to the end of the Interest Period in effect therefor, (ii) the conversion of any Eurodollar Loan to an ABR Loan, or the conversion of the Interest Period with respect to any Eurodollar Loan, in each case other than on the last day of the Interest Period in effect therefor, or (iii) any Eurodollar Loan to be made by such Lender (including any Eurodollar Loan to be made pursuant to a conversion or continuation under Section 2.10) not being made after notice of such Loan shall have been given by the Borrower hereunder (any of the events referred to in this clause (a) being called a “Breakage Event”) or (b) any default in the making of any payment or prepayment required to be made hereunder. In the case of any Breakage Event, such loss shall include an amount equal to the excess, as reasonably determined by such Lender, of (i) its cost of obtaining funds for the Eurodollar Loan that is the subject of such Breakage Event for the period from the date of such Breakage Event to the last day of the Interest Period in effect (or that would have been in effect) for such Loan over (ii) the amount of interest likely to be realized by such Lender in redeploying the funds released or not utilized by reason of such Breakage Event for such period. A certificate of any Lender setting forth any amount or amounts which such Lender is entitled to receive pursuant to this Section 2.16 shall be delivered to the Borrower and shall be conclusive absent manifest error.

SECTION 2.17. Pro Rata Treatment. Except as required under Section 2.15 and in respect of any election made pursuant to Section 2.13(h), each Borrowing, each payment or prepayment of principal of any Borrowing, each payment of interest on the Loans, each payment of the Commitment Fees, each payment of any prepayment fee, each reduction of the Term Loan Commitments or the Revolving Credit Commitments and each conversion of any Borrowing to or continuation of any Borrowing as a Borrowing of any Type shall be allocated pro rata among the Lenders in accordance with their respective applicable Commitments (or, if such Commitments shall have expired or been terminated, in accordance with the respective principal amounts of their outstanding Loans). Each Lender agrees that in computing such Lender’s portion of any Borrowing to be made hereunder, the Administrative Agent may, in its discretion, round each Lender’s percentage of such Borrowing to the next higher or lower whole dollar amount.

SECTION 2.18. Sharing of Setoffs. Each Lender agrees that if it shall, through the exercise of a right of banker’s lien, setoff or counterclaim against the Borrower or any other Loan Party, or pursuant to a secured claim under Section 506 of Title 11 of the United States Code or other security or interest arising from, or in lieu of, such secured claim, received by such Lender under any applicable bankruptcy, insolvency or other similar law or otherwise, or by any other means, obtain payment (voluntary or involuntary) in respect of any Loan or Loans or L/C Disbursement as a result of which the unpaid principal portion of its Loans and participations in L/C Disbursements shall be proportionately less than the unpaid principal portion of the Loans and participations in L/C Disbursements of any other Lender, it shall be deemed simultaneously to have purchased from such other Lender at face value, and shall promptly pay to such other Lender the purchase price for, a participation in the Loans and L/C Exposure of such other Lender, so that the aggregate unpaid principal amount of the Loans and L/C Exposure and participations in Loans and L/C Exposure held by each Lender shall be in the same proportion to the aggregate unpaid principal amount of all Loans and L/C Exposure then outstanding as the principal amount of its Loans and L/C Exposure prior to such exercise of banker’s lien, setoff or counterclaim or other event was to the principal amount of all Loans and L/C Exposure outstanding prior to such exercise of banker’s lien, setoff or counterclaim or other event;

41

provided, however, that if any such purchase or purchases or adjustments shall be made pursuant to this Section 2.18 and the payment giving rise thereto shall thereafter be recovered, such purchase or purchases or adjustments shall be rescinded to the extent of such recovery and the purchase price or prices or adjustment restored without interest. The Borrower expressly consents to the foregoing arrangements and agrees that any Lender holding a participation in a Loan or L/C Disbursement deemed to have been so purchased may exercise any and all rights of banker’s lien, setoff or counterclaim with respect to any and all moneys owing by the Borrower to such Lender by reason thereof as fully as if such Lender had made a Loan directly to the Borrower in the amount of such participation.

SECTION 2.19. Payments. (a) The Borrower shall make each payment (including principal of or interest on any Borrowing or any L/C Disbursement or any Fees or other amounts) hereunder and under any other Loan Document not later than 12:00 (noon), New York City time, on the date when due in immediately available dollars, without setoff, defense or counterclaim. Each such payment (other than Issuing Bank Fees, which shall be paid directly to the Issuing Bank) shall be made to the Administrative Agent at its offices at Eleven Madison Avenue, New York, NY 10010.

(b) Except as otherwise expressly provided herein, whenever any payment (including principal of or interest on any Borrowing or any Fees or other amounts) hereunder or under any other Loan Document shall become due, or otherwise would occur, on a day that is not a Business Day, such payment may be made on the next succeeding Business Day, and such extension of time shall in such case be included in the computation of interest or Fees, if applicable.

SECTION 2.20. Taxes. (a) Any and all payments by or on account of any obligation of the Borrower or any other Loan Party hereunder or under any other Loan Document shall be made free and clear of and without deduction for any Indemnified Taxes or Other Taxes; provided that if the Borrower or any other Loan Party shall be required to deduct any Indemnified Taxes or Other Taxes from such payments, then (i) the sum payable shall be increased as necessary so that after making all required deductions (including deductions applicable to additional sums payable under this Section) the Administrative Agent, such Lender or Issuing Bank (as the case may be) receives an amount equal to the sum it would have received had no such deductions been made, (ii) the Borrower or such Loan Party shall make such deductions and (iii) the Borrower or such Loan Party shall pay the full amount deducted to the relevant Governmental Authority in accordance with applicable law.

(b) In addition, the Borrower shall pay any Other Taxes to the relevant Governmental Authority in accordance with applicable law.

(c) The Borrower shall indemnify the Administrative Agent, each Lender and the Issuing Bank, within 10 days after written demand therefor, for the full amount of any Indemnified Taxes or Other Taxes paid by the Administrative Agent, such Lender or the Issuing Bank, as the case may be, on or with respect to any payment by or on account of any obligation of the Borrower or any other Loan Party hereunder or under any other Loan Document (including Indemnified Taxes or Other Taxes imposed or asserted on or attributable to amounts payable under this Section) and any penalties, interest and reasonable expenses arising therefrom or with

42

respect thereto, whether or not such Indemnified Taxes or Other Taxes were correctly or legally imposed or asserted by the relevant Governmental Authority. A certificate as to the amount of such payment or liability delivered to the Borrower by a Lender or the Issuing Bank, or by the Administrative Agent on its behalf or on behalf of a Lender or the Issuing Bank, shall be conclusive absent manifest error.

(d) As soon as practicable after any payment of Indemnified Taxes or Other Taxes by the Borrower or any other Loan Party to a Governmental Authority, the Borrower shall deliver to the Administrative Agent the original or a certified copy of a receipt issued by such Governmental Authority evidencing such payment, a copy of the return reporting such payment or other evidence of such payment reasonably satisfactory to the Administrative Agent.

(e) Any Foreign Lender that is entitled to an exemption from or reduction of withholding tax under the law of the jurisdiction in which the Borrower is located, or any treaty to which such jurisdiction is a party, with respect to payments under this Agreement shall deliver to the Borrower (with a copy to the Administrative Agent), at the time or times prescribed by applicable law, such properly completed and executed documentation prescribed by applicable law or reasonably requested by the Borrower as will permit such payments to be made without withholding or at a reduced rate.

SECTION 2.21. Assignment of Commitments or Loans Under Certain Circumstances; Duty to Mitigate. (a) In the event (i) any Lender or the Issuing Bank delivers a certificate requesting compensation pursuant to Section 2.14, (ii) any Lender or the Issuing Bank delivers a notice described in Section 2.15, (iii) the Borrower is required to pay any additional amount to any Lender or the Issuing Bank or any Governmental Authority on account of any Lender or the Issuing Bank pursuant to Section 2.20 or (iv) any Lender refuses to consent to any amendment, waiver or other modification of any Loan Document requested by the Borrower that requires the consent of a greater percentage of the Lenders than the Required Lenders and such amendment, waiver or other modification is consented to by the Required Lenders, the Borrower may, at its sole expense and effort (including with respect to the processing and recordation fee referred to in Section 9.04(b)), upon notice to such Lender or the Issuing Bank, as the case may be, and the Administrative Agent, require such Lender or the Issuing Bank to transfer and assign, without recourse (in accordance with and subject to the restrictions contained in Section 9.04), all of its interests, rights and obligations under this Agreement (or, in the case of clause (iv) above, all of its interests, rights and obligations with respect to the Class of Loans or Commitments that is the subject of the related consent, amendment, waiver or other modification) to an assignee that shall assume such assigned obligations (which assignee may be another Lender, if a Lender accepts such assignment); provided that (x) such assignment shall not conflict with any law, rule or regulation or order of any court or other Governmental Authority having jurisdiction, (y) the Borrower shall have received the prior written consent of the Administrative Agent (and, if a Revolving Credit Commitment is being assigned, of the Issuing Bank), which consents shall not unreasonably be withheld, and (z) the Borrower or such assignee shall have paid to the affected Lender or the Issuing Bank in immediately available funds an amount equal to the sum of the principal of and interest accrued to the date of such payment on the outstanding Loans or L/C Disbursements of such Lender or the Issuing Bank, respectively, plus all Fees and other amounts accrued for the account of such Lender or the Issuing Bank hereunder with respect thereto (including any amounts under Section 2.14 and Section 2.16 and, if applicable, the prepayment

43

fee pursuant to Section 2.12(b) (with such assignment being deemed to be an optional prepayment for purposes of determining the applicability of Section 2.12(b))); provided further that, if prior to any such transfer and assignment the circumstances or event that resulted in such Lender’s or the Issuing Bank’s claim for compensation under Section 2.14 or notice under Section 2.15 or the amounts paid pursuant to Section 2.20, as the case may be, cease to cause such Lender or the Issuing Bank to suffer increased costs or reductions in amounts received or receivable or reduction in return on capital, or cease to have the consequences specified in Section 2.15, or cease to result in amounts being payable under Section 2.20, as the case may be (including as a result of any action taken by such Lender or the Issuing Bank pursuant to paragraph (b) below), or if such Lender or the Issuing Bank shall waive its right to claim further compensation under Section 2.14 in respect of such circumstances or event or shall withdraw its notice under Section 2.15 or shall waive its right to further payments under Section 2.20 in respect of such circumstances or event or shall consent to the proposed amendment, waiver, consent or other modification, as the case may be, then such Lender or the Issuing Bank shall not thereafter be required to make any such transfer and assignment hereunder. Each Lender hereby grants to the Administrative Agent an irrevocable power of attorney (which power is coupled with an interest) to execute and deliver, on behalf of such Lender as assignor, any Assignment and Acceptance necessary to effectuate any assignment of such Lender’s interests hereunder in the circumstances contemplated by this Section 2.21(a).

(b) If (i) any Lender or the Issuing Bank shall request compensation under Section 2.14, (ii) any Lender or the Issuing Bank delivers a notice described in Section 2.15 or (iii) the Borrower is required to pay any additional amount to any Lender or the Issuing Bank or any Governmental Authority on account of any Lender or the Issuing Bank pursuant to Section 2.20, then such Lender or the Issuing Bank shall use reasonable efforts (which shall not require such Lender or the Issuing Bank to incur an unreimbursed loss or unreimbursed cost or expense or otherwise take any action inconsistent with its internal policies or legal or regulatory restrictions or suffer any disadvantage or burden deemed by it to be significant) (x) to file any certificate or document reasonably requested in writing by the Borrower or (y) to assign its rights and delegate and transfer its obligations hereunder to another of its offices, branches or affiliates, if such filing or assignment would reduce its claims for compensation under Section 2.14 or enable it to withdraw its notice pursuant to Section 2.15 or would reduce amounts payable pursuant to Section 2.20, as the case may be, in the future. The Borrower hereby agrees to pay all reasonable costs and expenses incurred by any Lender or the Issuing Bank in connection with any such filing or assignment, delegation and transfer.

SECTION 2.22. Application of Prepayment by Type of Term Loans. (a) In connection with any voluntary prepayments by the Borrower pursuant to Section 2.12, the amount thereof shall be applied first to ABR Loans to the full extent thereof before application to Eurodollar Loans, in each case in a manner that minimizes the amount of any payments required to be made by the Borrower pursuant to Section 2.16.

(b) In connection with any mandatory prepayments by the Borrower of the Term Loans pursuant to Section 2.13, the amount thereof shall be applied on a pro rata basis to the then outstanding Term Loans being prepaid irrespective of whether such outstanding Term Loans are ABR Loans or Eurodollar Loans; provided that if no Lenders exercise the right to waive a given mandatory prepayment of the Term Loans pursuant to Section 2.13(h), then, with respect to such

44

mandatory prepayment, the amount of such mandatory prepayment shall be applied first to Term Loans that are ABR Loans to the full extent thereof before application to Term Loans that are Eurodollar Loans in a manner that minimizes the amount of any payments required to be made by the Borrower pursuant to Section 2.16.

SECTION 2.23. Letters of Credit. (a) General. The Borrower may request the issuance of a Letter of Credit for its own account or for the account of any of its wholly owned Subsidiaries (in which case the Borrower and such wholly owned Subsidiary shall be co-applicants with respect to such Letter of Credit), in a form reasonably acceptable to the Administrative Agent and the Issuing Bank, at any time and from time to time while the L/C Commitment remains in effect. This Section shall not be construed to impose an obligation upon the Issuing Bank to issue any Letter of Credit that is inconsistent with the terms and conditions of this Agreement.

(b) Notice of Issuance, Amendment, Renewal, Extension; Certain Conditions. In order to request the issuance of Letters of Credit (or to amend, renew or extend any existing Letter of Credit), the Borrower shall hand deliver or fax to the Issuing Bank and the Administrative Agent (reasonably in advance of the requested date of issuance, amendment, renewal or extension) a notice requesting the issuance of a Letter of Credit, or identifying the Letter of Credit to be amended, renewed or extended, the date of issuance, amendment, renewal or extension, the date on which such Letter of Credit is to expire (which shall comply with paragraph (c) below), the amount of such Letter of Credit, the name and address of the beneficiary thereof and such other information as shall be necessary to prepare such Letter of Credit. A Letter of Credit shall be issued, amended, renewed or extended only if, and upon issuance, amendment, renewal or extension of each Letter of Credit, the Borrower shall be deemed to represent and warrant that, after giving effect to such issuance, amendment, renewal or extension (i) the L/C Exposure shall not exceed $50,000,000 and (ii) the Aggregate Revolving Credit Exposure shall not exceed the Total Revolving Credit Commitment.

(c) Expiration Date. Each Letter of Credit shall expire at the close of business on the earlier of the date one year after the date of the issuance of such Letter of Credit and the date that is five Business Days prior to the Revolving Credit Maturity Date, unless such Letter of Credit expires by its terms on an earlier date; provided, however, that a Letter of Credit may, upon the request of the Borrower, include a provision whereby such Letter of Credit shall be renewed automatically for additional consecutive periods of 12 months or less (but not beyond the date that is five Business Days prior to the Revolving Credit Maturity Date) unless the Issuing Bank notifies the beneficiary thereof at least 30 days (or such longer period as may be specified in such Letter of Credit) prior to the then-applicable expiration date that such Letter of Credit will not be renewed.

(d) Participations. By the issuance of a Letter of Credit and without any further action on the part of the Issuing Bank or the Lenders, the Issuing Bank hereby grants to each Revolving Credit Lender, and each Revolving Credit Lender hereby acquires from the Issuing Bank, a participation in such Letter of Credit equal to such Revolving Credit Lender’s Pro Rata Percentage of the aggregate amount available to be drawn under such Letter of Credit, effective upon the issuance of such Letter of Credit. In consideration and in furtherance of the foregoing, each Revolving Credit Lender hereby absolutely and unconditionally agrees to pay to the

45

Administrative Agent, for the account of the Issuing Bank, such Lender’s Pro Rata Percentage of each L/C Disbursement made by the Issuing Bank and not reimbursed by the Borrower (or, if applicable, another party pursuant to its obligations under any other Loan Document) forthwith on the date due as provided in Section 2.02(f). Each Revolving Credit Lender acknowledges and agrees that its obligation to acquire participations pursuant to this paragraph in respect of Letters of Credit is absolute and unconditional and shall not be affected by any circumstance whatsoever, including the occurrence and continuance of a Default or an Event of Default, and that each such payment shall be made without any offset, abatement, withholding or reduction whatsoever.

(e) Reimbursement. If the Issuing Bank shall make any L/C Disbursement in respect of a Letter of Credit, the Borrower shall pay to the Administrative Agent an amount equal to such L/C Disbursement not later than two hours after the Borrower shall have received notice from the Issuing Bank that payment of such draft will be made, or, if the Borrower shall have received such notice later than 10:00 a.m., New York City time, on any Business Day, not later than 10:00 a.m., New York City time, on the immediately following Business Day.

