Attached files

file filename
EX-23.3 - CONSENT OF COLLARINI ASSOCIATES - ATP OIL & GAS CORPdex233.htm
EX-23.6 - MANAGEMENT REPORT OF RYDER SCOTT COMPANY, L.P. - GULF OF MEXICO - ATP OIL & GAS CORPdex236.htm
EX-23.4 - CONSENT OF RYDER SCOTT COMPANY, L.P. - ATP OIL & GAS CORPdex234.htm
EX-23.5 - MANAGEMENT REPORT OF COLLARINI ASSOCIATES - ATP OIL & GAS CORPdex235.htm
EX-32.1 - SECTION 906 CERTIFICATION OF CEO - ATP OIL & GAS CORPdex321.htm
EX-31.2 - SECTION 302 CERTIFICATION OF CFO - ATP OIL & GAS CORPdex312.htm
EX-23.2 - CONSENT OF DELOITTE & TOUCHE LLP - ATP OIL & GAS CORPdex232.htm
EX-23.7 - MANAGEMENT REPORT OF RYDER SCOTT COMPANY, L.P. - NETHERLANDS - ATP OIL & GAS CORPdex237.htm
EX-23.1 - CONSENT OF PRICEWATERHOUSECOOPERS LLP - ATP OIL & GAS CORPdex231.htm
EX-31.1 - SECTION 302 CERTIFICATION OF CEO - ATP OIL & GAS CORPdex311.htm
EX-32.2 - SECTION 906 CERTIFICATION OF CFO - ATP OIL & GAS CORPdex322.htm
Table of Contents
Index to Financial Statements

 

 

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, 2009

or

 

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

Commission file number: 001-32647

 

 

ATP Oil & Gas Corporation

(Exact name of registrant as specified in its charter)

 

 

 

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

4600 Post Oak Place, Suite 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 whether the Registrant has submitted electronically and posted on its corporate website, if any, every interactive Data File required to be submitted electronically and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or such shorter period that Registrant was required to post such files).    Yes  ¨    No  ¨

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

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

 

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

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

The aggregate market value of the voting and non-voting common stock held by non-affiliates of the Registrant as of June 30, 2009 (the last business day of the Registrant’s most recently completed second fiscal quarter) was approximately $259.9 million. The number of shares of the Registrant’s common stock outstanding as of March 2, 2010 was 50,779,370.

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, 2009, are incorporated by reference in Part III of this Form 10-K.

 

 

 


Table of Contents
Index to Financial Statements

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

2009 FORM 10-K ANNUAL REPORT

TABLE OF CONTENTS

 

              Page

Part I

  
 

Item 1.

  

Business

   7
 

Item 1A.

  

Risk Factors

   14
 

Item 1B.

  

Unresolved Staff Comments

   23
 

Item 2.

  

Properties

   24
 

Item 3.

  

Legal Proceedings

   28
 

Item 4.

  

(Removed and Reserved)

   28

Part II

  
 

Item 5.

  

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

   28
 

Item 6.

  

Selected Financial Data

   31
 

Item 7.

  

Management’s Discussion and Analysis of Financial Condition and Results of Operations

   33
 

Item 7A.

  

Quantitative and Qualitative Disclosures about Market Risk

   51
 

Item 8.

  

Financial Statements and Supplementary Data

   52
 

Item 9.

  

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

   52
 

Item 9A.

  

Controls and Procedures

   52
 

Item 9B.

  

Other Information

   52

Part III

  
 

Item 10.

  

Directors, Executive Officers and Corporate Governance

   53
 

Item 11.

  

Executive Compensation

   54
 

Item 12.

  

Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

   54
 

Item 13.

  

Certain Relationships and Related Transactions, and Director Independence

   54
 

Item 14.

  

Principal Accounting Fees and Services

   54

Part IV

  
 

Item 15.

  

Exhibits, Financial Statement Schedules

   55

 

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Cautionary Statement About Forward-Looking Statements

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

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

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

 

   

projected operating or financial results;

 

   

timing and expectations of financing activities;

 

   

budgeted or projected capital expenditures;

 

   

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

 

   

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

 

   

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

 

   

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

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

 

   

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

 

   

the volatility in oil and natural gas prices;

 

   

the timing of planned capital expenditures;

 

   

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

 

   

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

 

   

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

 

   

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

 

   

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

 

   

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

 

   

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

 

   

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

 

   

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

 

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Index to Financial Statements
   

interest payment requirements on our debt obligations;

 

   

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

 

   

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

 

   

our price risk management decisions;

 

   

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

 

   

insufficient insurance coverage;

 

   

foreign currency fluctuations;

 

   

rapid production declines in our Gulf of Mexico properties;

 

   

substantial impairment write-downs;

 

   

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

 

   

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

 

   

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

 

   

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

 

   

rapid growth may place significant demands on our resources; and

 

   

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

 

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Index to Financial Statements

CERTAIN DEFINITIONS

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

 

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

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

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

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

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

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

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

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

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

Proved reserves are the estimated quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible – from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations. Reservoirs are considered proved if shown to be economically producible by either actual production or conclusive formation tests. See Regulation S-X, Rule 4-10(a)(22)-(26), (Reg. § 210.4-10) available on the Internet at www.sec.gov/divisions/corpfin/ecfrlinks.shtml.

 

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Proved developed reserves are the portion of proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well.

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

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

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

 

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Index to Financial Statements

PART I

 

Item 1. Business.

General

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

At December 31, 2009, we had estimated net proved reserves of 135.2 MMBoe, of which approximately 91.3 MMboe (68%) were in the Gulf of Mexico and 43.9 MMBoe (32%) were in the North Sea. Year-end reserves were comprised of 77.9 MMBbls of oil (58%) and 343.3 Bcf of natural gas (42%). As of December 31, 2009 our proved reserves in the deepwater Gulf of Mexico account for [62%] of our total proved reserves. Our proved reserves on the Gulf of Mexico Shelf account for [6%] of our total proved reserves. The majority (67%) of our oil reserves are located in the Gulf of Mexico. Our natural gas reserves are split between the Gulf of Mexico (68%) and the North Sea (32%). Of our total proved reserves, 13.7 MMBoe (10%) were producing, 3.7 MMBoe (3%) were developed and not producing and 117.8 MMBoe (87%) were undeveloped. Our average working interest in our properties at December 31, 2009 was approximately 80%. We operate 86% of our platforms. The estimated PV-10 of our proved reserves at December 31, 2009 was approximately $2.0 billion. See “Item 2. Properties – Oil and Natural Gas Reserves” for a reconciliation to our standardized measure of discounted future net cash flows.