(f) Obligations Absolute. The Borrower’s obligations to reimburse L/C Disbursements as provided in paragraph (e) above shall be absolute, unconditional and irrevocable, and shall be performed strictly in accordance with the terms of this Agreement, under any and all circumstances whatsoever, and irrespective of:

(i) any lack of validity or enforceability of any Letter of Credit or any Loan Document, or any term or provision therein;

(ii) any amendment or waiver of or any consent to departure from all or any of the provisions of any Letter of Credit or any Loan Document;

(iii) the existence of any claim, setoff, defense or other right that the Borrower, any other party guaranteeing, or otherwise obligated with, the Borrower, any Subsidiary or other Affiliate thereof or any other person may at any time have against the beneficiary under any Letter of Credit, the Issuing Bank, the Administrative Agent or any Lender or any other person, whether in connection with this Agreement, any other Loan Document or any other related or unrelated agreement or transaction;

(iv) any draft or other document presented under a Letter of Credit proving to be forged, fraudulent, invalid or insufficient in any respect or any statement therein being untrue or inaccurate in any respect;

(v) payment by the Issuing Bank under a Letter of Credit against presentation of a draft or other document that does not comply with the terms of such Letter of Credit; and

(vi) any other act or omission to act or delay of any kind of the Issuing Bank, the Lenders, the Administrative Agent or any other person or any other event or circumstance whatsoever, whether or not similar to any of the foregoing, that might, but for the provisions of this Section, constitute a legal or equitable discharge of the Borrower’s obligations hereunder.

46

Without limiting the generality of the foregoing, it is expressly understood and agreed that the absolute and unconditional obligation of the Borrower hereunder to reimburse L/C Disbursements will not be excused by the gross negligence or wilful misconduct of the Issuing Bank. However, the foregoing shall not be construed to excuse the Issuing Bank from liability to the Borrower to the extent of any direct damages (as opposed to consequential damages, claims in respect of which are hereby waived by the Borrower to the extent permitted by applicable law) suffered by the Borrower that are caused by the Issuing Bank’s gross negligence or wilful misconduct in determining whether drafts and other documents presented under a Letter of Credit comply with the terms thereof. It is further understood and agreed that the Issuing Bank may accept documents that appear on their face to be in order, without responsibility for further investigation, regardless of any notice or information to the contrary and, in making any payment under any Letter of Credit (i) the Issuing Bank’s exclusive reliance on the documents presented to it under such Letter of Credit as to any and all matters set forth therein, including reliance on the amount of any draft presented under such Letter of Credit, whether or not the amount due to the beneficiary thereunder equals the amount of such draft and whether or not any document presented pursuant to such Letter of Credit proves to be insufficient in any respect, if such document on its face appears to be in order, and whether or not any other statement or any other document presented pursuant to such Letter of Credit proves to be forged or invalid or any statement therein proves to be inaccurate or untrue in any respect whatsoever and (ii) any noncompliance in any immaterial respect of the documents presented under such Letter of Credit with the terms thereof shall, in each case, be deemed not to constitute gross negligence or wilful misconduct of the Issuing Bank.

(g) Disbursement Procedures. The Issuing Bank shall, promptly following its receipt thereof, examine all documents purporting to represent a demand for payment under a Letter of Credit. The Issuing Bank shall as promptly as possible give telephonic notification, confirmed by fax, to the Administrative Agent and the Borrower of such demand for payment and whether the Issuing Bank has made or will make an L/C Disbursement thereunder; provided that any failure to give or delay in giving such notice shall not relieve the Borrower of its obligation to reimburse the Issuing Bank and the Revolving Credit Lenders with respect to any such L/C Disbursement.

(h) Interim Interest. If the Issuing Bank shall make any L/C Disbursement in respect of a Letter of Credit, then, unless the Borrower shall reimburse such L/C Disbursement in full on such date, the unpaid amount thereof shall bear interest for the account of the Issuing Bank, for each day from and including the date of such L/C Disbursement to but excluding the earlier of the date of payment by the Borrower or the date on which interest shall commence to accrue thereon as provided in Section 2.02(f), at the rate per annum that would apply to such amount if such amount were an ABR Revolving Loan.

(i) Resignation or Removal of the Issuing Bank. The Issuing Bank may resign at any time by giving 30 days’ prior written notice to the Administrative Agent, the Revolving Credit Lenders and the Borrower, and may be removed at any time by the Borrower by notice to the Issuing Bank, the Administrative Agent and the Revolving Credit Lenders. Upon the acceptance of any appointment as the Issuing Bank hereunder by a Revolving Credit Lender that shall agree to serve as successor Issuing Bank, such successor shall succeed to and become vested with all the interests, rights and obligations of the retiring Issuing Bank. At the time such removal or

47

resignation shall become effective, the Borrower shall pay all accrued and unpaid fees pursuant to Section 2.05(c)(ii). The acceptance of any appointment as the Issuing Bank hereunder by a successor Revolving Credit Lender shall be evidenced by an agreement entered into by such successor, in a form satisfactory to the Borrower and the Administrative Agent, and, from and after the effective date of such agreement, (i) such successor Revolving Credit Lender shall have all the rights and obligations of the previous Issuing Bank under this Agreement and the other Loan Documents and (ii) references herein and in the other Loan Documents to the term “Issuing Bank” shall be deemed to refer to such successor or to any previous Issuing Bank, or to such successor and all previous Issuing Banks, as the context shall require. After the resignation or removal of the Issuing Bank hereunder, the retiring Issuing Bank shall remain a party hereto and shall continue to have all the rights and obligations of an Issuing Bank under this Agreement and the other Loan Documents with respect to Letters of Credit issued by it prior to such resignation or removal, but shall not be required to issue additional Letters of Credit.

(j) Cash Collateralization. If any Event of Default shall occur and be continuing, the Borrower shall, on the Business Day it receives notice from the Administrative Agent or the Required Lenders (or, if the maturity of the Loans has been accelerated, Revolving Credit Lenders holding participations in outstanding Letters of Credit representing greater than 50% of the aggregate undrawn amount of all outstanding Letters of Credit) thereof and of the amount to be deposited, deposit in an account with the Collateral Agent, for the benefit of the Revolving Credit Lenders, an amount in cash equal to the L/C Exposure as of such date. Such deposit shall be held by the Collateral Agent as collateral for the payment and performance of the Obligations. The Collateral Agent shall have exclusive dominion and control, including the exclusive right of withdrawal, over such account. Other than any interest earned on the investment of such deposits in Permitted Investments, which investments shall be made at the option and sole discretion of the Collateral Agent, such deposits shall not bear interest. Interest or profits, if any, on such investments shall accumulate in such account. Moneys in such account shall (i) automatically be applied by the Administrative Agent to reimburse the Issuing Bank for L/C Disbursements for which it has not been reimbursed, (ii) be held for the satisfaction of the reimbursement obligations of the Borrower for the L/C Exposure at such time and (iii) if the maturity of the Loans has been accelerated (but subject to the consent of Revolving Credit Lenders holding participations in outstanding Letters of Credit representing greater than 50% of the aggregate undrawn amount of all outstanding Letters of Credit), be applied to satisfy the Obligations. If the Borrower is required to provide an amount of cash collateral hereunder as a result of the occurrence of an Event of Default, such amount (to the extent not applied as aforesaid) shall be returned to the Borrower within three Business Days after all Events of Default have been cured or waived.

(k) Additional Issuing Banks. The Borrower may, at any time and from time to time with the consent of the Administrative Agent (which consent shall not be unreasonably withheld or delayed) and such Revolving Credit Lender, designate one or more additional Revolving Credit Lenders to act as an issuing bank under the terms of this Agreement. Any Revolving Credit Lender designated as an issuing bank pursuant to this paragraph (k) shall be deemed to be an “Issuing Bank” (in addition to being a Revolving Credit Lender) in respect of Letters of Credit issued or to be issued by such Lender, and, with respect to such Letters of Credit, such term shall thereafter apply to the other Issuing Bank and such Revolving Credit Lender.

48

ARTICLE III

Representations and Warranties

The Borrower represents and warrants to the Administrative Agent, the Collateral Agent, the Issuing Bank and each of the Lenders that:

SECTION 3.01. Organization; Powers. The Borrower and each of the Subsidiaries (a) is duly organized, validly existing and in good standing under the laws of the jurisdiction of its organization, (b) has all requisite power and authority to own its property and assets and to carry on its business as now conducted and as proposed to be conducted, (c) is qualified to do business in, and is in good standing in, every jurisdiction where such qualification is required, except where the failure so to qualify could not reasonably be expected to result in a Material Adverse Effect, and (d) has the power and authority to execute, deliver and perform its obligations under each of the Loan Documents and each other agreement or instrument contemplated hereby or thereby to which it is or will be a party and, in the case of the Borrower, to borrow hereunder.

SECTION 3.02. Authorization. The Transactions (a) have been duly authorized by all requisite corporate and, if required, stockholder action and (b) will not (i) violate (A) any provision of law, statute, rule or regulation, or of the certificate or articles of incorporation or other constitutive documents or by-laws of the Borrower or any Subsidiary, (B) any order of any Governmental Authority or (C) any provision of any indenture, agreement or other instrument to which the Borrower or any Subsidiary is a party or by which any of them or any of their property is or may be bound, (ii) be in conflict with, result in a breach of or constitute (alone or with notice or lapse of time or both) a default under, or give rise to any right to accelerate or to require the prepayment, repurchase or redemption of any obligation under any such indenture, agreement or other instrument or (iii) result in the creation or imposition of any Lien upon or with respect to any property or assets now owned or hereafter acquired by the Borrower or any Subsidiary (other than any Lien created hereunder or under the Security Documents).

SECTION 3.03. Enforceability. The Amendment Agreement has been duly executed and delivered by the Borrower and each Subsidiary Guarantor and constitutes, and this Agreement constitutes, and each other Loan Document when executed and delivered by each Loan Party party thereto will constitute, a legal, valid and binding obligation of such Loan Party enforceable against such Loan Party in accordance with its terms.

SECTION 3.04. Governmental Approvals. No action, consent or approval of, registration or filing with or any other action by any Governmental Authority is or will be required in connection with the Transactions, except for (a) the filing of Uniform Commercial Code financing statements and filings with the United States Patent and Trademark Office and the United States Copyright Office, (b) the recordation of the Mortgages, (c) such as have been made or obtained and are in full force and effect and (d) filings required by the Securities Exchange Act of 1934, as amended.

SECTION 3.05. Financial Statements. The Borrower has heretofore furnished to the Lenders its consolidated balance sheets and related statements of income, shareholders’ equity

49

and cash flows as of and for the fiscal year ended December 31, 2005, audited by and accompanied by the unqualified opinion of Deloitte & Touche LLP, independent public accountants. Such financial statements present fairly the financial condition and results of operations and cash flows of the Borrower and its consolidated Subsidiaries as of such dates and for such periods. Such balance sheets and the notes thereto disclose all material liabilities, direct or contingent, of the Borrower and its consolidated Subsidiaries as of the dates thereof. Such financial statements were prepared in accordance with GAAP applied on a consistent basis.

SECTION 3.06. No Material Adverse Change. No event, change or condition has occurred that has had, or could reasonably be expected to have, a material adverse effect on the business, assets, operations or condition (financial or otherwise) of the Borrower and the Subsidiaries, taken as a whole, since December 31, 2005.

SECTION 3.07. Title to Properties; Possession Under Leases. (a) Other than the Oil and Gas Properties (which are the subject of paragraph (b) below), the Borrower and each of the Subsidiaries has good and marketable title to, or valid leasehold interests in, all its material properties and assets, except for minor defects in title that do not interfere with its ability to conduct its business as currently conducted or to utilize such properties and assets for their intended purposes. All such material properties and assets are free and clear of Liens, other than Liens expressly permitted by Section 6.02.

(b) The Borrower and each of the Subsidiaries has good and marketable title to all of the Oil and Gas Properties included in the most recent Reserve Report delivered pursuant to 5.04(d) free from all Liens, claims and title imperfections, except for (i) such imperfections of title as do not in the aggregate detract from the value thereof to, or the use thereof in, the business of the Borrower or any of its Subsidiaries in any material respect, (ii) Oil and Gas Properties disposed of since the date of the most recent Reserve Report as permitted by Section 6.05, and (iii) Liens expressly permitted by Section 6.02. The quantum and nature of the interest of the Borrower and the Subsidiaries in and to the Oil and Gas Properties as set forth in each Reserve Report includes or will include the entire interest of the Borrower and the Subsidiaries in such Oil and Gas Properties as of the date of such Reserve Report and are or will be complete and accurate in all material respects as of the date of such Reserve Report; and there are no “back-in” or “reversionary” interests held by third parties which could reduce the interest of the Borrower and the Subsidiaries in such Oil and Gas Properties in any material respect, except as expressly set forth or given effect to in such Reserve Report.

(c) Each of the Borrower and each of the Subsidiaries has complied with all obligations under all licenses, leases and term mineral interests in the Oil and Gas Properties and all such licenses, leases and term mineral interests are valid, subsisting and in full force and effect, and neither the Borrower nor any of the Subsidiaries has knowledge that a default exists under any of the terms or provisions, express or implied, of any of such licenses, leases or interests or under any agreement to which the same are subject, except to the extent any inaccuracy in the foregoing could not reasonably be expected to result in a Material Adverse Effect. All of the Oil and Gas Contracts and obligations of the Borrower and the Subsidiaries that relate to the Oil and Gas Properties are in full force and effect and constitute legal, valid and binding obligations of the Borrower and the Subsidiaries party thereto, except to the extent any inaccuracy in the foregoing could not reasonably be expected to result in a Material Adverse Effect. None of the

50

Borrower or any of the Subsidiaries or, to the knowledge of the Borrower and the Subsidiaries, any other party to any licenses, leases or term mineral interests in the Oil and Gas Properties or any Oil and Gas Contract (i) is in breach of or default, or with the lapse of time or the giving of notice, or both, would be in breach or default, with respect to any obligations thereunder, whether express or implied, except such that could not reasonably be expected to result in a Material Adverse Effect or (ii) has given or threatened to give notice of any default under or inquiry into any possible default under, or action to alter, terminate, rescind or procure a judicial reformation of, any licenses or lease in the Oil and Gas Properties or any Oil and Gas Contract. Each of the Borrower and each of the Subsidiaries enjoys peaceful and undisturbed possession under all such licenses, leases and term mineral interests.

(d) The Borrower has not received any notice of, nor has any knowledge of, any pending or contemplated condemnation proceeding affecting the Mortgaged Properties or any sale or disposition thereof in lieu of condemnation.

(e) Neither the Borrower nor any of the Subsidiaries is obligated under any right of first refusal, option or other contractual right to sell, assign or otherwise dispose of any Mortgaged Property or any interest therein.

SECTION 3.08. Subsidiaries. Schedule 3.08 sets forth as of the Prior Restatement Date a list of all Subsidiaries and the percentage ownership interest of the Borrower therein. The shares of capital stock or other ownership interests so indicated on Schedule 3.08 are fully paid and non-assessable and are owned by the Borrower, directly or indirectly, free and clear of all Liens (other than Liens created under the Security Documents).

SECTION 3.09. Litigation; Compliance with Laws. (a) Except as set forth on Schedule 3.09, there are not any actions, suits or proceedings at law or in equity or by or before any Governmental Authority now pending or, to the knowledge of the Borrower, threatened against or affecting the Borrower, any Subsidiary or any business, property or rights of any such person (i) that involve any Loan Document or the Transactions or (ii) as to which there is a reasonable possibility of an adverse determination and that, if adversely determined, could reasonably be expected, individually or in the aggregate, to result in a Material Adverse Effect.

(b) Neither of the Borrower nor any of the Subsidiaries or any of their respective material properties or assets is in violation of, nor will the continued operation of their material properties and assets as currently conducted violate, any law, rule or regulation applicable to the Oil and Gas Business or any other applicable law, rule or regulation (including any zoning, building, Environmental Law, ordinance, code or approval or any building permits) or any restrictions of record or agreements affecting any Mortgaged Property, or is in default with respect to any judgment, writ, injunction, decree or order of any Governmental Authority, where such violation or default could reasonably be expected to result in a Material Adverse Effect.

SECTION 3.10. Agreements. (a) Except as set forth on Schedule 3.10, none of the Borrower or any of the Subsidiaries is a party to any agreement or instrument or subject to any corporate restriction that has resulted or could reasonably be expected to result in a Material Adverse Effect.

51

(b) Except as set forth on Schedule 3.10, none of the Borrower or any of the Subsidiaries is in default in any manner under any provision of any indenture or other agreement or instrument evidencing Indebtedness, or any other material agreement or instrument to which it is a party or by which it or any of its properties or assets are or may be bound, where such default could reasonably be expected to result in a Material Adverse Effect.

SECTION 3.11. Federal Reserve Regulations. (a) None of the Borrower or any of the Subsidiaries is engaged principally, or as one of its important activities, in the business of extending credit for the purpose of buying or carrying Margin Stock.

(b) No part of the proceeds of any Loan or any Letter of Credit will be used, whether directly or indirectly, and whether immediately, incidentally or ultimately, for any purpose that entails a violation of, or that is inconsistent with, the provisions of the Regulations of the Board, including Regulation T, U or X.

SECTION 3.12. Investment Company Act. None of the Borrower or any Subsidiary is an “investment company” as defined in, or subject to regulation under, the Investment Company Act of 1940.

SECTION 3.13. Use of Proceeds. The Borrower will use the proceeds of the Loans and will request the issuance of Letters of Credit only for the purposes specified in the preliminary statement to this Agreement.

SECTION 3.14. Tax Returns. Each of the Borrower and each of the Subsidiaries has filed or caused to be filed all Federal, state, local and foreign tax returns or materials required to have been filed by it and has paid or caused to be paid all taxes due and payable by it and all assessments received by it, except taxes that are being contested in good faith by appropriate proceedings and for which the Borrower or such Subsidiary, as applicable, shall have set aside on its books adequate reserves.

SECTION 3.15. No Material Misstatements. None of (a) the Confidential Information Memorandum or (b) any other information, report, financial statement, exhibit or schedule furnished by or on behalf of the Borrower to the Administrative Agent or any Lender in connection with the negotiation of any Loan Document or included therein or delivered pursuant thereto contained, contains or will contain any material misstatement of fact or omitted, omits or will omit to state any material fact necessary to make the statements therein, in the light of the circumstances under which they were, are or will be made, not misleading; provided that to the extent any such information, report, financial statement, exhibit or schedule was based upon or constitutes a forecast or projection, the Borrower represents only that it acted in good faith and utilized reasonable assumptions and due care in the preparation of such information, report, financial statement, exhibit or schedule.

SECTION 3.16. Employee Benefit Plans. Each of the Borrower and each of its ERISA Affiliates is in compliance in all material respects with the applicable provisions of ERISA and the Code and the regulations and published interpretations thereunder. No ERISA Event has occurred or is reasonably expected to occur that, when taken together with all other such ERISA Events, could reasonably be expected to result in material liability of the Borrower or any of its

52

ERISA Affiliates. The present value of all benefit liabilities under each Plan (based on the assumptions used for purposes of Statement of Financial Accounting Standards No. 87) did not, as of the last annual valuation date applicable thereto, exceed the fair market value of the assets of such Plan by an amount that is material, and the present value of all benefit liabilities of all underfunded Plans (based on the assumptions used to fund such plan) did not, as of the last annual valuation dates applicable thereto, exceed the fair market value of the assets of all such underfunded Plans by an amount that is material.

SECTION 3.17. Environmental Matters. Except as set forth in Schedule 3.17 and except with respect to any other matters that, individually or in the aggregate, could not reasonably be expected to result in a Material Adverse Effect, none of the Borrower or any of the Subsidiaries (i) has failed to comply with any Environmental Law or to obtain, maintain or comply with any permit, license or other approval required under any Environmental Law, (ii) has become subject to any Environmental Liability, (iii) has received notice of any claim with respect to any Environmental Liability or (iv) knows of any basis for any Environmental Liability on its part.

SECTION 3.18. Insurance. Schedule 3.18 sets forth a true, complete and correct description of all insurance maintained by the Borrower or by the Borrower for its Subsidiaries as of the Prior Restatement Date. As of such date, such insurance is in full force and effect and all premiums have been duly paid. The Borrower and its Subsidiaries have insurance in such amounts and covering such risks and liabilities as are in accordance with normal industry practice.

SECTION 3.19. Security Documents. (a) The Guarantee and Collateral Agreement creates in favor of the Collateral Agent, for the ratable benefit of the Secured Parties, a legal, valid and enforceable security interest in the Collateral (as defined in the Guarantee and Collateral Agreement) and the proceeds thereof and (i) with respect to all Pledged Collateral (as defined in the Guarantee and Collateral Agreement) previously delivered to and in possession of the Collateral Agent, the Guarantee and Collateral Agreement constitutes, or in the case of Pledged Collateral to be delivered to the Collateral Agent in the future, the Guarantee and Collateral Agreement will constitute, a fully perfected first priority Lien on, and security interest in, all right, title and interest of the Loan Parties in such Pledged Collateral, in each case prior and superior in right to any other person, and (ii) together with the financing statements previously filed in the offices specified on Schedule 3.19(a), the Lien created under the Guarantee and Collateral Agreement constitutes a fully perfected Lien on, and security interest in, all right, title and interest of the Loan Parties in such Collateral (other than Intellectual Property, as defined in the Guarantee and Collateral Agreement), in each case prior and superior in right to any other person, other than with respect to Liens expressly permitted by Section 6.02.

(b) The filing made pursuant to the Guarantee and Collateral Agreement currently on file with the United States Patent and Trademark Office, together with the financing statements previously filed in the offices specified on Schedule 3.19(a), constitutes a fully perfected Lien on, and security interest in, all right, title and interest of the Loan Parties in the Intellectual Property (as defined in the Guarantee and Collateral Agreement) in which a security interest may be perfected by filing in the United States and its territories and possessions, in each case prior and superior in right to any other person (it being understood that subsequent recordings in the United States Patent and Trademark Office and the United States Copyright Office may be necessary to perfect a Lien on registered trademarks, trademark applications and copyrights acquired by the Loan Parties after the date hereof).

53

(c) The Mortgages are effective to create in favor of the Collateral Agent, for the ratable benefit of the Secured Parties, a legal, valid and enforceable Lien on all of the Loan Parties’ right, title and interest in and to the Mortgaged Property thereunder and the proceeds thereof, and when the modifications to the Mortgages referred to in Section 3.04(a) are recorded in the offices specified on Schedule 3.19(c), the Mortgages shall constitute a fully perfected Lien on, and security interest in, all right, title and interest of the Loan Parties in such Mortgaged Property and the proceeds thereof, in each case prior and superior in right to any other person, other than with respect to the rights of persons pursuant to Liens expressly permitted by Section 6.02.

(d) The Foreign Pledge Agreements are effective to create in favor of the Collateral Agent, for the ratable benefit of the Secured Parties, a legal, valid and enforceable security interest in the Foreign Pledged Collateral described therein and the proceeds thereof and when the Foreign Pledge Agreements are filed in the offices specified on Schedule 3.19(d), or other appropriate instruments are filed or other actions are taken, all as described on Schedule 3.19(d), the Foreign Pledge Agreements shall provide for a fully perfected first priority Lien on, and security interest in, all right, title and interest of the Loan Parties in the Foreign Pledged Collateral, in each case prior and superior in right to any other person, other than with respect to Liens expressly permitted by Section 6.02.

SECTION 3.20. Location of Oil and Gas Properties, Real Property and Leased Premises. (a) Schedule 3.20(a) lists completely and correctly as of the Prior Restatement Date all Oil and Gas Properties of the Borrower and the Subsidiaries and the location and a property description thereof.

(b) Schedule 3.20(b) lists completely and correctly as of the Prior Restatement Date all real property (other than Oil and Gas Properties) owned by the Borrower and the Subsidiaries and the addresses thereof. The Borrower and the Subsidiaries own in fee all the real property set forth on Schedule 3.20(b).

(c) Schedule 3.20(c) lists completely and correctly as of the Prior Restatement Date all real property (other than Oil and Gas Properties) leased by the Borrower and the Subsidiaries and the addresses thereof. The Borrower and the Subsidiaries have valid leasehold interests in all the real property set forth on Schedule 3.20(c).

SECTION 3.21. Future Commitments. As of the Restatement Date, on a net basis there are no material gas imbalances, take-or-pay or other prepayments with respect to any Oil and Gas Property of the Borrower or any Subsidiary that would require the Borrower or any Subsidiary to deliver Hydrocarbons produced from Oil and Gas Properties at some future time without then or thereafter receiving full payment therefor.

SECTION 3.22. Labor Matters. As of the Restatement Date, there are no strikes, lockouts or slowdowns against the Borrower or any Subsidiary pending or, to the knowledge of the Borrower, threatened. The hours worked by and payments made to employees of the Borrower and the Subsidiaries have not been in violation in any material respect of the Fair

54

Labor Standards Act or any other applicable Federal, state, local or foreign law dealing with such matters. All payments due from the Borrower or any Subsidiary, or for which any claim may be made against the Borrower or any Subsidiary, on account of wages and employee health and welfare insurance and other benefits, have been paid or accrued as a liability on the books of the Borrower or such Subsidiary. The consummation of the Transactions will not give rise to any right of termination or right of renegotiation on the part of any union under any collective bargaining agreement to which the Borrower or any Subsidiary is bound.

SECTION 3.23. Solvency. Immediately after the consummation of the Transactions to occur on the Restatement Date and immediately following the making of each Loan and after giving effect to the application of the proceeds of each Loan, (a) the fair value of the assets of the Loan Parties, taken as a whole, at a fair valuation, will exceed their debts and liabilities, subordinated, contingent or otherwise, taken as a whole; (b) the present fair saleable value of the property of the Loan Parties will be greater than the amount that will be required to pay the probable liability of their debts and other liabilities, subordinated, contingent or otherwise, as such debts and other liabilities become absolute and matured; (c) the Loan Parties taken as a whole will be able to pay their debts and liabilities, subordinated, contingent or otherwise, as such debts and liabilities become absolute and matured; and (d) the Loan Parties will not have unreasonably small capital with which to conduct the business in which they are engaged as such businesses are now conducted and are proposed to be conducted following the Restatement Date.

ARTICLE IV

Conditions of Lending

The obligations of the Lenders to make Loans and of the Issuing Bank to issue Letters of Credit hereunder are subject to the satisfaction of the following conditions:

On the date of each Borrowing (other than a conversion or a continuation of a Borrowing), including on the date of each issuance, amendment, extension or renewal of a Letter of Credit (each such event being called a “Credit Event”):

(a) The Administrative Agent shall have received a notice of such Borrowing as required by Section 2.03 (or such notice shall have been deemed given in accordance with Section 2.02) or, in the case of the issuance, amendment, extension or renewal of a Letter of Credit, the Issuing Bank and the Administrative Agent shall have received a notice requesting the issuance, amendment, extension or renewal of such Letter of Credit as required by Section 2.23(b).

(b) The representations and warranties set forth in Article III hereof and in each other Loan Document shall be true and correct in all material respects on and as of the date of such Credit Event with the same effect as though made on and as of such date, except to the extent such representations and warranties expressly relate to an earlier date.

(c) The Borrower and each other Loan Party shall be in compliance with all the terms and provisions set forth herein and in each other Loan Document on its part to be observed or performed at or prior to the time of such Borrowing, and at the time of and immediately after such Credit Event, no Event of Default or Default shall have occurred and be continuing.

55

Each Credit Event shall be deemed to constitute a representation and warranty by the Borrower on the date of such Credit Event as to the matters specified in paragraphs (b) and (c) of this Article IV.

ARTICLE V

Affirmative Covenants

The Borrower covenants and agrees with each Lender that so long as this Agreement shall remain in effect and until the Commitments have been terminated and the principal of and interest on each Loan and all Fees and all other expenses or amounts payable under any Loan Document shall have been paid in full and all Letters of Credit have been cancelled or have expired and all amounts drawn thereunder have been reimbursed in full, unless the Required Lenders shall otherwise consent in writing, the Borrower will, and will cause each of the Subsidiaries to:

SECTION 5.01. Existence; Businesses; Oil and Gas Properties. (a) Do or cause to be done all things necessary to preserve, renew and keep in full force and effect its legal existence, except as otherwise expressly permitted under Section 6.05.

(b) Do or cause to be done all things necessary to obtain, preserve, renew, extend and keep in full force and effect the rights, licenses, permits, franchises, authorizations, patents, copyrights, trademarks and trade names material to the conduct of its business; maintain and operate such business in substantially the manner in which it is currently conducted and operated; comply in all material respects with all applicable laws, rules, regulations and decrees and orders of any Governmental Authority, whether now in effect or hereafter enacted; and at all times maintain and preserve all property material to the conduct of such business and keep such property in good repair, working order and condition and from time to time make, or cause to be made, all needful and proper repairs, renewals, additions, improvements and replacements thereto necessary in order that the business carried on in connection therewith may be properly conducted at all times.

(c) Comply in all material respects with the terms and provisions of all oil and gas leases and licenses relating to the Oil and Gas Properties of the Borrower and the Subsidiaries and all contracts and agreements relating thereto or to the production and sale of Hydrocarbons therefrom; and with respect to any such Oil and Gas Properties or oil and gas gathering assets that are operated by operators other than the Borrower or a Subsidiary, use all commercially reasonable efforts to enforce in a manner consistent with industry practice the operator’s contractual obligations to maintain, develop, and operate such Oil and Gas Properties and oil and gas gathering assets in accordance with the applicable operating agreements.

SECTION 5.02. Insurance. (a) Keep its insurable properties adequately insured at all times by financially sound and reputable insurers; maintain such other insurance, to such extent and against such risks, including fire and other risks insured against by extended coverage, as is customary with companies in the same or similar businesses operating in the same or similar locations, including public liability insurance against claims for personal injury or death or property damage occurring upon, in, about or in connection with the use of any properties owned, occupied or controlled by it; and maintain such other insurance as may be required by law.

56

(b) Cause all such policies covering any Collateral to be endorsed or otherwise amended to include a customary lender’s loss payable endorsement, in form and substance satisfactory to the Administrative Agent and the Collateral Agent, which endorsement shall provide that, from and after the Original Closing Date, if the insurance carrier shall have received written notice from the Administrative Agent or the Collateral Agent of the occurrence of an Event of Default, the insurance carrier shall pay all proceeds otherwise payable to the Borrower or the Loan Parties under such policies directly to the Collateral Agent; cause all such policies to provide that neither the Borrower, the Administrative Agent, the Collateral Agent nor any other party shall be a coinsurer thereunder and to contain a “Replacement Cost Endorsement”, without any deduction for depreciation, and such other provisions as the Administrative Agent or the Collateral Agent may reasonably require from time to time to protect their interests; deliver original or certified copies of all such policies or certificates evidencing such policies to the Collateral Agent; cause each such policy to provide that it shall not be canceled, modified or not renewed (i) by reason of nonpayment of premium upon not less than 10 days’ prior written notice thereof by the insurer to the Administrative Agent and the Collateral Agent (giving the Administrative Agent and the Collateral Agent the right to cure defaults in the payment of premiums) or (ii) for any other reason upon not less than 30 days’ prior written notice thereof by the insurer to the Administrative Agent and the Collateral Agent; deliver to the Administrative Agent and the Collateral Agent, prior to the cancellation, modification or nonrenewal of any such policy of insurance, a copy of a renewal or replacement policy (or other evidence of renewal of a relevant policy) together with evidence satisfactory to the Administrative Agent and the Collateral Agent of payment of the premium therefor.

(c) With respect to any Mortgaged Property, carry and maintain comprehensive general liability insurance including the “broad form” commercial general liability endorsement and coverage on an occurrence basis against claims made for personal injury (including bodily injury, death and property damage) and umbrella liability insurance against any and all claims, in no event for a combined single limit of less than $10,000,000, naming the Collateral Agent as an additional insured, on forms satisfactory to the Collateral Agent.

(d) Notify the Administrative Agent and the Collateral Agent immediately whenever any separate insurance concurrent in form or contributing in the event of loss with that required to be maintained under this Section 5.02 is taken out by the Borrower; and promptly deliver to the Administrative Agent and the Collateral Agent a duplicate original copy of such policy or policies or certificates evidencing such policy or policies.

SECTION 5.03. Obligations and Taxes. Pay its Indebtedness and other obligations promptly and in accordance with their terms and pay and discharge promptly when due all taxes, assessments and governmental charges or levies imposed upon it or upon its income or profits or in respect of its property, before the same shall become delinquent or in default, as well as all lawful claims for labor, materials and supplies or otherwise that, if unpaid, might give rise to a Lien upon such properties or any part thereof; provided, however, that such payment and discharge shall not be required with respect to any such tax, assessment, charge, levy or claim so long as the validity or amount thereof shall be contested in good faith by appropriate proceedings

57

and the Borrower shall have set aside on its books adequate reserves with respect thereto in accordance with GAAP and such contest operates to suspend collection of the contested obligation, tax, assessment or charge and enforcement of a Lien (or, in the case of an involuntary Lien of the type described in Section 6.02(e), such Lien remains in effect and unreleased for no more than 30 days after the date it is imposed) and, in the case of a Mortgaged Property, there is no risk of forfeiture of such property.