At December 31, 2009, we owned leasehold and other interests in 62 offshore blocks and 104 wells, including 19 subsea wells, in the Gulf of Mexico. We operate 93 (89%) of these wells, including 95% of the subsea wells. We also had interests in 11 blocks and three company-operated subsea wells in the North Sea.

As of the date of this report, we own an interest in [36] platforms including two floating production facilities, the ATP Innovator and the ATP Titan. The ATP Innovator is operating in the Gulf of Mexico at our Gomez Hub and the ATP Titan in the Gulf of Mexico at our Telemark Hub is expected to begin operating during March 2010. These floating production facilities are fundamental to our hub strategy and business plan. The presence of these facilities allows us a competitive advantage for additional acquisitions in a large area surrounding each installation. A third floating production facility called an Octabuoy is under construction in China for initial deployment at our Cheviot Hub in the U.K. North Sea during 2012. We operate the ATP Innovator and the ATP Titan and also expect to operate the Octabuoy when it is placed in service. The floating production facilities have longer useful lives than the underlying reserves and are capable of redeployment to new producing locations upon depletion of the reserves. Accordingly they are expected eventually to be moved several times over their useful lives.

Our Business Strategy

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

 

   

significant undeveloped reserves and reservoirs;

 

   

close proximity to developed markets for oil and natural gas;

 

   

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

 

   

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

 

   

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

 

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Our focus is on acquiring properties that are noncore or nonstrategic to their current owners for a variety of reasons. For example, larger oil companies from time to time adjust their capital spending or shift their focus to exploration prospects they believe will offer greater reserve potential. Some projects may provide lower economic returns to a company due to the cost structure and focus of that company. Also, due to timing or budget constraints, a company may be unwilling or unable to develop a property before the expiration of the lease. With our cost structure and acquisition strategy, it is not unusual for us to have an acquisition cost of a property that is less than the total development costs incurred by the previous owner. This strategy, coupled with our expertise in our areas of focus and our successful ability to develop projects, tend to make our oil and gas property acquisitions more financially attractive to us than the seller. Given our strategy of acquiring properties that contain proved reserves or where previous drilling by others indicates to us the presence of recoverable hydrocarbons, our operations typically are lower risk than exploration-focused Gulf of Mexico and North Sea operators.

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. 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. For the three-year period ended December 31, 2009, we added 10.1 MMBoe of proved oil and natural gas reserves through acquisitions at a total cost of $44.2 million. Development costs for the same period were approximately $2,469.3 million or 91% of oil and gas capital expenditures. Additional detail of our costs incurred and changes in reserve estimates is set forth in our financial statements under the caption “Supplemental Disclosures About Oil and Gas Producing Activities.”

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

Our Strengths

 

   

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

 

   

Significant Infrastructure Investment at our Hubs. With over $1.0 billion already invested in infrastructure at our Gomez Hub and our Telemark Hub, it is our belief that we have a significant competitive advantage to expand our interest in the area over other production companies in these areas that do not have such an investment.

 

   

Technical Expertise and Significant Experience. We have assembled a technical staff with an average of over 27 years of industry experience. Our technical staff has specific expertise in the Gulf of Mexico and North Sea offshore property development, including the implementation of subsea completion technology.

 

   

Operating Control. As the operator of a property, we are afforded greater control of the selection of completion and production equipment, the timing and amount of capital expenditures and the operating parameters and costs of the project. As of December 31, 2009, we operated all of our properties under development, all of our subsea wells and 86% of our offshore platforms.

 

   

Employee Ownership. Through employee ownership of company stock, we have assembled a staff whose business decisions are aligned with the interests of our shareholders. As of March 2, 2010, our executive officers and directors own approximately 13% of our common stock.

 

   

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

 

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Marketing and Delivery Commitments

We sell crude oil and natural gas production under price sensitive or market price contracts. Our revenues, profitability and future growth depend substantially on prevailing prices for oil and natural gas. The price received by us for such production can fluctuate widely. Changes in the prices of oil and natural gas will affect our proved reserves as well as our revenues, profitability and cash flow. Additionally, 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.

Historically, we have sold our oil and natural gas production to a relatively small number of purchasers. Due to the nature of oil and natural gas markets and because oil and natural gas are commodities and there are numerous purchasers in the areas in which we sell production, we do not believe the loss of a single purchaser, or a few purchasers, would materially affect our ability to sell our production. For the year ended December 31, 2009, revenues from four purchasers accounted for 39%, 33%, 13% and 7%, respectively, of oil and gas production revenues.

Competition

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

Regulation

Gulf of Mexico

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

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

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

 

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access to such transportation. In furtherance of this mandate, MMS, in 2008, issued regulations establishing a process for a shipper transporting oil or gas production from OCS leases to follow if it believes it has been denied open and non-discriminatory access to pipelines on the OCS and the remedies that MMS may impose on a transporter that MMS has determined to have denied open or non-discriminatory access to an OCS shipper.

Additional proposals and proceedings that might affect the natural gas industry are pending before FERC and the courts. For example, the Federal Energy Policy Act, signed into law in August 2005, contains various provisions designed to increase the level of competition and transparency in FERC-regulated natural gas markets (e.g. one such provision implemented by FERC in its regulations makes market-based rate authority generally available to new interstate natural gas storage facilities). Those provisions are now in various stages of implementation by FERC. The natural gas industry historically has been very heavily regulated; therefore, there is no assurance that the less stringent regulatory approach pursued by FERC will continue. 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.

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

For offshore operations, lessees must obtain MMS approval for exploration, development and production plans prior to the commencement of such operations. In addition to permits required from other agencies such as the Coast Guard, the Army Corps of Engineers and the Environmental Protection Agency, lessees must obtain a permit from the MMS prior to the commencement of drilling. The MMS has promulgated regulations requiring offshore production facilities located on the Outer Continental Shelf to meet stringent engineering and construction specifications. The MMS also has regulations restricting the flaring or venting of natural gas, and has proposed to amend such regulations to prohibit the flaring of liquid hydrocarbons and oil without prior authorization. Similarly, the MMS has promulgated other regulations governing the plugging and abandonment of wells located offshore and the installation, operation, 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. Crude oil sale transactions not at arm’s-length are valued, for purposes of royalty calculation, based on NYMEX prices adjusted for locality and quality differentials, and clarifying the treatment of transactions under a joint operating agreement.