SECTION 5.04. Financial Statements, Reserve Reports, etc. In the case of the Borrower, furnish to the Administrative Agent:

(a) within 95 days after the end of each fiscal year, its consolidated balance sheet and related statements of income, stockholders’ equity and cash flows showing the financial condition of the Borrower and its consolidated Subsidiaries as of the close of such fiscal year and the results of its operations and the operations of such Subsidiaries during such year, together with comparative figures for the immediately preceding fiscal year, all audited by Deloitte & Touche LLP or other independent public accountants of recognized national standing and accompanied by an opinion of such accountants (which opinion shall be without a “going concern” or like qualification or exception and without any qualification or exception as to the scope of such audit) to the effect that such consolidated financial statements fairly present the financial condition and results of operations of the Borrower and its consolidated Subsidiaries on a consolidated basis in accordance with GAAP consistently applied;

(b) within 50 days after the end of each of the first three fiscal quarters of each fiscal year, its consolidated balance sheet and related statements of income, stockholders’ equity and cash flows showing the financial condition of the Borrower and its consolidated Subsidiaries as of the close of such fiscal quarter and the results of its operations and the operations of such Subsidiaries during such fiscal quarter and the then elapsed portion of the fiscal year, and comparative figures for the same periods in the immediately preceding fiscal year, all certified by one of its Financial Officers as fairly presenting the financial condition and results of operations of the Borrower and its consolidated Subsidiaries on a consolidated basis in accordance with GAAP consistently applied, subject to normal year-end audit adjustments;

(c) concurrently with any delivery of financial statements under paragraph (a) or (b) above, a certificate of the chief financial officer of the Borrower (i) certifying that no Event of Default or Default has occurred or, if such an Event of Default or Default has occurred, specifying the nature and extent thereof and any corrective action taken or proposed to be taken with respect thereto, (ii) describing the material terms of (x) any Asset Sales and (y) any sales, transfers or other dispositions of the nature described in clause (y) to the proviso in the definition of the term “Asset Sale”, in each case, that occurred during the preceding quarter (including, as applicable, the nature of the assets sold, the sale price and Net Cash Proceeds therefrom and the amount of proceeds from all Asset Sales during such period that have been reinvested or that are awaiting reinvestment in accordance with the definition of the term “Net Cash Proceeds”) and (iii) setting forth computations in reasonable detail satisfactory to the Administrative Agent demonstrating compliance with the covenants contained in Sections 6.12, 6.13, 6.14 and 6.15 and, in the case of a certificate delivered with the financial statements required by paragraph (a) above, setting forth the Borrower’s calculation of Excess Cash Flow;

58

(d) prior to or concurrently with any delivery of financial statements under paragraph (a) or (b) above, a Reserve Report (which shall be (i) an annual Reserve Report (as described in the definition of such term) in the case of a Reserve Report delivered in connection with annual financial statements or (ii) a semi-annual Reserve Report (as so described) in the case of a Reserve Report delivered in connection with quarterly financial statements for the fiscal quarter ended June 30) setting forth, among other things, (i) the Oil and Gas Properties owned by the Borrower and the Subsidiaries and covered by such Reserve Report, (ii) the Proved Reserves and probable reserves attributable to such Oil and Gas Properties and (iii) a projection of the rate of production and net income of such Proved Reserves and probable reserves as of the date as of which the information set forth in such Reserve Report is provided, all in accordance with the guidelines published by the Securities and Exchange Commission (but utilizing the pricing parameters set forth in the definition of the term PV-10 Value (and, in the case of an annual Reserve Report, in addition to such pricing parameters those specified in such Securities and Exchange Commission guidelines)) and utilizing such operating cost and other assumptions as proposed by the Company and agreed to by the Administrative Agent (or, if no such agreement is reached, such cost and other assumptions as the Administrative Agent shall from time to time specify);

(e) concurrently with the delivery of each Reserve Report under paragraph (d) above, a certificate of a Responsible Officer showing any additions to or deletions from the Oil and Gas Properties made by the Borrower and the Subsidiaries since the date of the most recently delivered previous Reserve Report;

(f) at least 30 days prior to the commencement of each fiscal year of the Borrower, a detailed consolidated budget for such fiscal year (including a projected consolidated balance sheet and related statements of projected operations and cash flows as of the end of and for such fiscal year and setting forth the assumptions used for purposes of preparing such budget) and, promptly when available, any significant revisions of such budget;

(g) concurrently with any delivery of financial statements under paragraph (a) or (b) above, copies of all periodic and other reports, proxy statements and other materials filed by the Borrower or any Subsidiary with the Securities and Exchange Commission, or any Governmental Authority succeeding to any or all of the functions of said Commission, or with any national securities exchange, or distributed to its shareholders, as the case may be (it being understood and agreed that the Borrower shall notify the Administrative Agent of the filing of any such periodic report on Form 8-K that the Borrower determines in good faith relates to a matter that is or may be material to the interests of the Lenders promptly after the same becomes publicly available);

(h) promptly after the receipt thereof by the Borrower or any Subsidiary, a copy of any “management letter” (whether in final or draft form) received by any such person from its certified public accountants and the management’s response thereto;

59

(i) promptly after the request by any Lender, all documentation and other information that such Lender reasonably requests in order to comply with its ongoing obligations under applicable “know your customer” and anti-money laundering rules and regulations, including the USA Patriot Act; and

(j) promptly, from time to time, such other information regarding the operations, business affairs and financial condition of the Borrower or any Subsidiary, or compliance with the terms of any Loan Document, as the Administrative Agent or any Lender may reasonably request.

SECTION 5.05. Litigation and Other Notices. Furnish to the Administrative Agent and the Issuing Bank prompt written notice of the following:

(a) any Event of Default or Default, specifying the nature and extent thereof and the corrective action (if any) taken or proposed to be taken with respect thereto;

(b) the filing or commencement of, or any threat or notice of intention of any person to file or commence, any action, suit or proceeding, whether at law or in equity or by or before any Governmental Authority, against the Borrower or any Affiliate thereof that could reasonably be expected to result in a Material Adverse Effect;

(c) the occurrence of any ERISA Event that, alone or together with any other ERISA Events that have occurred, could reasonably be expected to result in liability of the Borrower and the Subsidiaries in an aggregate amount exceeding $2,500,000; and

(d) any development that has resulted in, or could reasonably be expected to result in, a Material Adverse Effect.

SECTION 5.06. Information Regarding Collateral. (a) Furnish to the Administrative Agent prompt written notice of any change (i) in any Loan Party’s corporate name, (ii) in the jurisdiction of organization or formation of any Loan Party, (iii) in any Loan Party’s identity or corporate structure or (iv) in any Loan Party’s Federal Taxpayer Identification Number. The Borrower agrees not to effect or permit any change referred to in the preceding sentence unless all filings have been made under the Uniform Commercial Code or otherwise that are required in order for the Collateral Agent to continue at all times following such change to have a valid, legal and perfected security interest in all the Collateral. The Borrower also agrees promptly to notify the Administrative Agent if any material portion of the Collateral is damaged or destroyed.

(b) In the case of the Borrower, each year, at the time of delivery of the annual financial statements with respect to the preceding fiscal year pursuant to Section 5.04(a), deliver to the Administrative Agent a certificate of a Financial Officer setting forth the information required pursuant to Section 2 of the Perfection Certificate or confirming that there has been no change in such information since the date of the Perfection Certificate delivered on the Original Closing Date or the date of the most recent certificate delivered pursuant to this Section 5.06.

SECTION 5.07. Maintaining Records; Access to Properties and Inspections. Keep proper books of record and account in which full, true and correct entries in conformity with

60

GAAP and all requirements of law are made of all dealings and transactions in relation to its business and activities. The Borrower will, and will cause each of the Subsidiaries to, permit any representatives designated by the Administrative Agent or any Lender to visit and inspect the financial records and the properties of any such person at reasonable times and as often as reasonably requested and to make extracts from and copies of such financial records, and permit any representatives designated by the Administrative Agent or any Lender to discuss the affairs, finances and condition of any such person with the officers thereof and independent accountants therefor.

SECTION 5.08. Use of Proceeds. Use the proceeds of the Loans and request the issuance of Letters of Credit only for the purposes specified in the preliminary statement to this Agreement and, together with the proceeds of the Second Lien Facility Documents, to repurchase, redeem or otherwise refinance the Existing Preferred Stock.

SECTION 5.09. Further Assurances. (a) Execute any and all further documents, financing statements, agreements and instruments, and take all further action (including filing Uniform Commercial Code and other financing statements, mortgages and deeds of trust) that may be required under applicable law, or that the Required Lenders, the Administrative Agent or the Collateral Agent may reasonably request, in order to effectuate the transactions contemplated by the Loan Documents and in order to grant, preserve, protect and perfect the validity and first priority (subject only to Liens permitted by Section 6.02) of the Liens created or intended to be created by the Security Documents. The Borrower will cause any subsequently acquired or organized Domestic Subsidiary to become a Loan Party by executing the Guarantee and Collateral Agreement and each other applicable Security Document in favor of the Collateral Agent. In addition, from time to time, the Borrower will, at its cost and expense, promptly secure the Obligations by pledging or creating, or causing to be pledged or created, first priority perfected Liens with respect to such of its assets and properties as the Administrative Agent or the Required Lenders shall designate (it being understood that it is the intent of the parties that the Obligations shall be secured on a first priority basis by substantially all the assets of the Borrower and its Domestic Subsidiaries (including Oil and Gas Properties and other real and other properties acquired subsequent to the Original Closing Date)). Such security interests and Liens will be created under the Security Documents and other security agreements, mortgages, deeds of trust and other instruments and documents in form and substance satisfactory to the Collateral Agent, and the Borrower shall deliver or cause to be delivered to the Collateral Agent all such instruments and documents (including legal opinions, title insurance policies and lien searches) as the Collateral Agent shall reasonably request to evidence compliance with this Section 5.09. The Borrower agrees to provide such evidence as the Collateral Agent shall reasonably request as to the perfection and priority status of each such security interest and Lien. In furtherance of the foregoing, the Borrower will give notice to the Administrative Agent concurrently with any delivery of financial statements under Section 5.04(a) or (b) of the acquisition by it or any of the Domestic Subsidiaries of any Oil and Gas Property or real property (or any interest in any Oil and Gas Property or real property) having a value in excess of $1,000,000. It is understood and agreed that, notwithstanding anything to the contrary in the foregoing, the Borrower and the Domestic Subsidiaries will not be required to grant a security interest in or mortgage on any Oil and Gas Property under this paragraph (a) that would not otherwise be required under paragraph (c) of this Section 5.09.

61

(b) Within 60 days after the making of a request therefor by the Administrative Agent, furnish such title opinions and/or title information as may be necessary to achieve title opinion/title information coverage with respect to Oil and Gas Properties representing in the aggregate not less than 90% of PV-10 Value as set forth in the Reserve Report most recently delivered pursuant to Section 5.04(d) prior to the making of such request.

(c) Regularly monitor engineering data covering all Oil and Gas Properties of the Borrower and the Domestic Subsidiaries and mortgage or cause to be mortgaged such of the same to the Collateral Agent on behalf of the Secured Parties pursuant to a Mortgage to the extent necessary to ensure that the Obligations shall at all times be secured by first priority perfected Liens and security interests in each Domestic Oil and Gas Property having an individual value of $25,000,000 or more (on a contribution to PV-10 Value basis) and Domestic Oil and Gas Properties in the aggregate representing not less than 90% of the aggregate PV-10 Value attributable to all Domestic Oil and Gas Properties.

SECTION 5.10. Commodity Hedging Agreements. Maintain in effect Commodity Hedging Agreements with one or more Approved Counterparties that establish minimum prices reasonably acceptable to the Administrative Agent on a volume of Hydrocarbons equal to not less than 40% of the projected PDP production (measured as of each date of delivery to the Administrative Agent of the financial statements and certificates required by Section 5.04(a) or (b) and Section 5.04(c), respectively) from the Oil and Gas Properties of the Borrower and the Subsidiaries for the succeeding twelve calendar months on a rolling twelve calendar month basis.

ARTICLE VI

Negative Covenants

The Borrower covenants and agrees with each Lender that, so long as this Agreement shall remain in effect and until the Commitments have been terminated and the principal of and interest on each Loan and all Fees and all other expenses or amounts payable under any Loan Document have been paid in full and all Letters of Credit have been cancelled or have expired and all amounts drawn thereunder have been reimbursed in full, unless the Required Lenders shall otherwise consent in writing, the Borrower will not, nor will it cause or permit any of the Subsidiaries to:

SECTION 6.01. Indebtedness. Incur, create, assume or permit to exist any Indebtedness, except:

(a) Indebtedness existing on the Prior Restatement Date and set forth in Schedule 6.01;

(b) Indebtedness created hereunder and under the other Loan Documents;

(c) intercompany Indebtedness of the Borrower and the Subsidiaries to the extent permitted by Section 6.04(c);

(d) Indebtedness of the Borrower or any Subsidiary incurred to finance the acquisition, construction or improvement of any fixed or capital assets, and extensions,

62

renewals and replacements of any such Indebtedness that do not increase the outstanding principal amount thereof; provided that (i) such Indebtedness is incurred prior to or within 90 days after such acquisition or the completion of such construction or improvement and (ii) the aggregate principal amount of Indebtedness permitted by this Section 6.01(d), when combined with the aggregate principal amount of all Capital Lease Obligations and Synthetic Lease Obligations incurred pursuant to Section 6.01(e), shall not exceed $200,000,000 at any time outstanding;

(e) Capital Lease Obligations and Synthetic Lease Obligations in an aggregate principal amount, when combined with the aggregate principal amount of all Indebtedness incurred pursuant to Section 6.01(d), not in excess of $200,000,000 at any time outstanding;

(f) Indebtedness under performance bonds or with respect to workers’ compensation claims, in each case incurred in the ordinary course of business, and Indebtedness in the form of Letters of Credit provided in lieu of or as security for any of the foregoing;

(g) Indebtedness consisting of reimbursement obligations or other obligations as an account party in respect of letters of credit issued for the account of the Borrower or any Subsidiary (i) to ensure payment or performance of the obligations referred to in Section 6.02(g), or (ii) in the ordinary course of business in an amount not in excess of $10,000,000 at any time outstanding;

(h) (i) Permitted Subordinated Indebtedness incurred by the Borrower; provided that (A) at the time of the incurrence of such Permitted Subordinated Indebtedness and after giving pro forma effect thereto, no Default or Event of Default shall have occurred and be continuing or would result therefrom and the Borrower shall be in Pro Forma Financial Covenant Compliance, (B) a Financial Officer of the Borrower shall have delivered an officer’s certificate demonstrating the calculation of such Pro Forma Financial Covenant Compliance in form and detail reasonably satisfactory to the Administrative Agent and (C) the Borrower shall have notified the Administrative Agent reasonably prior to the issuance of such Permitted Subordinated Indebtedness and of the principal terms thereof and the Administrative Agent shall have approved of such terms to the extent the Administrative Agent’s approval thereof is contemplated by the definition of the term “Permitted Subordinated Indebtedness”; and (ii) Permitted Refinancing Indebtedness in respect thereof;

(i) (i) Indebtedness under a Second Lien Facility (A) the proceeds of which are used solely to repurchase, redeem or otherwise refinance the Existing Preferred Stock and to pay related transaction costs, in an aggregate principal amount not exceeding the aggregate accreted liquidation value of the Existing Preferred Stock to be so repurchased, redeemed or otherwise refinanced (plus an amount equal to the Borrower’s good faith estimate of such transaction costs), and (B) in an aggregate principal amount for all such Indebtedness incurred pursuant to this clause (B) not to exceed $100,000,000 at any time outstanding; provided that (1) at the time of the incurrence of such Indebtedness and after giving pro forma effect thereto, no Default or Event of Default shall have occurred and be

63

continuing or would result therefrom and the Borrower shall be in Pro Forma Financial Covenant Compliance, (2) a Financial Officer of the Borrower shall have delivered an officer’s certificate demonstrating the calculation of such Pro Forma Financial Covenant Compliance and (3) the Borrower shall have notified the Administrative Agent reasonably prior to the issuance of such Indebtedness and of the principal terms thereof and the Administrative Agent shall have approved of such terms to the extent the Administrative Agent’s approval thereof is contemplated by the definition “Second Lien Facility”; and (ii) Permitted Refinancing Indebtedness in respect thereof; and

(j) other unsecured Indebtedness of the Borrower or the Subsidiaries in an aggregate principal amount not exceeding $60,000,000 at any time outstanding (provided that the aggregate principal amount of Indebtedness incurred pursuant to this paragraph (j) by Subsidiaries that are not Subsidiary Guarantors shall not exceed $10,000,000).

SECTION 6.02. Liens. Create, incur, assume or permit to exist any Lien on any property or assets (including Equity Interests or other securities of any person, including any Subsidiary) now owned or hereafter acquired by it or on any income or revenues or rights in respect of any thereof, except:

(a) Liens on property or assets of the Borrower and its Subsidiaries existing on the Prior Restatement Date and set forth in Schedule 6.02; provided that such Liens shall secure only those obligations which they secure on the Prior Restatement Date;

(b) any Lien created under the Loan Documents;

(c) any Lien existing on any property or asset prior to the acquisition thereof by the Borrower or any Subsidiary; provided that (i) such Lien is not created in contemplation of or in connection with such acquisition, (ii) such Lien does not apply to any other property or assets of the Borrower or any Subsidiary and (iii) such Lien does not (A) materially interfere with the use, occupancy and operation of any Mortgaged Property, (B) materially reduce the fair market value of such Mortgaged Property but for such Lien or (C) result in any material increase in the cost of operating, occupying or owning or leasing such Mortgaged Property;

(d) Liens for taxes not yet due or which are being contested in compliance with Section 5.03;

(e) carriers’, warehousemen’s, mechanics’, materialmen’s, repairmen’s or other like Liens arising in the ordinary course of business and securing obligations that are not due and payable or which are being contested in compliance with Section 5.03;

(f) pledges and deposits made in the ordinary course of business in compliance with workmen’s compensation, unemployment insurance and other social security laws or regulations;

(g) deposits to secure the performance of bids, trade contracts (other than for Indebtedness), leases (other than Capital Lease Obligations), statutory obligations, surety

64

and appeal bonds, performance bonds and other obligations of a like nature incurred in the ordinary course of business, or to secure letters of credit issued to ensure payment or performance of any of the foregoing;

(h) zoning restrictions, easements, rights-of-way, restrictions on use of real property and other similar encumbrances incurred in the ordinary course of business which, in the aggregate, are not substantial in amount and do not materially detract from the value of the property subject thereto or interfere with the ordinary conduct of the business of the Borrower or any of its Subsidiaries;

(i) purchase money security interests or other Liens in real property, improvements thereto or equipment hereafter acquired (or, in the case of improvements, constructed) by the Borrower or any Subsidiary; provided that (i) such security interests or other Liens secure Indebtedness permitted by Section 6.01, (ii) such security interests or other Liens are incurred, and the Indebtedness secured thereby is created, within 90 days after such acquisition (or construction), (iii) the Indebtedness secured thereby does not exceed 90% of the lesser of the cost or the fair market value of such real property, improvements or equipment at the time of such acquisition (or construction) and (iv) such security interests or other Liens do not apply to any other property or assets of the Borrower or any Subsidiary;

(j) Liens arising out of judgments or awards in respect of which the Borrower or any of the Subsidiaries shall in good faith be prosecuting an appeal or proceedings for review in respect of which there shall be secured a subsisting stay of execution pending such appeal or proceedings; provided that the aggregate amount of all such judgments or awards (and any cash and the fair market value of any property subject to such Liens) does not exceed $10,000,000 at any time outstanding;

(k) deposits of cash collateral required under the terms of Commodity Hedging Agreements entered into in the ordinary course of business in compliance with Section 5.11 in an amount not exceeding $20,000,000 at any time;

(l) Liens arising under operating agreements, joint venture agreements, partnership agreements, oil and gas leases, farm-out and farm-in agreements, division orders, contracts for the sale, transportation or exchange of oil or natural gas, unitization and pooling declarations and agreements, area of mutual interest agreements and other agreements that are customary in the Oil and Gas Business; provided that the amount of any obligations secured thereby that are delinquent, that are not diligently contested in good faith and for which adequate reserves are not maintained by the Borrower or the applicable Subsidiary, as the case may be, do not exceed, at any time outstanding, the amount owing by the Borrower or such Subsidiary, as applicable, for two months’ billed operating expenses or other expenditures attributable to such person’s interest in the property covered thereby; and provided further that the obligations secured thereby do not constitute obligations in respect of borrowed money;

(m) Liens reserved in oil and gas mineral leases for bonus or rental payments and for compliance with the terms of such leases, provided that the amount of any obligations

65

secured thereby that are delinquent, that are not diligently contested in good faith and for which adequate reserves are not maintained by the Borrower or the applicable Subsidiary, as the case may be, do not exceed, at any time outstanding, the amount owing by the Borrower or such Subsidiary, as applicable, for two months’ payments as due thereunder;

(n) Liens on pipeline or pipeline facilities that arise under operation of law; and

(o) Liens on the Collateral (but not any other assets) securing Indebtedness under any Second Lien Facility (or any Permitted Refinancing Indebtedness in respect thereof), so long as such Liens are subject to the Second Lien Intercreditor Agreement (or, in the case of any such Permitted Refinancing Indebtedness, another intercreditor agreement that is no less favorable to the Secured Parties than the Second Lien Intercreditor Agreement).

SECTION 6.03. Sale and Lease-Back Transactions. Enter into any arrangement, directly or indirectly, with any person whereby it shall sell or transfer any property, real or personal, used or useful in its business, whether now owned or hereafter acquired, and thereafter rent or lease such property or other property which it intends to use for substantially the same purpose or purposes as the property being sold or transferred unless (a) the sale of such property is permitted by Section 6.05 and (b) any Capital Lease Obligations, Synthetic Lease Obligations or Liens arising in connection therewith are permitted by Sections 6.01 and 6.02, as the case may be.

SECTION 6.04. Investments, Loans, Advances and Oil and Gas Property Acquisitions. Purchase, hold or acquire any Equity Interests, evidences of indebtedness or other securities of, make or permit to exist any loans or advances to, or make or permit to exist any investment or any other interest in, any other person, or make any other investment or acquisition of Oil and Gas Properties, except:

(a) (i) investments by the Borrower and the Subsidiaries existing on the Prior Restatement Date in the Equity Interests of the Borrower and the Subsidiaries and (ii) additional investments by the Borrower and the Subsidiaries in the Equity Interests of the Borrower and the Subsidiaries; provided that (A) any such Equity Interests held by a Loan Party shall be pledged pursuant to the Guarantee and Collateral Agreement or other applicable Security Document and (B) the aggregate amount of investments by Loan Parties in, and loans and advances by Loan Parties to, Subsidiaries that are not Loan Parties (determined without regard to any write-downs or write-offs of such investments, loans and advances), other than those permitted pursuant to paragraph (d) below, shall not exceed $10,000,000 at any time outstanding;

(b) Permitted Investments;

(c) loans or advances made by the Borrower to any Subsidiary and made by any Subsidiary to the Borrower or any other Subsidiary; provided that (i) any such loans and advances made by a Loan Party shall be evidenced by a promissory note pledged to the Collateral Agent for the ratable benefit of the Secured Parties pursuant to the Guarantee and Collateral Agreement or other applicable Security Document and (ii) the amount of

66

such loans and advances made by Loan Parties to Subsidiaries that are not Loan Parties shall be subject to the limitations set forth in paragraph (a) above and paragraph (d) below;

(d) investments by Loan Parties in, and loans and advances by Loan Parties to any Foreign Subsidiary to fund Capital Expenditures and other development costs in respect of Oil and Gas Properties located in the North Sea, the aggregate amount of which following the Prior Restatement Date (determined without regard to any write-downs or write-offs of such investments, loans and advances) shall not exceed $300,000,000;

(e) investments received in connection with the bankruptcy or reorganization of, or settlement of delinquent accounts and disputes with, customers and suppliers, in each case in the ordinary course of business;

(f) the Borrower and the Subsidiaries may make loans and advances in the ordinary course of business to their respective employees so long as the aggregate principal amount thereof at any time outstanding (determined without regard to any write-downs or write-offs of such loans and advances) shall not exceed $1,000,000 at any time;

(g) the Borrower or any Subsidiary may enter into Hedging Agreements that (i) are required by Section 5.10 or (ii) are not speculative in nature;

(h) Permitted Business Investments; provided that (i) the aggregate amount of Permitted Business Investments in any fiscal year does not exceed the greater of (A) $150,000,000 or (B) 7.5% of PV-10 Value and (ii) both before and after giving effect thereto, no Event of Default or Default shall have occurred and be continuing;

(i) in addition to investments permitted by paragraphs (a) through (h) above, additional investments, loans and advances by the Borrower and the Subsidiaries so long as the aggregate amount invested, loaned or advanced pursuant to this paragraph (i) (determined without regard to any write-downs or write-offs of such investments, loans and advances) does not exceed $10,000,000 in the aggregate.

SECTION 6.05. Mergers, Consolidations, Sales of Assets and Acquisitions. (a) Merge into or consolidate with any other person, or permit any other person to merge into or consolidate with it, or sell, transfer, lease or otherwise dispose of (in one transaction or in a series of transactions) all or substantially all the assets (whether now owned or hereafter acquired) of the Borrower or less than all the Equity Interests of any Subsidiary, or purchase, lease or otherwise acquire (in one transaction or a series of transactions) all or any substantial part of the assets of any other person, except that (i) the Borrower and any Subsidiary may purchase and sell Hydrocarbons and other inventory in the ordinary course of business and (ii) if at the time thereof and immediately after giving effect thereto no Event of Default or Default shall have occurred and be continuing (x) any wholly owned Subsidiary may merge into the Borrower in a transaction in which the Borrower is the surviving corporation, (y) any wholly owned Subsidiary may merge into or consolidate with any other wholly owned Subsidiary in a transaction in which

67

the surviving entity is a wholly owned Subsidiary and no person other than the Borrower or a wholly owned Subsidiary receives any consideration (provided that if any party to any such transaction is a Loan Party, the surviving entity of such transaction shall be a Loan Party) and (z) the Borrower and the Subsidiaries may make Permitted Business Investments in accordance with Section 6.04.

(b) Engage in any Asset Sale otherwise permitted under paragraph (a) above unless (i) such Asset Sale (x) involves the sale, transfer, lease or other disposition of Hydrocarbon Interests for consideration that consists of Hydrocarbon Interests or a combination of Hydrocarbon Interests and cash or (y) is for consideration at least 75% of which is cash, (ii) such consideration is at least equal to the fair market value of the assets being sold, transferred, leased or disposed of and (iii) the fair market value of all assets sold, transferred, leased or disposed of pursuant to this paragraph (b) shall not exceed, in the aggregate, the greater of (A) $75,000,000 or (B) 7.5% of PV-10 Value.

SECTION 6.06. Restricted Payments; Restrictive Agreements. (a) Declare or make, or agree to declare or make, directly or indirectly, any Restricted Payment (including pursuant to any Synthetic Purchase Agreement), or incur any obligation (contingent or otherwise) to do so; provided, however, that (i) any Subsidiary may declare and pay dividends or make other distributions ratably to its equity holders, (ii) so long as no Event of Default or Default shall have occurred and be continuing or would result therefrom, the Borrower may (A) repurchase its Equity Interests owned by employees of the Borrower or the Subsidiaries or make payments to employees of the Borrower or the Subsidiaries upon termination of employment in connection with the exercise of stock options, stock appreciation rights or similar equity incentives or equity based incentives pursuant to management incentive plans or in connection with the death or disability of such employees in an aggregate amount not to exceed $5,000,000 in any fiscal year, (B) repurchase, redeem or otherwise refinance the Existing Preferred Stock with the Net Cash Proceeds of (x) any Permitted Subordinated Indebtedness incurred by the Borrower pursuant to Section 6.01(h), (y) any Indebtedness under a Second Lien Facility incurred by the Borrower pursuant to Section 6.01(i) or (z) any additional Term Loans made pursuant to (1) Amendment No. 1 and Agreement dated as of November 22, 2006, to the Existing Credit Agreement, among the Borrower, the Subsidiary Guarantors, Bayerische Hypo-und Vereinsbank AG, New York Branch, Credit Suisse, as Administrative Agent, and the Required Lenders or (2) any future amendment to this Agreement that provides for the making of additional Term Loans hereunder or (C) repurchase its common Equity Interests in the open market or otherwise in an aggregate amount not to exceed the sum of (x) $10,000,000 and (y) the CNI Growth Amount as in effect immediately prior to the time of the making of such Restricted Payment; (iii) so long as no Default or Event of Default shall have occurred and be continuing or would result therefrom, the Borrower may pay regularly scheduled cash dividends on any Preferred Equity Interests issued after the Prior Restatement Date to the extent the incurrence thereof is permitted pursuant to Section 6.01, and (iv) so long as no Default or Event of Default shall have occurred and be continuing or would result therefrom, the Borrower may make other Restricted Payments under this clause (iv) in an amount not to exceed $5,000,000 in any fiscal year.

(b) Enter into, incur or permit to exist any agreement or other arrangement that prohibits, restricts or imposes any condition upon (i) the ability of the Borrower or any Subsidiary to create, incur or permit to exist any Lien upon any of its property or assets, or (ii) the ability of

68

any Subsidiary to pay dividends or other distributions with respect to any of its Equity Interests or to make or repay loans or advances to the Borrower or any other Subsidiary or to Guarantee Indebtedness of the Borrower or any other Subsidiary; provided that (A) the foregoing shall not apply to restrictions and conditions imposed by law or by any Loan Document (or any Second Lien Facility Document), (B) the foregoing shall not apply to customary restrictions and conditions contained in agreements relating to the sale of a Subsidiary pending such sale, provided such restrictions and conditions apply only to the Subsidiary that is to be sold and such sale is permitted hereunder, (C) clause (i) of the foregoing shall not apply to restrictions or conditions imposed by any agreement relating to secured Indebtedness permitted by this Agreement if such restrictions or conditions apply only to the property or assets securing such Indebtedness and (D) clause (i) of the foregoing shall not apply to customary provisions in leases and other contracts restricting the assignment thereof.

SECTION 6.07. Transactions with Affiliates. Except for transactions between or among Loan Parties, sell or transfer any property or assets to, or purchase or acquire any property or assets from, or otherwise engage in any other transactions with, any of its Affiliates, except that the Borrower or any Subsidiary may engage in any of the foregoing transactions in the ordinary course of business at prices and on terms and conditions not less favorable to the Borrower or such Subsidiary than could be obtained on an arm’s-length basis from unrelated third parties.

SECTION 6.08. Business of the Borrower and Subsidiaries. Engage at any time in any business or business activity other than the Oil and Gas Business.

SECTION 6.09. Other Indebtedness and Agreements. (a) Permit any waiver, supplement, modification, amendment, termination or release of any Junior Financing Documentation or any other indenture, instrument or agreement pursuant to which any Material Indebtedness of the Borrower or any of the Subsidiaries is outstanding if the effect of such waiver, supplement, modification, amendment, termination or release would materially increase the obligations of the obligor or confer additional material rights on the holder of such Indebtedness in a manner adverse to the Borrower, any of the Subsidiaries or the Lenders.

(b) (i) Make any distribution, whether in cash, property, securities or a combination thereof, other than regular scheduled payments of principal and interest as and when due (to the extent not prohibited by applicable subordination provisions), in respect of, or pay, or offer or commit to pay, or directly or indirectly (including pursuant to any Synthetic Purchase Agreement) redeem, repurchase, retire or otherwise acquire for consideration, or set apart any sum for the aforesaid purposes, (A) any Permitted Subordinated Indebtedness or other subordinated Indebtedness, (B) any Indebtedness under any Second Lien Facility (other than with the Net Cash Proceeds of any Permitted Subordinated Indebtedness), except with Declined Proceeds applied in accordance with the mandatory prepayment provisions of the Second Lien Credit Agreement as contemplated by Section 2.13(h), or, in the case of Declined Proceeds that are retained by the Borrower after having been declined by (I) the Lenders pursuant to Section 2.13(h) and (II) the lenders under the Second Lien Credit Agreement pursuant to the mandatory prepayment provisions thereof, with such Declined Proceeds in accordance with the voluntary prepayment provisions of the Second Lien Credit Agreement or (C) any Disqualified Capital Stock, or (ii) pay in cash any amount in respect of any Indebtedness or Preferred Equity Interests that may at the obligor’s option be paid in kind or in other securities.

69

SECTION 6.10. Forward Sales. Except in accordance with usual and customary practice in the Oil and Gas Business and except for Hydrocarbon imbalances not in excess of the greater of (i) 10 Bcfe or (ii) 3% of projected PDP production from time to time from the Oil and Gas Properties of the Borrower and the Subsidiaries for the succeeding twelve calendar months, enter into or permit to exist any advance payment agreement or other arrangement pursuant to which the Borrower or any of the Subsidiaries, having received full or substantial payment of the purchase price for a specified quantity of Hydrocarbons upon entering such agreement or arrangement, is required to deliver, in one or more installments subsequent to the date of such agreement or arrangement, such quantity of Hydrocarbons pursuant to and during the terms of such agreement or arrangement.

SECTION 6.11. Limitation on Commodity Hedging. Enter into any Commodity Hedge Agreement if, after giving effect thereto the total volume of Hydrocarbons to be hedged under Commodity Hedging Agreements would exceed, at the time of entering into any Commodity Hedge Agreement, 80% of the projected PDP production from the Oil and Gas Properties of the Borrower and the Subsidiaries for the period during which such Commodity Hedging Agreement is in effect.

SECTION 6.12. Interest Coverage Ratio. Permit the Interest Coverage Ratio for any period of four consecutive fiscal quarters, in each case taken as one accounting period, ending on the last day of any fiscal quarter to be less than 2.50 to 1.00.

SECTION 6.13. Maximum Leverage Ratio. Permit the Leverage Ratio at the end of any fiscal quarter to be greater than 3.00 to 1.00.

SECTION 6.14. Minimum Current Ratio. Permit the Current Ratio at the end of any fiscal quarter to be less than 1.00 to 1.00.

SECTION 6.15. Minimum Asset Coverage Ratios. Permit (i) the Reserve Coverage Ratio at June 30 or December 31 of any fiscal year to be less than 3.00 to 1.00 or (ii) the PDP Coverage Ratio at June 30 or December 31 of any fiscal year to be less than 0.50 to 1.00.

SECTION 6.16. Designated Senior Debt. Designate any Indebtedness (other than under this Agreement and the other Loan Documents) of the Borrower or any of its Subsidiaries as “Senior Indebtedness”, “Designated Senior Debt” or “Senior Secured Financing” (or any comparable term) under, and as defined in, any Junior Financing Documentation relating to any Permitted Subordinated Indebtedness.

SECTION 6.17. Fiscal Year. With respect to the Borrower, change its fiscal year-end to a date other than December 31.