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 nondiscriminatory 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

 

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methodology. Under this indexing methodology, pipeline rates are subject to changes in the Producer Price Index for Finished Goods. A pipeline can seek to increase its rates above index levels provided that the pipeline can establish that there is a substantial divergence between the actual costs experienced by the pipeline and the rate resulting from application of the index. A pipeline can seek to charge market-based rates if it establishes that it lacks significant market power. In addition, a pipeline can establish rates pursuant to settlement if agreed upon by all current shippers. A pipeline can seek to establish initial rates for new services through a cost-of-service proceeding, a market-based rate proceeding, or through an agreement between the pipeline and at least one shipper not affiliated with the pipeline. As provided for in Order No. 561, the FERC’s indexing methodology is subject to review at five-year intervals.

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

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

Environmental Regulations. Our operations are subject to stringent laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. These laws and regulations may require the acquisition of a permit before drilling commences, restrict the types, quantities and concentration of various substances that can be released into the environment, and impose substantial liabilities for pollution. Failure to comply with these laws and regulations may result in the assessment of administrative, 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.

The Oil Pollution Act of 1990, also known as “OPA,” and related regulations impose a variety of regulations on “responsible parties” related to the prevention of oil spills and liability for damages resulting from such spills in navigable waters, adjoining shorelines or in the exclusive economic zone of the United States. 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 ($10.0 million if the offshore facility is located landward of the seaward boundary of a state) to address oil spills and associated damages, with this financial assurance amount increasing up to $150.0 million in certain limited circumstances depending on the risk represented by the quantity or quality of oil that is handled by the facility. We carry insurance coverage to meet these obligations. The OPA also imposes other requirements, such as the preparation of an oil spill contingency plan. A failure to comply with OPA’s requirements or inadequate cooperation during a spill response action may subject a responsible party to civil or criminal enforcement actions. We are not aware of any action or event that would subject us to liability under OPA, and we believe that compliance with OPA’s financial responsibility and other operating requirements will not have a material adverse affect on us.

We are also regulated by the Clean Water Act, which prohibits any discharge of pollutants into waters of the U.S. except in conformance with discharge permits issued by federal or state agencies. Further, the EPA

 

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

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

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

The Safe Drinking Water Act (“SDWA”) regulates the underground injection of fluid (such as the reinjection of brine produced and separated from oil and natural gas production) through a well. The SDWA of 1974, as amended establishes a regulatory framework for underground injection, with the main goal being the protection of usable aquifers. The primary objective of injection well operating requirements is to ensure the mechanical integrity of the injection apparatus and to prevent migration of fluids from the injection zone into underground sources of drinking water. Hazardous-waste injection well operations are strictly controlled and certain wastes, absent an exemption, cannot be injected into underground injection control wells. Failure to abide by our permits could subject us to civil and/or criminal enforcement. We believe that we are in compliance in all material respects with the requirements of applicable state underground injection control programs and our permits.

We may also incur liability under the Resource Conservation and Recovery Act, 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 wastes under CERCLA, RCRA, and analogous state laws. Under such laws, we could be required to remediate previously disposed wastes or to perform remedial operations to prevent future contamination.

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 any more burdensome to us than to other companies our size involved in similar natural gas and oil development and production activities.

 

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North Sea

Our properties in the U.K. sector represent virtually all of our total proved reserves in the North Sea. Related government regulations in the U.K. are discussed below.

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 Energy and Climate Change (the “Secretary of State”) a consent to commence field development. We would be required to obtain the consent of the Secretary of State prior to transferring an interest in a license.

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

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

Environmental Regulations. Our operations are subject to environmental laws and regulations imposed by both the European Union and the U.K. government. The offshore industry in the U.K. is regulated with regard to the environment before and during the conduct of exploration and production activities. The licensing 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 Energy and Climate Change, will consult with various public bodies having responsibility for the environment. Applicants for production licenses are required to submit a statement of the general environmental policy of the operator in respect of the contemplated license activities and a summary of its management systems for implementation of that policy and how those systems will be applied to the proposed work program. In addition, the Offshore Petroleum Production and Pipe-lines (Assessment of Environmental Effects) Regulations 1999, require the Secretary of State to exercise his licensing powers under the Petroleum Act 1998 in such a way to ensure that an environmental assessment is undertaken and considered before consent is given to certain projects.

Petroleum production licenses require the prior approval of the Secretary of State of a licensee to act as operator. The operator under a license organizes or supervises all or any of the development and production operations of 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.

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

 

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

Compliance

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

Employees

At December 31, 2009 we had 53 full-time employees in our Houston office, 8 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, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to such reports filed or furnished pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934, as amended, as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC. Information contained on our website is not part of this report. Also, the SEC maintains an internet site (http://www.sec.gov) that contains reports, proxy and other information about the Company. The Company will provide a copy of the Form 10-K annual report upon the written request of any shareholder. Financial information regarding our operating segments is set forth in Note 16, “Segment Information” of the Notes to Consolidated Financial Statements.

 

Item 1A. Risk Factors.

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

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

We have 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 development and exploration of our oil and gas reserves. Acquisitions and abandonment of oil and gas properties and meeting our debt service obligations account for a portion of capital requirements. Cash paid for capital expenditures for oil and gas properties was approximately $635.3 million, $917.5 million and $849.5 million for the years ended December 31, 2009, 2008 and 2007, respectively. Development and exploration costs accounted for 100%, 100%, and 96%, respectively, of the total capital expenditures during those three years. During 2010, we plan to finance anticipated expenses, debt service, development, exploration, acquisition and abandonment requirements with available cash, funds generated by operating activities and, potentially, net cash proceeds from the sales of assets and capital market transactions.

We have been dependent on debt and equity financing to fund our cash needs that were not funded from operations or the sale of assets. Since mid-2008, the capital markets in the United States and the remainder of the world have been in disarray. There have been capital market transactions completed, but they have been very expensive compared to historical levels. In addition, low commodity prices, production problems,

 

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disappointing drilling results and other factors beyond our control could reduce our funds from operations and may restrict our ability to obtain additional financing or to pay interest and principal on our debt obligations. Furthermore, we have incurred losses in the past that may affect our ability to obtain financing. Quantifying or predicting the likelihood of any or all of these occurring is difficult in the current domestic and world economy. For these reasons, financing may not be available to us in the future on acceptable terms or at all. In the event additional capital is required but not available on acceptable terms, we would curtail our acquisition, drilling, development and other activities or could be forced to sell some of our assets on an untimely or unfavorable basis.

We have debt, trade payables, other long-term obligations, related interest payment requirements and certain properties which are burdened by net profits interests and overriding royalty interests that may restrict our future operations and impair our ability to meet our obligations.

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

 

   

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

 

   

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

 

   

increase our vulnerability to general adverse economic and industry conditions;

 

   

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

 

   

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

 

   

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

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

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

During June 2008, we, Credit Suisse (as Administrative Agent and Collateral Agent for the lenders) and the lenders named therein entered into a new senior secured term loan facility (“Term Loans”) with two tranches of Term Loans. The terms of the Term Loans require us to comply with certain covenants. On November 2, 2009, we entered into an amendment (the “First Amendment”) to the Term Loans to provide additional flexibility during the period from October 1, 2009 through December 31, 2010 (the “Amendment Period”). Among other provisions, the Amendment relaxes the Net Debt to EBITDAX ratio from 3.0 to 4.0, the EBITDAX to Interest ratio from 2.5 times to 2.0 times and the current ratio from 1.0 to 0.8 for the duration of the Amendment Period. The interest rate on the first tranche of Term Loans balance will increase to a minimum 11.25% during the Amendment Period, at the end of which it will decrease to a minimum 9.5% for the remainder of the term. The First Amendment will further increase the rate on the balance outstanding of the second tranche of Term Loans by 2.75% to a minimum 11.75% effective October 1, 2009. Effective January 1, 2010, the minimum rate will decrease by 1.25% to 10.5% until July 1, 2010, at which time any balance that remains outstanding will bear interest at a minimum 11.0%. On each of July 1, 2009 and January 1, 2010, the minimum rate on the second tranche of Term Loans increased by 0.5%, and the rate will continue to increase by 0.5% on each January 1 and July 1 until it is repaid in full. Capitalized terms are defined in the Term Loans. In addition to those mentioned above, remaining covenants include:

 

   

Ratio of pre-tax PV-10 of our total Proved Developed Producing oil and gas reserves using the average of future oil and gas prices for the next three years, to Total Net Debt of at least 0.5 to 1.0 at June 30 and December 31 of any fiscal year;

 

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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 using the average of future oil and gas prices for the next three years, to Total Net Debt of at least 2.5 to 1.0 at June 30 or December 31 of any fiscal year;

 

   

Commodity Hedging Agreements, based on forecasted production attributable to our proved developed producing reserves of (i) 60% of the projected PDP production 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 and (ii) 40% of such projected PDP production on a rolling basis for the twelve calendar month period subsequent to the twelve calendar month period;

 

   

Permitted Business Investments during any fiscal year of no more than $150.0 million or 7.5% of PV-10 value of our total proved reserves;

 

   

Requirement that at least 75% of Net Cash Proceeds from all Asset Sales be applied to the Asset Sale Facility as long as any balance is outstanding on the Asset Sale Facility.

 

   

Restrictions on certain types of payments including dividends or open market purchases of common stock.

On January 29, 2010, we entered into a second amendment (the “Second Amendment”) to the Term Loans to provide us the right to issue unlimited indebtedness in the form of unsecured senior debt, provided that 75% of the net proceeds from any such additional indebtedness are used to repay the outstanding Term Loans.

Additionally, the calculation of trailing-twelve-months EBITDAX, as defined in the Term Loans, was expanded to include, in addition to any amount calculated under the terms of the Term Loans, (i) with respect to, and for any period that includes, the fiscal quarter ended March 31, 2009, $32,086,261, (ii) with respect to, and for any period that includes, the fiscal quarter ended September 30, 2009, $35,767,712, (iii) with respect to, and for any period that includes, the fiscal quarter ended December 31, 2009, $10,926,115 and (iv) with respect to, and for any period that includes, the fiscal quarter ending March 31, 2010, $44,272,499. These amounts represent realized economic gains from certain property transactions during the current and preceding three calendar quarters that did not qualify for gain accounting treatment.

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. There can be no assurance that we will remain in compliance with the covenants under our Term Loans. If 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.

The global financial crisis and economic downturn may materially and adversely impact our financial condition and results of operations in amounts and ways that we currently cannot predict.

During 2007, the U.S., Canada and many other countries began to exhibit signs of economic weakness, which continued throughout 2008 and 2009. This weakness has had an adverse impact on the global financial system, stressing a number of large financial institutions. Capital constraints coupled with significant energy price volatility have produced pervasive liquidity issues for many companies. Such events have created uncertainty in the economic outlook, and have amplified the potential likelihood of certain risks in our business.

The continued credit crisis and related turmoil in the global financial system may have an impact on our industry, our business and our financial condition. This stress in the markets may cause us to face greater challenges if conditions in the financial markets do not improve. Our ability to access the capital markets or to consummate planned asset sales may be restricted at a time when we would like or need to raise capital, impairing our ability to react to changing economic and business conditions, or modifying or interrupting our business plans. The current economic situation could lead to reduced demand for oil and natural gas, or lower prices for oil and natural gas, or both, which could have a negative impact on our revenues, the value of our assets and our ability to meet our obligations. Further, the economic situation could also impact our lenders, customers and hedging counterparties and may cause them to fail to meet their obligations to us with little or no warning.

 

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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. This phenomenon occurred again beginning in 2004 when oil began to climb reaching an all-time high in mid 2008. By the end of 2008, oil had lost nearly two thirds of its value dropping from a high of $146 per barrel in July 2008 to a close of $45 per barrel in December 2008. In February 2009, oil closed at its low for the year of $33.98 per barrel only to rise to its high for the year of $81.37 per barrel in October. Among the factors that have caused and may continue to cause this volatility are:

 

   

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

 

   

the domestic and foreign supply of oil and natural gas;

 

   

the devaluation and subsequent revaluation of the U.S. dollar against other currencies;

 

   

weather conditions;

 

   

domestic and foreign governmental regulations and lack of regulations;

 

   

speculation by non-energy companies buying and selling commodities with no intention to receive physical delivery;

 

   

political conditions in natural gas or oil producing regions;

 

   

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

Estimates of our oil and natural gas reserves and the costs and timing associated with developing these reserves may not be accurate. Additionally, at December 31, 2009, approximately 87% of our total proved reserves are classified as undeveloped. Development of these reserves may not yield the expected results, or the development may be delayed or the development costs may exceed our estimates, any of which may materially affect our financial position and results of operations. Development activity may result in downward adjustments of reserves or higher than estimated costs.