ARTICLE VII

Events of Default

In case of the happening of any of the following events (“Events of Default”):

(a) any representation or warranty made or deemed made in or in connection with any Loan Document or the borrowings or issuances of Letters of Credit hereunder, or any representation, warranty, statement or information contained in any report, certificate, financial statement or other instrument furnished in connection with or pursuant to any Loan Document, shall prove to have been false or misleading in any material respect when so made, deemed made or furnished;

70

(b) default shall be made in the payment of any principal of any Loan or the reimbursement with respect to any L/C Disbursement when and as the same shall become due and payable, whether at the due date thereof or at a date fixed for prepayment thereof or by acceleration thereof or otherwise;

(c) default shall be made in the payment of any interest on any Loan or any Fee or L/C Disbursement or any other amount (other than an amount referred to in (b) above) due under any Loan Document, when and as the same shall become due and payable, and such default shall continue unremedied for a period of three Business Days;

(d) default shall be made in the due observance or performance by the Borrower or any Subsidiary of any covenant, condition or agreement contained in Section 5.01(a), 5.05 or 5.08 or in Article VI;

(e) default shall be made in the due observance or performance by the Borrower or any Subsidiary of any covenant, condition or agreement contained in any Loan Document (other than those specified in (b), (c) or (d) above) and such default shall continue unremedied for a period of 20 days after notice thereof from the Administrative Agent or any Lender to the Borrower;

(f) (i) the Borrower or any Subsidiary shall fail to pay any principal or interest, regardless of amount, due in respect of any Material Indebtedness, when and as the same shall become due and payable or (ii) any other event or condition occurs that results in any Material Indebtedness becoming due prior to its scheduled maturity or that enables or permits (with or without the giving of notice, the lapse of time or both) the holder or holders of any Material Indebtedness or any trustee or agent on its or their behalf to cause any Material Indebtedness to become due, or to require the prepayment, repurchase, redemption or defeasance thereof, prior to its scheduled maturity; provided that this clause (ii) shall not apply to secured Indebtedness that becomes due as a result of the voluntary sale or transfer of the property or assets securing such Indebtedness;

(g) an involuntary proceeding shall be commenced or an involuntary petition shall be filed in a court of competent jurisdiction seeking (i) relief in respect of the Borrower or any Subsidiary, or of a substantial part of the property or assets of the Borrower or a Subsidiary, under Title 11 of the United States Code, as now constituted or hereafter amended, or any other Federal, state or foreign bankruptcy, insolvency, receivership or similar law, (ii) the appointment of a receiver, trustee, custodian, sequestrator, conservator or similar official for the Borrower or any Subsidiary or for a substantial part of the property or assets of the Borrower or a Subsidiary or (iii) the winding-up or liquidation of the Borrower or any Subsidiary; and such proceeding or petition shall continue undismissed for 60 days or an order or decree approving or ordering any of the foregoing shall be entered;

71

(h) the Borrower or any Subsidiary shall (i) voluntarily commence any proceeding or file any petition seeking relief under Title 11 of the United States Code, as now constituted or hereafter amended, or any other Federal, state or foreign bankruptcy, insolvency, receivership or similar law, (ii) consent to the institution of, or fail to contest in a timely and appropriate manner, any proceeding or the filing of any petition described in (g) above, (iii) apply for or consent to the appointment of a receiver, trustee, custodian, sequestrator, conservator or similar official for the Borrower or any Subsidiary or for a substantial part of the property or assets of the Borrower or any Subsidiary, (iv) file an answer admitting the material allegations of a petition filed against it in any such proceeding, (v) make a general assignment for the benefit of creditors, (vi) become unable, admit in writing its inability or fail generally to pay its debts as they become due or (vii) take any action for the purpose of effecting any of the foregoing;

(i) one or more judgments shall be rendered against the Borrower, any Subsidiary or any combination thereof and the same shall remain undischarged for a period of 30 consecutive days during which execution shall not be effectively stayed, or any action shall be legally taken by a judgment creditor to levy upon assets or properties of the Borrower or any Subsidiary to enforce any such judgment and such judgment either (i) is for the payment of money in an aggregate amount in excess of $10,000,000 or (ii) is for injunctive relief and could reasonably be expected to result in a Material Adverse Effect;

(j) an ERISA Event shall have occurred that, in the opinion of the Required Lenders, when taken together with all other such ERISA Events, could reasonably be expected to result in liability of the Borrower and its ERISA Affiliates in an aggregate amount exceeding $5,000,000;

(k) any Guarantee under the Guarantee and Collateral Agreement for any reason shall cease to be in full force and effect (other than in accordance with its terms), or any Guarantor shall deny in writing that it has any further liability under the Guarantee and Collateral Agreement (other than as a result of the discharge of such Guarantor in accordance with the terms of the Loan Documents);

(l) any security interest purported to be created by any Security Document shall cease to be, or shall be asserted by the Borrower or any other Loan Party not to be, a valid, perfected, first priority (except as otherwise expressly provided in this Agreement or such Security Document) security interest in the securities, assets or properties covered thereby, except to the extent that any such loss of perfection or priority results from the failure of the Collateral Agent to maintain possession of certificates representing securities pledged under the Guarantee and Collateral Agreement or other applicable Security Document;

(m) (i) any of the Obligations of the Loan Parties under the Loan Documents for any reason shall cease to be “Senior Indebtedness”, “Designated Senior Debt” or “Senior Secured Financing” (or any comparable term) under, and as defined in, any other Junior Financing Documentation relating to any Permitted Subordinated Indebtedness, (ii) the subordination provisions set forth in any Junior Financing Documentation relating to any Permitted Subordinated Indebtedness shall, in whole or in part, cease to be effective or cease to be legally valid, binding and enforceable against the holders of such Permitted Subordinated Indebtedness or (iii) the Second Lien Intercreditor Agreement (or, with respect to any Permitted Refinancing Indebtedness in respect thereof, any other intercreditor agreement as described in clause (f) of

72

the definition of the term “Permitted Refinancing Indebtedness”) shall, in whole or in part, cease to be effective or cease to be legally valid, binding and enforceable against the holders of any Indebtedness under the Second Lien Facility or such Permitted Refinancing Indebtedness, as the case may be; or

(n) there shall have occurred a Change in Control;

then, and in every such event (other than an event with respect to the Borrower described in paragraph (g) or (h) above), and at any time thereafter during the continuance of such event, the Administrative Agent may, and at the request of the Required Lenders shall, by notice to the Borrower, take either or both of the following actions, at the same or different times: (i) terminate forthwith the Commitments and (ii) declare the Loans then outstanding to be forthwith due and payable in whole or in part, whereupon the principal of the Loans so declared to be due and payable, together with accrued interest thereon and any unpaid accrued Fees and all other liabilities of the Borrower accrued hereunder and under any other Loan Document, shall become forthwith due and payable, without presentment, demand, protest or any other notice of any kind, all of which are hereby expressly waived by the Borrower, anything contained herein or in any other Loan Document to the contrary notwithstanding; and in any event with respect to the Borrower described in paragraph (g) or (h) above, the Commitments shall automatically terminate and the principal of the Loans then outstanding, together with accrued interest thereon and any unpaid accrued Fees and all other liabilities of the Borrower accrued hereunder and under any other Loan Document, shall automatically become due and payable, without presentment, demand, protest or any other notice of any kind, all of which are hereby expressly waived by the Borrower, anything contained herein or in any other Loan Document to the contrary notwithstanding.

ARTICLE VIII

The Administrative Agent and the Collateral Agent

Each of the Lenders and the Issuing Bank hereby irrevocably appoints the Administrative Agent and the Collateral Agent (for purposes of this Article VIII, the Administrative Agent and the Collateral Agent are referred to collectively as the “Agents”) its agent and authorizes the Agents to take such actions on its behalf and to exercise such powers as are delegated to such Agent by the terms of the Loan Documents, together with such actions and powers as are reasonably incidental thereto. Without limiting the generality of the foregoing, the Agents are hereby expressly authorized to execute any and all documents (including releases) with respect to the Collateral and the rights of the Secured Parties with respect thereto, as contemplated by and in accordance with the provisions of this Agreement and the Security Documents.

The bank serving as the Administrative Agent and/or the Collateral Agent hereunder shall have the same rights and powers in its capacity as a Lender as any other Lender and may exercise the same as though it were not an Agent, and such bank and its Affiliates may accept deposits from, lend money to and generally engage in any kind of business with the Borrower or any Subsidiary or other Affiliate thereof as if it were not an Agent hereunder.

73

Neither Agent shall have any duties or obligations except those expressly set forth in the Loan Documents. Without limiting the generality of the foregoing, (a) neither Agent shall be subject to any fiduciary or other implied duties, regardless of whether a Default has occurred and is continuing, (b) neither Agent shall have any duty to take any discretionary action or exercise any discretionary powers, except discretionary rights and powers expressly contemplated hereby that such Agent is instructed in writing to exercise by the Required Lenders (or such other number or percentage of the Lenders as shall be necessary under the circumstances as provided in Section 9.08), and (c) except as expressly set forth in the Loan Documents, neither Agent shall have any duty to disclose, nor shall it be liable for the failure to disclose, any information relating to the Borrower or any of the Subsidiaries that is communicated to or obtained by the bank serving as Administrative Agent and/or Collateral Agent or any of its Affiliates in any capacity. Neither Agent shall be liable for any action taken or not taken by it with the consent or at the request of the Required Lenders (or such other number or percentage of the Lenders as shall be necessary under the circumstances as provided in Section 9.08) or in the absence of its own gross negligence or wilful misconduct. Neither Agent shall be deemed to have knowledge of any Default unless and until written notice thereof is given to such Agent by the Borrower or a Lender, and neither Agent shall be responsible for or have any duty to ascertain or inquire into (i) any statement, warranty or representation made in or in connection with any Loan Document, (ii) the contents of any certificate, report or other document delivered thereunder or in connection therewith, (iii) the performance or observance of any of the covenants, agreements or other terms or conditions set forth in any Loan Document, (iv) the validity, enforceability, effectiveness or genuineness of any Loan Document or any other agreement, instrument or document, or (v) the satisfaction of any condition set forth in Article IV or elsewhere in any Loan Document, other than to confirm receipt of items expressly required to be delivered to such Agent.

Each Agent shall be entitled to rely upon, and shall not incur any liability for relying upon, any notice, request, certificate, consent, statement, instrument, document or other writing believed by it to be genuine and to have been signed or sent by the proper person. Each Agent may also rely upon any statement made to it orally or by telephone and believed by it to have been made by the proper person, and shall not incur any liability for relying thereon. Each Agent may consult with legal counsel (who may be counsel for the Borrower), independent accountants and other experts selected by it, and shall not be liable for any action taken or not taken by it in accordance with the advice of any such counsel, accountants or experts.

Each Agent may perform any and all its duties and exercise its rights and powers by or through any one or more sub-agents appointed by it. Each Agent and any such sub-agent may perform any and all its duties and exercise its rights and powers by or through their respective Related Parties. The exculpatory provisions of the preceding paragraphs shall apply to any such sub-agent and to the Related Parties of each Agent and any such sub-agent, and shall apply to their respective activities in connection with the syndication of the Credit Facilities as well as activities as Agent.

Subject to the appointment and acceptance of a successor Agent as provided below, either Agent may resign at any time by notifying the Lenders, the Issuing Bank and the Borrower. Upon any such resignation, the Required Lenders shall have the right, in consultation with the Borrower, to appoint a successor. If no successor shall have been so appointed by the Required Lenders and shall have accepted such appointment within 30 days after the retiring Agent gives

74

notice of its resignation, then the retiring Agent may, on behalf of the Lenders and the Issuing Bank, appoint a successor Agent which shall be a bank with an office in New York, New York, or an Affiliate of any such bank. Upon the acceptance of its appointment as Agent hereunder by a successor, such successor shall succeed to and become vested with all the rights, powers, privileges and duties of the retiring Agent, and the retiring Agent shall be discharged from its duties and obligations hereunder. The fees payable by the Borrower to a successor Agent shall be the same as those payable to its predecessor unless otherwise agreed between the Borrower and such successor. After an Agent’s resignation hereunder, the provisions of this Article and Section 9.05 shall continue in effect for the benefit of such retiring Agent, its sub-agents and their respective Related Parties in respect of any actions taken or omitted to be taken by any of them while acting as Agent.

Each Lender acknowledges that it has, independently and without reliance upon the Agents or any other Lender and based on such documents and information as it has deemed appropriate, made its own credit analysis and decision to enter into this Agreement. Each Lender also acknowledges that it will, independently and without reliance upon the Agents or any other Lender and based on such documents and information as it shall from time to time deem appropriate, continue to make its own decisions in taking or not taking action under or based upon this Agreement or any other Loan Document, any related agreement or any document furnished hereunder or thereunder.

ARTICLE IX

Miscellaneous

SECTION 9.01. Notices. Notices and other communications provided for herein shall be in writing and shall be delivered by hand or overnight courier service, mailed by certified or registered mail or sent by fax, as follows:

(a) if to the Borrower, to it at 4600 Post Oak Place, Suite 200, Houston, TX 77027, Attention of Chief Financial Officer (Fax No. (713) 622-5101, with a copy to Jackson Walker L.L.P. at 1401 McKinney, Suite 1900, Houston, Texas 77010, Attention of David G. Dunlap (Fax No. (713) 308-4101);

(b) if to the Administrative Agent, to Credit Suisse, Eleven Madison Avenue, New York, NY 10010, Attention of Agency Group (Fax No. (212) 325-8304); and

(c) if to a Lender, to it at its address (or fax number) set forth in its Administrative Questionnaire or in the Assignment and Acceptance pursuant to which such Lender shall have become a party hereto.

All notices and other communications given to any party hereto in accordance with the provisions of this Agreement shall be deemed to have been given on the date of receipt if delivered by hand or overnight courier service or sent by fax or on the date five Business Days after dispatch by certified or registered mail if mailed, in each case delivered, sent or mailed (properly addressed) to such party as provided in this Section 9.01 or in accordance with the latest unrevoked direction from such party given in accordance with this Section 9.01. As agreed

75

to among the Borrower, the Administrative Agent and the applicable Lenders from time to time, notices and other communications may also be delivered by e-mail to the e-mail address of a representative of the applicable person provided from time to time by such person.

SECTION 9.02. Survival of Agreement. All covenants, agreements, representations and warranties made by the Borrower herein and in the certificates or other instruments prepared or delivered in connection with or pursuant to this Agreement or any other Loan Document shall be considered to have been relied upon by the Lenders and the Issuing Bank and shall survive the making by the Lenders of the Loans and the issuance of Letters of Credit by the Issuing Bank, regardless of any investigation made by the Lenders or the Issuing Bank or on their behalf, and shall continue in full force and effect as long as the principal of or any accrued interest on any Loan or any Fee or any other amount payable under this Agreement or any other Loan Document is outstanding and unpaid or any Letter of Credit is outstanding and so long as the Commitments have not been terminated. The provisions of Sections 2.14, 2.16, 2.20 and 9.05 shall remain operative and in full force and effect regardless of the expiration of the term of this Agreement, the consummation of the transactions contemplated hereby, the repayment of any of the Loans, the expiration of the Commitments, the expiration of any Letter of Credit, the invalidity or unenforceability of any term or provision of this Agreement or any other Loan Document, or any investigation made by or on behalf of the Administrative Agent, the Collateral Agent, any Lender or the Issuing Bank.

SECTION 9.03. Binding Effect. This Agreement shall become effective as set forth in the Amendment Agreement.

SECTION 9.04. Successors and Assigns. (a) Whenever in this Agreement any of the parties hereto is referred to, such reference shall be deemed to include the permitted successors and assigns of such party; and all covenants, promises and agreements by or on behalf of the Borrower, the Administrative Agent, the Collateral Agent, the Issuing Bank or the Lenders that are contained in this Agreement shall bind and inure to the benefit of their respective successors and assigns.

(b) Each Lender may assign to one or more assignees all or a portion of its interests, rights and obligations under this Agreement (including all or a portion of its Commitments and the Loans at the time owing to it), with the prior written consent of the Administrative Agent (not to be unreasonably withheld or delayed); provided, however, that (i) in the case of an assignment of a Revolving Credit Commitment, each of the Borrower and the Issuing Bank must also give its prior written consent to such assignment (which consent shall not be unreasonably withheld or delayed) (provided, that the consent of the Borrower shall not be required to any such assignment made to another Lender or an Affiliate of a Lender or after the occurrence and during the continuance of any Event of Default), (ii) the amount of the Commitment or Loans of the assigning Lender subject to each such assignment (determined as of the date the Assignment and Acceptance with respect to such assignment is delivered to the Administrative Agent) shall not be less than $1,000,000 (or, if less, the entire remaining amount of such Lender’s Commitment or Loans of the relevant Class), (iii) the parties to each such assignment shall (A) electronically execute and deliver to the Administrative Agent an Assignment and Acceptance via an electronic settlement system acceptable to the Administrative Agent (which initially shall be ClearPar, LLC) or (B) if no such system shall then be specified by the Administrative Agent, manually

76

execute and deliver to the Administrative Agent an Assignment and Acceptance, together with a processing and recordation fee of $3,500 and (iv) the assignee, if it shall not be a Lender, shall deliver to the Administrative Agent an Administrative Questionnaire and all applicable tax forms. Upon acceptance and recording pursuant to paragraph (e) of this Section 9.04, from and after the effective date specified in each Assignment and Acceptance, (A) the assignee thereunder shall be a party hereto and, to the extent of the interest assigned by such Assignment and Acceptance, have the rights and obligations of a Lender under this Agreement and (B) the assigning Lender thereunder shall, to the extent of the interest assigned by such Assignment and Acceptance, be released from its obligations under this Agreement (and, in the case of an Assignment and Acceptance covering all or the remaining portion of an assigning Lender’s rights and obligations under this Agreement, such Lender shall cease to be a party hereto but shall continue to be entitled to the benefits of Sections 2.14, 2.16, 2.20 and 9.05, as well as to any Fees or other amounts accrued for its account and not yet paid).

(c) By executing and delivering an Assignment and Acceptance, the assigning Lender thereunder and the assignee thereunder shall be deemed to confirm to and agree with each other and the other parties hereto as follows: (i) such assigning Lender warrants that it is the legal and beneficial owner of the interest being assigned thereby free and clear of any adverse claim and that its Term Loan Commitment and Revolving Credit Commitment, and the outstanding balances of its Term Loans and Revolving Loans, in each case without giving effect to assignments thereof which have not become effective, are as set forth in such Assignment and Acceptance, (ii) except as set forth in (i) above, such assigning Lender makes no representation or warranty and assumes no responsibility with respect to any statements, warranties or representations made in or in connection with this Agreement, or the execution, legality, validity, enforceability, genuineness, sufficiency or value of this Agreement, any other Loan Document or any other instrument or document furnished pursuant hereto, or the financial condition of the Borrower or any Subsidiary or the performance or observance by the Borrower or any Subsidiary of any of its obligations under this Agreement, any other Loan Document or any other instrument or document furnished pursuant hereto; (iii) such assignee represents and warrants that it is legally authorized to enter into such Assignment and Acceptance; (iv) such assignee confirms that it has received a copy of this Agreement, together with copies of the most recent financial statements referred to in Section 3.05 or delivered pursuant to Section 5.04, and such other documents and information as it has deemed appropriate to make its own credit analysis and decision to enter into such Assignment and Acceptance; (v) such assignee will independently and without reliance upon the Administrative Agent, the Collateral Agent, such assigning Lender or any other Lender and based on such documents and information as it shall deem appropriate at the time, continue to make its own credit decisions in taking or not taking action under this Agreement; (vi) such assignee appoints and authorizes the Administrative Agent and the Collateral Agent to take such action as agent on its behalf and to exercise such powers under this Agreement as are delegated to the Administrative Agent and the Collateral Agent, respectively, by the terms hereof, together with such powers as are reasonably incidental thereto; and (vii) such assignee agrees that it will perform in accordance with their terms all the obligations which by the terms of this Agreement are required to be performed by it as a Lender.

(d) The Administrative Agent, acting for this purpose as an agent of the Borrower, shall maintain at one of its offices in The City of New York a copy of each Assignment and Acceptance delivered to it and a register for the recordation of the names and addresses of the

77

Lenders, and the Commitment of, and principal amount of the Loans owing to, each Lender pursuant to the terms hereof from time to time (the “Register”). The entries in the Register shall be conclusive absent manifest error and the Borrower, the Administrative Agent, the Issuing Bank, the Collateral Agent and the Lenders may treat each person whose name is recorded in the Register pursuant to the terms hereof as a Lender hereunder for all purposes of this Agreement, notwithstanding notice to the contrary. The Register shall be available for inspection by the Borrower, the Issuing Bank, the Collateral Agent and any Lender, at any reasonable time and from time to time upon reasonable prior notice.

(e) Upon its receipt of, and consent to, a duly completed Assignment and Acceptance executed by an assigning Lender and an assignee, an Administrative Questionnaire completed in respect of the assignee (unless the assignee shall already be a Lender hereunder), the processing and recordation fee referred to in paragraph (b) above, if applicable, and the written consent of the Administrative Agent and, if required, the Borrower and the Issuing Bank to such assignment and any applicable tax forms, the Administrative Agent shall (i) accept such Assignment and Acceptance and (ii) record the information contained therein in the Register. No assignment shall be effective unless it has been recorded in the Register as provided in this paragraph (e).

(f) Each Lender may without the consent of the Borrower, the Issuing Bank or the Administrative Agent sell participations to one or more banks or other entities in all or a portion of its rights and obligations under this Agreement (including all or a portion of its Commitment and the Loans owing to it); provided, however, that (i) such Lender’s obligations under this Agreement shall remain unchanged, (ii) such Lender shall remain solely responsible to the other parties hereto for the performance of such obligations, (iii) the participating banks or other entities shall be entitled to the benefit of the cost protection provisions contained in Sections 2.14, 2.16 and 2.20 to the same extent as if they were Lenders (but, with respect to any particular participant, to no greater extent than the Lender that sold the participation to such participant) and (iv) the Borrower, the Administrative Agent, the Issuing Bank and the Lenders shall continue to deal solely and directly with such Lender in connection with such Lender’s rights and obligations under this Agreement, and such Lender shall retain the sole right to enforce the obligations of the Borrower relating to the Loans or L/C Disbursements owing to it and to approve any amendment, modification or waiver of any provision of this Agreement (other than amendments, modifications or waivers decreasing any fees payable hereunder the amount of principal of or the rate at which interest is payable on the Loans, extending any scheduled principal payment date or date fixed for the payment of interest on the Loans, increasing or extending the Commitments or releasing any Guarantor (other than in connection with a transaction permitted hereunder) or all or substantially all of the Collateral).

(g) Any Lender or participant may, in connection with any assignment or participation or proposed assignment or participation pursuant to this Section 9.04, disclose to the assignee or participant or proposed assignee or participant any information relating to the Borrower furnished to such Lender by or on behalf of the Borrower; provided that, prior to any such disclosure of information designated by the Borrower as confidential, each such assignee or participant or proposed assignee or participant shall execute an agreement whereby such assignee or participant shall agree (subject to customary exceptions) to preserve the confidentiality of such confidential information on terms no less restrictive than those applicable to the Lenders pursuant to Section 9.16.

78

(h) Any Lender may at any time assign all or any portion of its rights under this Agreement to secure extensions of credit to such Lender or in support of obligations owed by such Lender; provided that no such assignment shall release a Lender from any of its obligations hereunder or substitute any such assignee for such Lender as a party hereto.

(i) Notwithstanding anything to the contrary contained herein, any Lender (a “Granting Lender”) may grant to a special purpose funding vehicle (an “SPC”), identified as such in writing from time to time by the Granting Lender to the Administrative Agent and the Borrower, the option to provide to the Borrower all or any part of any Loan that such Granting Lender would otherwise be obligated to make to the Borrower pursuant to this Agreement; provided that (i) nothing herein shall constitute a commitment by any SPC to make any Loan and (ii) if an SPC elects not to exercise such option or otherwise fails to provide all or any part of such Loan, the Granting Lender shall be obligated to make such Loan pursuant to the terms hereof. The making of a Loan by an SPC hereunder shall utilize the Commitment of the Granting Lender to the same extent, and as if, such Loan were made by such Granting Lender. Each party hereto hereby agrees that no SPC shall be liable for any indemnity or similar payment obligation under this Agreement (all liability for which shall remain with the Granting Lender). In furtherance of the foregoing, each party hereto hereby agrees (which agreement shall survive the termination of this Agreement) that, prior to the date that is one year and one day after the payment in full of all outstanding commercial paper or other senior indebtedness of any SPC, it will not institute against, or join any other person in instituting against, such SPC any bankruptcy, reorganization, arrangement, insolvency or liquidation proceedings under the laws of the United States or any State thereof. In addition, notwithstanding anything to the contrary contained in this Section 9.04, any SPC may (i) with notice to, but without the prior written consent of, the Borrower and the Administrative Agent and without paying any processing fee therefor, assign all or a portion of its interests in any Loans to the Granting Lender or to any financial institutions (consented to by the Borrower and Administrative Agent) providing liquidity and/or credit support to or for the account of such SPC to support the funding or maintenance of Loans and (ii) disclose on a confidential basis any non-public information relating to its Loans to any rating agency, commercial paper dealer or provider of any surety, guarantee or credit or liquidity enhancement to such SPC.

(j) The Borrower shall not assign or delegate any of its rights or duties hereunder without the prior written consent of the Administrative Agent, the Issuing Bank and each Lender, and any attempted assignment without such consent shall be null and void.

(k) In the event that any Revolving Credit Lender shall become a Defaulting Lender or S&P, Moody’s and Thompson’s BankWatch (or InsuranceWatch Ratings Service, in the case of Lenders that are insurance companies (or Best’s Insurance Reports, if such insurance company is not rated by Insurance Watch Ratings Service)) shall, after the date that any Lender becomes a Revolving Credit Lender, downgrade the long-term certificate deposit ratings of such Lender, and the resulting ratings shall be below BBB-, Baa3 and C (or BB, in the case of a Lender that is an insurance company (or B, in the case of an insurance company not rated by InsuranceWatch Ratings Service)) (or, with respect to any Revolving Credit Lender that is not rated by any such ratings service or provider, the Issuing Bank shall have reasonably determined that there has occurred a material adverse change in the financial condition of any such Lender, or a material impairment of the ability of any such Lender to perform its obligations hereunder, as compared

79

to such condition or ability as of the date that any such Lender became a Revolving Credit Lender) then the Issuing Bank shall have the right, but not the obligation, at its own expense, upon notice to such Lender and the Administrative Agent, to replace such Lender with an assignee (in accordance with and subject to the restrictions contained in paragraph (b) above), and such Lender hereby agrees to transfer and assign without recourse (in accordance with and subject to the restrictions contained in paragraph (b) above) all its interests, rights and obligations in respect of its Revolving Credit Commitment to such assignee; provided, however, that (i) no such assignment shall conflict with any law, rule and regulation or order of any Governmental Authority and (ii) the Issuing Bank or such assignee, as the case may be, shall pay to such Lender in immediately available funds on the date of such assignment the principal of and interest accrued to the date of payment on the Loans made by such Lender hereunder and all other amounts accrued for such Lender’s account or owed to it hereunder.

SECTION 9.05. Expenses; Indemnity. (a) The Borrower agrees to pay all reasonable out-of-pocket expenses incurred by the Administrative Agent, the Collateral Agent and the Issuing Bank in connection with the syndication of the Credit Facilities and the preparation and administration of this Agreement and the other Loan Documents or in connection with any amendments, modifications or waivers of the provisions hereof or thereof (whether or not the transactions hereby or thereby contemplated shall be consummated) or incurred by the Administrative Agent, the Collateral Agent or any Lender in connection with the enforcement or protection of its rights in connection with this Agreement and the other Loan Documents or in connection with the Loans made or Letters of Credit issued hereunder, including the fees, charges and disbursements of Cravath, Swaine & Moore LLP, counsel for the Administrative Agent and the Collateral Agent, and, in connection with any such enforcement or protection, the fees, charges and disbursements of any other counsel for the Administrative Agent, the Collateral Agent or any Lender.

(b) The Borrower agrees to indemnify the Administrative Agent, the Collateral Agent, each Lender, the Issuing Bank and each Related Party of any of the foregoing persons (each such person being called an “Indemnitee”) against, and to hold each Indemnitee harmless from, any and all losses, claims, damages, liabilities and related expenses, including reasonable counsel fees, charges and disbursements, incurred by or asserted against any Indemnitee arising out of, in any way connected with, or as a result of (i) the execution or delivery of this Agreement or any other Loan Document or any agreement or instrument contemplated thereby, the performance by the parties thereto of their respective obligations thereunder or the consummation of the Transactions and the other transactions contemplated thereby (including the syndication of the Credit Facilities), (ii) the use of the proceeds of the Loans or issuance of Letters of Credit, (iii) any claim, litigation, investigation or proceeding relating to any of the foregoing, whether or not any Indemnitee is a party thereto (and regardless of whether such matter is initiated by a third party or by the Borrower, any other Loan Party or any of their respective Affiliates), or (iv) any actual or alleged presence or Release of Hazardous Materials on any property currently or formerly owned or operated by the Borrower or any of the Subsidiaries, or any Environmental Liability related in any way to the Borrower or the Subsidiaries; provided that such indemnity shall not, as to any Indemnitee, be available to the extent that such losses, claims, damages, liabilities or related expenses are determined by a court of competent jurisdiction by final and nonappealable judgment to have resulted from the gross negligence or wilful misconduct of such Indemnitee.

80

(c) To the extent that the Borrower fails to pay any amount required to be paid by it to the Administrative Agent, the Collateral Agent or the Issuing Bank under paragraph (a) or (b) of this Section, each Lender severally agrees to pay to the Administrative Agent, the Collateral Agent or the Issuing Bank, as the case may be, such Lender’s pro rata share (determined as of the time that the applicable unreimbursed expense or indemnity payment is sought) of such unpaid amount; provided that the unreimbursed expense or indemnified loss, claim, damage, liability or related expense, as the case may be, was incurred by or asserted against the Administrative Agent, the Collateral Agent or the Issuing Bank in its capacity as such. For purposes hereof, a Lender’s “pro rata share” shall be determined based upon its share of the sum of the Aggregate Revolving Credit Exposure, outstanding Term Loans and unused Commitments at the time.

(d) To the extent permitted by applicable law, the Borrower shall not assert, and it hereby waives, any claim against any Indemnitee, on any theory of liability, for special, indirect, consequential or punitive damages (as opposed to direct or actual damages) arising out of, in connection with, or as a result of, this Agreement or any agreement or instrument contemplated hereby, the Transactions, any Loan or Letter of Credit or the use of the proceeds thereof.

(e) The provisions of this Section 9.05 shall remain operative and in full force and effect regardless of the expiration of the term of this Agreement, the consummation of the transactions contemplated hereby, the repayment of any of the Loans, the expiration of the Commitments, the expiration of any Letter of Credit, the invalidity or unenforceability of any term or provision of this Agreement or any other Loan Document, or any investigation made by or on behalf of the Administrative Agent, the Collateral Agent, any Lender or the Issuing Bank. All amounts due under this Section 9.05 shall be payable on written demand therefor.

SECTION 9.06. Right of Setoff. If an Event of Default shall have occurred and be continuing, each Lender is hereby authorized at any time and from time to time, except to the extent prohibited by law, to set off and apply any and all deposits (general or special, time or demand, provisional or final) at any time held and other indebtedness at any time owing by such Lender to or for the credit or the account of the Borrower against any of and all the obligations of the Borrower now or hereafter existing under this Agreement and the other Loan Documents held by such Lender, irrespective of whether or not such Lender shall have made any demand under this Agreement or such other Loan Document and although such obligations may be unmatured. The rights of each Lender under this Section 9.06 are in addition to other rights and remedies (including other rights of setoff) which such Lender may have.

SECTION 9.07. Applicable Law. THIS AGREEMENT AND THE OTHER LOAN DOCUMENTS (OTHER THAN LETTERS OF CREDIT AND AS EXPRESSLY SET FORTH IN OTHER LOAN DOCUMENTS OR TO THE EXTENT THE LAWS OF ANOTHER JURISDICTION MANDATORILY GOVERN ANY LOAN DOCUMENT) SHALL BE CONSTRUED IN ACCORDANCE WITH AND GOVERNED BY THE LAWS OF THE STATE OF NEW YORK. EACH LETTER OF CREDIT SHALL BE GOVERNED BY, AND SHALL BE CONSTRUED IN ACCORDANCE WITH, THE LAWS OR RULES DESIGNATED IN SUCH LETTER OF CREDIT, OR IF NO SUCH LAWS OR RULES ARE DESIGNATED, THE UNIFORM CUSTOMS AND PRACTICES FOR DOCUMENTARY CREDITS MOST RECENTLY PUBLISHED AND IN EFFECT, ON THE DATE SUCH LETTER OF CREDIT WAS ISSUED, BY THE INTERNATIONAL CHAMBER OF COMMERCE (THE “UNIFORM CUSTOMS”) AND, AS TO MATTERS NOT GOVERNED BY THE UNIFORM CUSTOMS, THE LAWS OF THE STATE OF NEW YORK.

81

SECTION 9.08. Waivers; Amendment. (a) No failure or delay of the Administrative Agent, the Collateral Agent, any Lender or the Issuing Bank in exercising any power or right hereunder or under any other Loan Document shall operate as a waiver thereof, nor shall any single or partial exercise of any such right or power, or any abandonment or discontinuance of steps to enforce such a right or power, preclude any other or further exercise thereof or the exercise of any other right or power. The rights and remedies of the Administrative Agent, the Collateral Agent, the Issuing Bank and the Lenders hereunder and under the other Loan Documents are cumulative and are not exclusive of any rights or remedies that they would otherwise have. No waiver of any provision of this Agreement or any other Loan Document or consent to any departure by the Borrower or any other Loan Party therefrom shall in any event be effective unless the same shall be permitted by paragraph (b) below, and then such waiver or consent shall be effective only in the specific instance and for the purpose for which given. No notice or demand on the Borrower in any case shall entitle the Borrower to any other or further notice or demand in similar or other circumstances, except as expressly provided in this Agreement or any other Loan Document.