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.

 

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

The size of our operations and our capital expenditure budget limits the number of properties that we can develop in any given year. Complications in the development of any single major well or infrastructure installation may result in a material adverse effect on our financial condition and results of operations. For instance, during 2009, a workover operation at a well in our Gomez Hub took longer to obtain permits than anticipated. As a result, this workover scheduled for completion in the fourth quarter of 2009, was not finished until late January 2010. In 2008, we experienced production delays and increased costs at our High Island A-589 project in the Gulf of Mexico. During 2006 and 2007, we experienced production delays and increased development costs in connection with the development of our Tors wells in the North Sea.

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

Rapid growth may place significant demands on our resources.

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

 

   

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

 

   

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

 

   

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

 

   

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

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

Our success depends on dedicated and skillful management and staff, whose departure could disrupt our business operations.

Our success will depend on our ability to retain and attract experienced geoscientists and other professional staff. As of December 31, 2009, we had 22 engineers, geologist/geophysicists and other technical personnel in our Houston office, three 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.

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

We utilize derivative instruments and fixed-price forward sales contracts with respect to a portion of our expected production, generally not less than 40% or more than 80% of such production in order to manage our exposure to oil and natural gas price volatility. These instruments expose us to risk of financial loss if:

 

   

production is less than expected for forward sales contracts;

 

   

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

 

   

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

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

 

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

Shortages or 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. Increased drilling activity in the Gulf of Mexico and the North Sea decreases the availability of offshore rigs and associated equipment. In periods of increased drilling activity in the Gulf of Mexico and the North Sea, we may experience increases in associated costs, including those related to drilling rigs, equipment, supplies and personnel and the services and products of other vendors to the industry. These costs may increase further and necessary equipment and services may not be available to us at economical prices. For the years ended December 31, 2009, 2008 and 2007, we recorded losses on abandonment of $2.9 million, $13.3 million and $18.6 million, respectively, primarily as a result of unanticipated increases in service costs in the Gulf of Mexico.

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 worker’s compensation laws in dealing with their employees. In addition, pollution and environmental risks generally are not fully insurable.

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

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

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

Our development activities may be unsuccessful for many reasons, including cost overruns, equipment shortages and mechanical difficulties. Moreover, the successful drilling of 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 uneconomic or only marginally economic. In addition to their cost, unsuccessful wells can hurt our efforts to replace reserves.

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

 

   

fires;

 

   

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.

 

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

 

   

injury or loss of life;

 

   

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

 

   

pollution and other environmental damage;

 

   

clean-up responsibilities;

 

   

regulatory investigation and penalties;

 

   

suspension of our operations; and

 

   

repairs to resume operations.

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

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

Reservoirs in the Gulf of Mexico are typically prolific producers due to their high permeability and efficient completions. Reserves can therefore be produced rapidly. As of December 31, 2009, we project normalized decline rates of 21% for oil and 15% for gas in our Gulf of Mexico undeveloped deepwater fields. While this results in recovery of a relatively higher percentage of reserves from Gulf of Mexico properties during the initial years of production, we must incur significant capital expenditures to replace declining production.

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

We may incur substantial impairment write-downs.

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

If management’s estimates of the recoverable reserves on a property are revised downward, if development costs exceed previous estimates or if oil and natural gas prices decline, we may be required to record additional noncash impairment write-downs in the future, which would result in a negative impact to our financial position and earnings. We review our proved oil and gas properties for impairment on a depletable unit basis regularly on each calendar quarter, or whenever events or changes in circumstances indicate that an asset’s carrying amount may not be recoverable. To determine if a depletable unit is impaired, we compare the carrying value of the depletable unit to the undiscounted future net cash flows by applying management’s estimates of future oil and gas prices to the estimated future production of oil and gas reserves over the economic life of the property and deducting estimated future operating and development costs. Future net cash flows are based upon reservoir engineers’ estimates of proved reserves. In addition, other factors such as probable and possible reserves are taken into consideration when justified by economic conditions and actual or planned drilling or other development activities. For a property determined to be impaired, an impairment

 

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loss equal to the excess of the carrying value over the estimated fair value of the impaired property will be recognized. Fair value, on a depletable unit basis, is estimated to be the present value of the aforementioned expected future net cash flows. Any impairments of proved properties are aggregated in accumulated depletion, depreciation, amortization and impairment, and reduce our basis in the asset. Each part of this calculation is subject to a large degree of judgment, including the determination of the depletable units’ estimated reserves, future net cash flows and fair value. We recorded impairments during the years ended December 31, 2009, 2008 and 2007 totaling $44.6 million, $124.7 million and $34.1 million, respectively, on certain proved Gulf of Mexico shelf properties, primarily due to reduced commodity prices and reductions in estimates of recoverable reserves.

Unproved properties are also assessed periodically to determine whether they have been impaired. An impairment allowance is provided on an unproved property when we determine that the property will not be developed, or the development activities undertaken are subsequently determined to be unsuccessful proving the reserves. Impairments of unproved properties were $1.2 million, $0.4 million and $0.2 million during 2009, 2008 and 2007, respectively, related to surrendered leases.

Management’s assumptions used in calculating oil and gas reserves or estimating the future cash flows or fair value of our properties are subject to change in the future at any time as economic conditions change. Any change in reserves volumes or commodity price forecasts will directly impact our estimates of future cash flows from the properties, and consequently each property’s fair value. Any adverse change in these variables could cause impairment expense to be recognized, which would reduce our net income (or increase a net loss) and reduce our basis in the related asset.

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

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 created prior to our purchase of the property. We may be required to assume the risk of the physical condition of the properties in addition to the risk that the properties may not perform in accordance with our expectations.

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

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

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

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

 

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

The terrorist attacks that took place in the 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.

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

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

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

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

The adoption of derivatives legislation by Congress could have an adverse impact on our ability to hedge risks associated with our business.