(b) Neither this Agreement nor any provision hereof may be waived, amended or modified except pursuant to an agreement or agreements in writing entered into by the Borrower and the Required Lenders; provided, however, that no such agreement shall (i) decrease the principal amount of, or extend the maturity of or any scheduled principal payment date or date for the payment of any interest on any Loan or any date for reimbursement of an L/C Disbursement, or waive or excuse any such payment or any part thereof, or decrease the rate of interest on any Loan or L/C Disbursement, or waive or excuse the payment of (or extend the date for payment of) any prepayment fee, or reduce the amount thereof, without the prior written consent of each Lender affected thereby, (ii) increase or extend the Commitment of any Lender or decrease or extend the date for payment of any Fees to any Lender without the prior written consent of such Lender, (iii) amend or modify the pro rata requirements of Section 2.17, the provisions of Section 9.04(j) or the provisions of this Section, or release any Guarantor (other than in connection with a transaction permitted hereunder) or all or substantially all of the Collateral, without the prior written consent of each Lender, (iv) change the provisions of any Loan Document in a manner that by its terms adversely affects the rights in respect of payments due to Lenders holding Loans of one Class differently from the rights of Lenders holding Loans of any other Class without the prior written consent of Lenders holding a majority in interest of the outstanding Loans and unused Commitments of each adversely affected Class, (v) modify the protections afforded to an SPC pursuant to the provisions of Section 9.04(i) without the written consent of such SPC or (vi) reduce the percentage contained in the definition of the term “Required Lenders” without the prior written consent of each Lender (it being understood that with the consent of the Required Lenders, additional extensions of credit pursuant to this Agreement may be included in the determination of the Required Lenders on substantially the same basis as the Term Loan Commitments and Revolving Credit Commitments on the date hereof); provided further that no such agreement shall amend, modify or otherwise affect the rights or duties of the Administrative Agent, the Collateral Agent or the Issuing Bank hereunder or under any other Loan Document without the prior written consent of the Administrative Agent, the Collateral Agent or the Issuing Bank.

82

SECTION 9.09. Interest Rate Limitation. Notwithstanding anything herein to the contrary, if at any time the interest rate applicable to any Loan or participation in any L/C Disbursement, together with all fees, charges and other amounts which are treated as interest on such Loan or participation in such L/C Disbursement under applicable law (collectively the “Charges”), shall exceed the maximum lawful rate (the “Maximum Rate”) which may be contracted for, charged, taken, received or reserved by the Lender holding such Loan or participation in accordance with applicable law, the rate of interest payable in respect of such Loan or participation hereunder, together with all Charges payable in respect thereof, shall be limited to the Maximum Rate and, to the extent lawful, the interest and Charges that would have been payable in respect of such Loan or participation but were not payable as a result of the operation of this Section 9.09 shall be cumulated and the interest and Charges payable to such Lender in respect of other Loans or participations or periods shall be increased (but not above the Maximum Rate therefor) until such cumulated amount, together with interest thereon at the Federal Funds Effective Rate to the date of repayment, shall have been received by such Lender.

SECTION 9.10. Entire Agreement. This Agreement, the Fee Letter and the other Loan Documents constitute the entire contract between the parties relative to the subject matter hereof. Any other previous agreement among the parties with respect to the subject matter hereof is superseded by this Agreement, the Fee Letter and the other Loan Documents. Nothing in this Agreement or in the other Loan Documents, expressed or implied, is intended to confer upon any person (other than the parties hereto and thereto, their respective successors and assigns permitted hereunder (including any Affiliate of the Issuing Bank that issues any Letter of Credit) and, to the extent expressly contemplated hereby, the Related Parties of each of the Administrative Agent, the Collateral Agent, the Issuing Bank and the Lenders) any rights, remedies, obligations or liabilities under or by reason of this Agreement or the other Loan Documents.

SECTION 9.11. WAIVER OF JURY TRIAL. EACH PARTY HERETO HEREBY WAIVES, TO THE FULLEST EXTENT PERMITTED BY APPLICABLE LAW, ANY RIGHT IT MAY HAVE TO A TRIAL BY JURY IN RESPECT OF ANY LITIGATION DIRECTLY OR INDIRECTLY ARISING OUT OF, UNDER OR IN CONNECTION WITH THIS AGREEMENT OR ANY OF THE OTHER LOAN DOCUMENTS. EACH PARTY HERETO (A) CERTIFIES THAT NO REPRESENTATIVE, AGENT OR ATTORNEY OF ANY OTHER PARTY HAS REPRESENTED, EXPRESSLY OR OTHERWISE, THAT SUCH OTHER PARTY WOULD NOT, IN THE EVENT OF LITIGATION, SEEK TO ENFORCE THE FOREGOING WAIVER AND (B) ACKNOWLEDGES THAT IT AND THE OTHER PARTIES HERETO HAVE BEEN INDUCED TO ENTER INTO THIS AGREEMENT AND THE OTHER LOAN DOCUMENTS, AS APPLICABLE, BY, AMONG OTHER THINGS, THE MUTUAL WAIVERS AND CERTIFICATIONS IN THIS SECTION 9.11.

SECTION 9.12. Severability. In the event any one or more of the provisions contained in this Agreement or in any other Loan Document should be held invalid, illegal or unenforceable in any respect, the validity, legality and enforceability of the remaining provisions contained herein and therein shall not in any way be affected or impaired thereby (it being understood that the invalidity of a particular provision in a particular jurisdiction shall not in and of itself affect the validity of such provision in any other jurisdiction). The parties shall endeavor in good-faith negotiations to replace the invalid, illegal or unenforceable provisions with valid provisions the economic effect of which comes as close as possible to that of the invalid, illegal or unenforceable provisions.

83

SECTION 9.13. [Intentionally Omitted].

SECTION 9.14. Headings. Article and Section headings and the Table of Contents used herein are for convenience of reference only, are not part of this Agreement and are not to affect the construction of, or to be taken into consideration in interpreting, this Agreement.

SECTION 9.15. Jurisdiction; Consent to Service of Process. (a) The Borrower hereby irrevocably and unconditionally submits, for itself and its property, to the exclusive jurisdiction of any New York State court or Federal court of the United States of America sitting in New York City, and any appellate court from any thereof, in any action or proceeding arising out of or relating to this Agreement or the other Loan Documents, or for recognition or enforcement of any judgment, and each of the parties hereto hereby irrevocably and unconditionally agrees that all claims in respect of any such action or proceeding may be heard and determined in such New York State or, to the extent permitted by law, in such Federal court. Each of the parties hereto agrees that a final judgment in any such action or proceeding shall be conclusive and may be enforced in other jurisdictions by suit on the judgment or in any other manner provided by law. Nothing in this Agreement shall affect any right that the Administrative Agent, the Collateral Agent, the Issuing Bank or any Lender may otherwise have to bring any action or proceeding relating to this Agreement or the other Loan Documents against the Borrower or its properties in the courts of any jurisdiction.

(b) The Borrower hereby irrevocably and unconditionally waives, to the fullest extent it may legally and effectively do so, any objection which it may now or hereafter have to the laying of venue of any suit, action or proceeding arising out of or relating to this Agreement or the other Loan Documents in any New York State or Federal court. Each of the parties hereto hereby irrevocably waives, to the fullest extent permitted by law, the defense of an inconvenient forum to the maintenance of such action or proceeding in any such court.

(c) Each party to this Agreement irrevocably consents to service of process in the manner provided for notices in Section 9.01. Nothing in this Agreement will affect the right of any party to this Agreement to serve process in any other manner permitted by law; provided that notice of the use of any such alternative means of service shall be provided to each affected party in the manner provided in Section 9.01.

SECTION 9.16. Confidentiality. Each of the Administrative Agent, the Collateral Agent, the Issuing Bank and the Lenders agrees to maintain the confidentiality of the Information (as defined below), except that Information may be disclosed (a) to its and its Affiliates’ officers, directors, employees and agents, including accountants, legal counsel and other advisors (it being understood that the persons to whom such disclosure is made will be informed of the confidential nature of such Information and instructed to keep such Information confidential), (b) to the extent requested by any regulatory authority or quasi-regulatory authority (such as the National Association of Insurance Commissioners), (c) to the extent required by applicable laws or regulations or by any subpoena or similar legal process, (d) in connection with the exercise of any remedies hereunder or under the other Loan Documents or any suit, action or

84

proceeding relating to the enforcement of its rights hereunder or thereunder, (e) subject to an agreement containing provisions substantially the same as those of this Section 9.16, to (i) any actual or prospective assignee of or participant in any of its rights or obligations under this Agreement and the other Loan Documents or (ii) any actual or prospective counterparty (or its advisors) to any swap or derivative transaction relating to the Borrower or any Subsidiary or any of their respective obligations, (f) with the consent of the Borrower or (g) to the extent such Information becomes publicly available other than as a result of a breach of this Section 9.16. For the purposes of this Section, “Information” shall mean all information received from the Borrower and related to the Borrower or its business, other than any such information that was available to the Administrative Agent, the Collateral Agent, the Issuing Bank or any Lender on a nonconfidential basis prior to its disclosure by the Borrower; provided that, in the case of Information received from the Borrower after the date hereof, such information is clearly identified at the time of delivery as confidential. Any person required to maintain the confidentiality of Information as provided in this Section 9.16 shall be considered to have complied with its obligation to do so if such person has exercised the same degree of care to maintain the confidentiality of such Information as such person would accord its own confidential information.

SECTION 9.17. USA Patriot Act Notice. Each Lender and the Administrative Agent (for itself and not on behalf of any Lender) hereby notifies the Borrower that pursuant to the requirements of the USA Patriot Act, it is required to obtain, verify and record information that identifies the Borrower, which information includes the name and address of the Borrower and other information that will allow such Lender or the Administrative Agent, as applicable, to identify the Borrower in accordance with the USA Patriot Act.

SECTION 9.18. Parallel Debt. (a) Notwithstanding anything to the contrary contained in this Agreement and the other Loan Documents and solely for the purpose of ensuring and preserving the validity and effect of the security rights granted and to be granted under or pursuant to the Security Documents governed by the laws of The Netherlands (the “Dutch Security Agreements”), each of the Lenders and the other parties hereto hereby acknowledges and consents to (i) each Loan Party that is party to the Dutch Security Agreements undertaking herein to pay to the Collateral Agent, in its individual capacity and not as agent, representative or trustee, as a separate independent obligation to the Collateral Agent, the amount of its Dutch Parallel Debt (which each such Loan Party hereby so undertakes to do), and (ii) the security rights contemplated by the Dutch Security Agreements being granted in favor of the Collateral Agent in its individual capacity as security for its claims under the Dutch Parallel Debt.

(b) Each Loan Party acknowledges and agrees that it may not pay its Dutch Parallel Debt other than at the instruction of, and in the manner instructed by, the Collateral Agent; provided, however, that no Loan Party shall be obligated to pay any amount of its Dutch Parallel Debt unless and until a corresponding amount of its Underlying Debt Obligations shall have become due and payable.

(c) To the extent any amount is paid to and received by the Collateral Agent in payment of the Dutch Parallel Debt and the Collateral Agent has turned over any amounts received by it in respect to the Dutch Parallel Debt to the Lenders as their interests appeared with respect to the Underlying Debt Obligations, the total amount due and payable in respect of the Underlying Debt Obligations shall be decreased as if such amount were received by the Lenders or any of them in payment of the corresponding Underlying Debt Obligations.

85

SECTION 9.19. Effect of Restatement. This Agreement shall, except as otherwise expressly set forth herein, supersede the Existing Credit Agreement from and after the Restatement Date with respect to the Loans outstanding under the Existing Credit Agreement as of the Restatement Date. The parties hereto acknowledge and agree, however, that (a) this Agreement and all other Loan Documents executed and delivered herewith do not constitute a novation, payment and reborrowing or termination of the Obligations under the Existing Credit Agreement and the other Loan Documents as in effect prior to the Restatement Date, (b) such Obligations are in all respects continuing with only the terms being modified as provided in this Agreement and the other Loan Documents, (c) the liens and security interests in favor of the Collateral Agent for the benefit of the Secured Parties securing payment of such Obligations are in all respects continuing and in full force and effect with respect to all Obligations (except as otherwise expressly provided for in the Amendment Agreement) and (d) all references in the other Loan Documents to the Credit Agreement shall be deemed to refer without further amendment to this Agreement.

86

EX-23.1

Exhibit 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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

/s/ Deloitte & Touche LLP

Deloitte & Touche LLP

Houston, Texas

March 1, 2007

EX-23.2

Exhibit 23.2

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS

We hereby consent to the use of the name Ryder Scott Company, L.P. and of references to Ryder Scott Company, L.P. and to the inclusion of and references to our reports, or information contained therein, dated February 22, 2007, prepared for ATP Oil & Gas Corporation annual report on Form 10-K for the year ended 31^st December 2006, and the incorporation by reference to the report prepared by Ryder Scott Company, L.P. into ATP Oil & Gas Corporation’s previously filed Registration Forms S-3 (Nos. 333-105699 and 333-121662) and on Form S-8 (No. 333-60762).

/s/ Ryder Scott Company, L.P.

Ryder Scott Company, L.P.

March 1, 2007

EX-23.3

Exhibit 23.3

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS

We hereby consent to the use of the name RPS Energy and of references to RPS Energy and to the inclusion of and references to our report, or information contained therein, dated 13 February 2007, prepared for ATP Oil & Gas (UK) Limited in the ATP Oil & Gas Corporation annual report on Form 10-K for the year ended 31^st December 2006, and the incorporation by reference to the report prepared by RPS Energy into ATP Oil & Gas Corporation’s previously filed Registration Forms S-3 (Nos. 333-105699 and
333-121662) and on Form S-8 (No. 333-60762).

RPS Energy Limited

26 February 2007

EX-23.4

Exhibit 23.4

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS

We hereby consent to the use of the name Collarini Associates and of references to Collarini Associates and to the inclusion of and references to our report, or information contained therein, dated 21^st February 2007, prepared for ATP Oil & Gas Corporation annual report on Form 10-K for the year ended 31^st December 2006, and the incorporation by reference to the report prepared by Collarini Associates into ATP Oil & Gas Corporation’s previously filed Registration Forms S-3 (Nos. 333-105699 and 333-121662) and on Form S-8 (No. 333-60762).

Collarini Associates

/s/ Mitchell C. Reece P.E.

Mitchell C. Reece P.E.

Vice President

23^rd February 2007

EX-23.5

Exhibit 23.5

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS

We hereby consent to the reference to DeGolyer and MacNaughton, to the incorporation of the information contained in our “Appraisal Report as of December 31, 2006 on Certain Properties owned by ATP Oil & Gas Corporation” (our Report), and to references to our Report in the Annual Report on Form 10-K of ATP Oil & Gas Corporation for the year ended December 31, 2006 In addition, we hereby consent to the incorporation by reference of such reference to DeGolyer and MacNaughton and to our Report in ATP Oil & Gas Corporation’s previously filed Registration Statements on Form S-3 (Nos. 333-105699 and 333-121662) and on Form S-8 (No. 333-60762).

Very truly yours,

/s/ DeGolyer and McNaughton

DeGolyer and MacNaughton

March 1, 2007

EX-31.1

EXHIBIT 31.1

ATP OIL & GAS CORPORATION

Section 302 Certification of Principal Executive Officer

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

1. I have reviewed this Form 10-K for the annual period ended December 31, 2006 of ATP Oil & Gas Corporation;

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

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

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

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

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

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

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

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

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

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

Date:	March 1, 2007	/s/ T. Paul Bulmahn
		CEO & President

EX-31.2

EXHIBIT 31.2

ATP OIL & GAS CORPORATION

Section 302 Certification of Principal Financial Officer

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

1. I have reviewed this Form 10-K for the annual period ended December 31, 2006 of ATP Oil & Gas Corporation;

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

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

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

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

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

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

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

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

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

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

Date:	March 1, 2007	/s/ Albert L. Reese
		Chief Financial Officer

EX-32.1

Exhibit 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

I, T. Paul Bulmahn, Chairman and Chief Executive Officer of ATP Oil & Gas Corporation (the "Company"), do hereby certify that the Annual Report on Form 10-K (the “Report”) for the year ended December 31, 2006, filed with the Securities Exchange Commission on the date hereof:

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

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

Date: March 1, 2007	By:	/s/ T. Paul Bulmahn
		T. Paul Bulmahn Chairman, Chief Executive Officer and President

EX-32.2

Exhibit 32.2

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

I, Albert L. Reese, Jr., Chief Financial Officer of ATP Oil & Gas Corporation (the "Company"), do hereby certify that the Annual Report on Form 10-K (the “Report”) for the quarter ended December 31, 2006, filed with the Securities Exchange Commission on the date hereof:

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

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

March 1, 2007	By:	/s/ Albert L. Reese, Jr.
		Albert L. Reese, Jr. Chief Financial Officer