We enter into a number of commodity derivative contracts in order to hedge a portion of our natural gas production. Congress is currently considering legislation to impose restrictions on certain transactions involving derivatives, which could affect the use of derivatives in hedging transactions. The American Clean Energy and Security Act (“ACESA”) contains provisions that would prohibit private energy commodity derivative and hedging transactions. ACESA would expand the power of the Commodity Futures Trading Commission (“CFTC”) to regulate derivative transactions related to energy commodities, including natural gas and oil, and to mandate clearance of such derivative contracts through registered derivative clearing organizations. Under ACESA, the CFTC’s expanded authority over energy derivatives would terminate upon the adoption of general legislation covering derivative regulatory reform. The CFTC is considering whether to set limits on trading and positions in commodities with finite supply, particularly energy commodities, such as natural gas, crude oil and other energy products. The CFTC also is evaluating whether position limits should be applied consistently across all markets and participants. Separately, two committees of the House of Representatives, the Financial Services and Agriculture Committees, acted on October 15, 2009 and October 21, 2009, respectively, to adopt legislation that would impose comprehensive regulation on the over-the-counter (“OTC”) derivatives marketplace. This legislation would subject swap dealers and major swap participants to substantial supervision and regulation, including capital standards, margin requirements, business conduct standards, and recordkeeping and reporting requirements. It also would require central clearing for transactions entered into between swap dealers or major swap participants, and would provide the CFTC with authority to impose position limits in the OTC derivatives markets. A major swap participant generally would be someone other than a dealer who maintains a “substantial” position in outstanding swaps other than swaps used for commercial hedging, or whose positions create substantial exposure to its counterparties or the system. Although it is not possible at this time to predict whether or when Congress may act on derivatives legislation or how any climate change bill approved by the Senate would be reconciled with ACESA, any laws or regulations that may be adopted that subject us to additional capital or margin requirements relating to, or to additional restrictions on, our commodity risk management positions could have an adverse effect on our ability to hedge risks associated with our business or on the cost of our hedging activity.

 

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

Among the changes contained in the White House budget proposals, released on February 26, 2009, and February 1, 2010, is the elimination of certain key U.S. federal income tax preferences currently available to oil and gas exploration and production companies. Such changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and gas properties; (ii) the elimination of current deductions for intangible drilling and development costs; (iii) the elimination of the deduction for certain U.S. production activities; and (iv) an extension of the amortization period for certain geological and geophysical expenditures. Additionally, the Senate version of the Oil Industry Tax Break Repeal Act of 2009, introduced on April 23, 2009, and the Senate version of the Energy Fairness for America Act, introduced on May 20, 2009, include many of the proposals outlined in the White House budget proposals. It is unclear, however, whether any such changes will be enacted or how soon such changes could be effective.

The passage of any legislation as a result of the budget proposals, either Senate Bill or any other similar change in U.S. federal income tax law could eliminate certain tax deductions that are currently available with respect to oil and gas exploration and development, and any such change could negatively affect our financial condition, results of operation and, thus, our ability to make payments on our outstanding indebtedness.

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

Section 382 of the Internal Revenue Code of 1986, as amended (the “I.R.C.”), generally limits the ability of a corporation that undergoes an “ownership change” to utilize its net operating loss carryforwards (“NOLs”) and certain other tax attributes against future taxable income in periods after the ownership change. The amount of taxable income in each tax year after the ownership change that may be offset by pre-change NOLs and certain other pre-change tax attributes is generally equal to the product of (a) the fair market value of the corporation’s outstanding stock immediately prior to the ownership change and (b) the long-term tax exempt rate (i.e., a rate of interest established by the Internal Revenue Service that fluctuates from month to month). In general, an “ownership change” occurs whenever the percentage of the stock of a corporation owned, directly or indirectly, by “5-percent stockholders” (within the meaning of Section 382 of the I.R.C.) increases by more than 50 percentage points over the lowest percentage of the stock of such corporation owned, directly or indirectly, by such “5-percent stockholders” at any time over the preceding three years.

Our NOLs and certain other tax attributes are already subject to an annual limitation as a result of an ownership change we experienced in November 2007. Changes in our ownership since November 2007, including changes resulting from our June 2009 common equity offering, our September 2009 common equity offering and our September 2009 convertible perpetual preferred stock offering may have already caused a second ownership change, or may result in one in the near future. Another ownership change could dramatically reduce our annual NOL limitation if our equity value at the time of the second ownership change was/is significantly below our equity value as of the November 2007 ownership change. Issuances of our stock, sales or other dispositions of our stock by certain significant stockholders, certain acquisitions of our stock and issuances, sales or other dispositions or acquisitions of interests in certain significant stockholders may have already triggered a second “ownership change,” and, even if no second ownership change has occurred to date, we will have little or no control over any such events in the future. If a second ownership change has already occurred, or were to occur in the future, any further limitation on our use of NOLs and certain other tax attributes to offset our taxable income could result in a significant increase in our future tax liability, and could negatively affect our financial condition, results of operation and our ability to make payments on our outstanding indebtedness.

 

Item 1B. Unresolved Staff Comments.

None

 

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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, 2009, we owned leasehold and other interests in 62 offshore blocks and 104 wells, including 19 subsea wells, in the Gulf of Mexico. We operate 93 (89%) of these wells, including 95% of the subsea wells. We also had interests in 11 blocks and three company-operated subsea wells in the North Sea. Our average working interest in our properties at December 31, 2009 was approximately 80%. As of December 31, 2009, we had leasehold interests located in the Gulf of Mexico and North Sea covering approximately 384,275 gross and 294,280 net acres, respectively, of which 215,778 gross acres (143,582 net acres) were developed.

We own interests in 36 platforms including two floating production facilities, the ATP Innovator and the ATP Titan. The ATP Innovator is operating in the Gulf of Mexico at our Gomez Hub and the ATP Titan is expected to begin operating during March 2010 in the Gulf of Mexico at our Telemark Hub. These floating production facilities are fundamental to our hub strategy and business plan. The presence of these facilities allows us a competitive advantage for additional acquisitions in a large area surrounding each installation. A third floating production facility called an Octabuoy is under construction in China for initial deployment at our Cheviot Hub in the U.K. North Sea in 2012. We operate the ATP Innovator, the ATP Titan and 85% of our other offshore platforms. We expect to operate the Octabuoy when it is placed in service. The floating production facilities have longer useful lives than the underlying reserves and are capable of redeployment to new producing locations upon depletion of the reserves. Accordingly they are expected eventually to be moved several times over their useful lives.

Gulf of Mexico

Acquisitions – During 2009, we paid $0.2 million to acquire a 55.3% working interest in Green Canyon Block 344, a lease with unproved reserves south of our Green Canyon Block 300 property in the Gulf of Mexico (“Clipper”). Also, in exchange for our assumption of any property abandonment obligations and payment to us of $4.8 million, we acquired a partner’s working interests in certain properties in the Gulf of Mexico.

During January 2010, we consummated our December 2009 agreements for a cash-free swap of our interest in Mississippi Canyon (“MC”) Block 800, an exploratory prospect, for a third party’s interests in MC Block 754 and MC Block 710. MC Block 710 is an exploratory prospect adjacent to our Gomez Hub in MC Block 711 and surrounding blocks.

Development – Development activities continued in 2009 at our Telemark Hub in the deepwater Gulf of Mexico. The ATP Titan – a floating drilling and production platform - was sailed to location and moored during December 2009, and is currently in the final stages of completion. In the northern part of the Telemark Hub, the initial drilling of three wells was performed in 2008 at Mirage (MC Block 941) and Morgus (MC Block 942). Once placed in service, the ATP Titan will be used to complete the drilling of the three wells and to serve as the production platform for the life of the reserves. First production through the ATP Titan is expected during March 2010. Also in 2009, we began completion operations on a well at Telemark Field (Atwater Valley Block 63) which we expect to begin producing through the ATP Titan during 2010. The ATP Titan has a design capacity of 25 MBbls of oil per day, 60 MMcf of gas per day and a useful life of 40 years. We have a 100% working interest in the Telemark Hub.

North Sea

Acquisitions – In the U.K. North Sea, we participated in the 25th licensing round and were awarded a 50% equity interest in Block 9/21a, a property known as “Skipper,” for no upfront investment. Under the agreement, we are committed to perform certain activities to assess the feasibility of future development of this field.

Development – In the U.K. North Sea, we completed and began producing two wells at Wenlock. We operate Wenlock with a 20% working interest.

Oil and Natural Gas Reserves

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

 

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

During December 2008, the SEC issued the final rule, “Modernization of Oil and Gas Reporting,” and we have adopted it as of December 31, 2009 in this annual report.

The following table presents our estimated net proved oil and natural gas reserves (all from traditional resources) at December 31, 2009 based on reserve reports prepared by independent petroleum engineers Collarini Associates and Ryder Scott Company, L.P. for our Gulf of Mexico reserves, Collarini Associates for our U.K. reserves and Ryder Scott Company, L.P. for our Netherlands reserves. The technical personnel responsible for preparing the reserve estimates at both Collarini Associates and Ryder Scott Company, L.P. meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. Both are independent firms of petroleum engineers, geologists, geophysicists, and petrophysicists; they do not own an interest in our properties and are not employed on a contingent fee basis.

 

     Proved Reserves
     Developed    Undeveloped    Total

Gulf of Mexico

        

Oil and condensate (MBbls)

   7,826    44,614    52,440

Natural gas (MMcf)

   44,517    188,522    233,039

Total proved reserves (MBoe)

   15,246    76,034    91,280

North Sea

        

Oil and condensate (MBbls)

   4    25,498    25,502

Natural gas (MMcf)

   12,745    97,497    110,242

Total proved reserves (MBoe)

   2,128    41,748    43,876

Total

        

Oil and condensate (MBbls)

   7,830    70,112    77,942

Natural gas (MMcf)

   57,262    286,019    343,281

Total proved reserves (MBoe)

   17,374    117,782    135,156

Our corporate reservoir engineering group has oversight and compliance responsibility for the internal reserve estimation process and provides data to the independent third party engineers who estimate our reserves. The management of this group which includes the Chief Operating Officer consists of a degreed petroleum engineer with 27 years of industry experience, including 11 years of experience managing ATP’s reserves. Annually, this petroleum engineer attends continuing technical education courses. He is a 25-year member of the Society of Petroleum Engineers.

The estimates of proved reserves in the table above do not differ from those we have filed with other federal agencies. The process of estimating 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.

Proved Undeveloped Reserves

As of December 31, 2009, our PUDs totaled 70.1 MMBbls of crude oil and 286.0 Bcf of natural gas, for a total of 117.8 MMBoe.

 

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PUD Locations - Approximately 59% of our PUDs at year-end 2009 were associated with our major development hubs at Gomez, Telemark, and Canyon Express in the Gulf of Mexico. An additional 34% of PUDs at year-end 2009 were associated with a major development project at the Cheviot field in the North Sea. We do not have any material concentrations of PUDs that have been on our books for more than five years.

Changes in PUDs - Significant changes in PUDs that occurred during the year were due to:

 

   

conversion of approximately 2.6 MMBoe PUDs into proved developed reserves;

 

   

upward revision of 21.9 MMBoe due to well performance and development drilling

 

   

reclassification of approximately 0.4 MMBoe PUDs that were not scheduled to be developed within five years from proved to probable reserves; and

 

   

negative revisions of approximately 1.5 MMBoe in PUDs were due primarily to changes in commodity prices.

Development Costs - Costs incurred relating to the development of PUDs in 2009 were approximately $627.6 million, exclusive of capitalized interest. Estimated future development costs relating to the development of PUDs are projected to be approximately $503 million in 2010, $461 million in 2011, $494 million in 2012, and $694 million in years 2013 to 2015.

Drilling Plans - All PUD drilling locations are scheduled to be drilled prior to the end of 2015.

Standardized Measure of Cash Flows

At December 31, 2009 our standardized measure of discounted future net cash flows was $1.8 billion. The present value of future net pre-tax cash flows attributable to estimated net proved reserves, discounted at 10% per annum, (“PV-10”) is a computation of the standardized measure of discounted future net cash flows on a pre-tax basis. The table below provides a reconciliation of PV-10 to the standardized measure of discounted future net cash flows at December 31, 2009. 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 net cash flows, before income taxes

   $ 1,989,136   

Future income taxes, discounted at 10%

     (214,429
        

Standardized measure of discounted future net cash flows

   $ 1,774,707   
        

Significant Properties

The following table sets forth additional information on our more significant properties as of December 31, 2009:

 

Field

  

Development
Location

   Net Total
Proved
Reserves
MBoe
   2009 Net
Production
MBoe
   Net
Revenue
Interest%
  

Expected
First
Production

Telemark Hub (1)

   GOM    49,279    —      91    2010

Gomez Hub (1)

   GOM    24,950    2,709    63    Producing

Cheviot

   N. Sea    39,539    —      92    2012

Canyon Express Hub (1)

   GOM    5,894    228    49    Producing

 

(1) Contains both shut-in reserves and/or undeveloped reserves, both of which are scheduled to be on production in 2010.

 

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Drilling Activity

The following table shows our drilling and well completion activity for the year ended December 31, 2009. 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
     2009    2008    2007    2009    2008    2007

Gross Development Wells:

                 

Productive

   2.0    6.0    4.0    2.0    —      2.0

Nonproductive

   —      —      —      —      —      —  
                             

Total

   2.0    6.0    4.0    2.0    —      2.0
                             

Net Development Wells:

                 

Productive

   1.6    5.5    4.0    0.4    —      1.9

Nonproductive

   —      —      —      —      —      —  
                             

Total

   1.6    5.5    4.0    0.4    —      1.9
                             

Gross Exploratory Wells:

                 

Productive

   —      2.0    3.0    —      —      1.0

Nonproductive

   —      —      1.0    —      —      —  
                             

Total

   —      2.0    4.0    —      —      1.0
                             

Net Exploratory Wells:

                 

Productive

   —      0.4    3.0    —      —      0.9

Nonproductive

   —      —      1.0    —      —      —  
                             

Total

   —      0.4    4.0    —      —      0.9
                             

Total Gross Wells:

                 

Productive

   2.0    8.0    7.0    2.0    —      3.0

Nonproductive

   —      —      1.0    —      —      —  
                             

Total

   2.0    8.0    8.0    2.0    —      3.0
                             

Total Net Wells:

                 

Productive

   1.6    5.9    7.0    0.4    —      2.8

Nonproductive

   —      —      1.0    —      —      —  
                             

Total

   1.6    5.9    8.0    0.4    —      2.8
                             

At December 31, 2009, 4.0 gross development wells (4.0 net wells) were in the process of being drilled in the Gulf of Mexico.

Productive Wells

The following table presents the number of productive oil and natural gas wells in which we owned an interest as of December 31, 2009:

 

     Gulf of
Mexico
   North Sea    Total

Gross

        

Natural gas

   27.0    9.0    36.0

Oil

   16.0    —      16.0
              

Total

   43.0    9.0    52.0
              

Net

        

Natural gas

   20.5    2.3    22.8

Oil

   11.7    —      11.7
              

Total

   32.2    2.3    34.5
              

At December 31, 2009, we had two gross natural gas wells with multiple completions.

 

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Acreage

The following table summarizes our developed and undeveloped acreage holdings at December 31, 2009. 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

   173,392    132,842    127,920    121,026    301,312    253,868

North Sea

   42,386    10,740    40,577    29,672    82,963    40,412
                             

Total

   215,778    143,582    168,497    150,698    384,275    294,280
                             

 

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

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

 

Year Ending December 31,:

   Gulf of Mexico    North Sea    Total
     Gross    Net    Gross    Net    Gross    Net

2010

   41,520    41,520    11,703    11,703    53,223    53,223

2011

   17,280    17,280    —      —      17,280    17,280

2012

   11,520    7,200    —      —      11,520    7,200

2013 & beyond

   57,600    55,026    28,874    17,969    86,474    72,995
                             

Total

   127,920    121,026    40,577    29,672    168,497    150,698
                             

The leases expiring in 2010 include 11,703 acres related to proved reserves which are actively being developed and as such the lease term will be extended beyond the stated expiration. The remaining acreage expiring in 2010 is related to unproven property which we are evaluating for potential future activity or sales.

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.

In February 2010, Bison Capital Corporation filed suit against ATP alleging that fees totaling $102 million related to certain financial transactions had not been paid by ATP. We believe we have paid Bison Capital Corporation all amounts due under our 2004 agreement with them. ATP is currently preparing a response to the petition and plans to vigorously defend against these allegations.

We are, in the ordinary course of business, involved in various other legal proceedings from time to time. Management does not believe that the outcome of these proceedings as of December 31, 2009, either individually or in the aggregate, will have a materially adverse effect on our financial condition, results of operations or cash flows

 

Item 4. (Removed and Reserved.)

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 50,779,370 shares of common stock and 1,400,000 shares of 8% convertible perpetual preferred stock outstanding as of March 2, 2010. Our common stock is traded on the NASDAQ Global Select Market under the ticker symbol ATPG. The number of holders of our common stock and 8% convertible perpetual preferred stock as of March 15, 2010 is 48 and 24,415, respectively. The following table sets forth the range of high and low sales prices for the common stock as reported on the NASDAQ Global Select Market for the periods indicated below. Such over-the-counter market quotations reflect inter-dealer prices, without retail mark-up, mark-down or commission and may not necessarily represent actual transactions.

 

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     High    Low

2008

     

1st Quarter

   $ 52.25    $ 28.88

2nd Quarter

     47.35      26.54

3rd Quarter

     41.50      16.16

4th Quarter

     18.72      3.89

2009

     

1st Quarter

   $ 7.92    $ 2.75

2nd Quarter

     10.20      4.81

3rd Quarter

     22.99      5.22

4th Quarter

     21.87      14.40

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 Loans limit the amount we can pay for 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. We pay quarterly dividends on outstanding shares of our convertible preferred stock at the annual rate of 8% of liquidation value.

Shareholder Return Performance Presentation

The information set forth in the graph and table below compares the value of our Common Stock to the NASDAQ Market Index and to a “Peer Group Index,” which is comprised of the following 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 (through June 2007), Newfield Exploration Company, Noble Energy Inc., Pogo Producing Company (through November 2007), Remington Oil and Gas Corporation (through December 2005), Stone Energy Corporation, Callon Petroleum Company, Forest Oil Corporation (beginning June 2007), Helix Energy Solution GP (beginning January 2006), Plains Exploration & Production (beginning November 2007).

Each of the total cumulative returns presented assumes a $100 investment beginning December 31, 2004 and ending December 31, 2009. 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.

 

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LOGO

 

Total Return Analysis

   12/31/04    12/31/05    12/31/06    12/31/07    12/31/08    12/31/09

ATP Oil & Gas Corporation

   $ 100.00    $ 199.09    $ 212.86    $ 271.87    $ 31.47    $ 98.33

NASDAQ Composite Index

   $ 100.00    $ 102.20    $ 112.68    $ 124.57    $ 74.71    $ 108.56

Peer Group Index

   $ 100.00    $ 126.10    $ 128.22    $ 159.36    $ 83.74    $ 132.47

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

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

 

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Item 6. Selected Financial Data.

(In thousands, except per share data)

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

 

     Year Ended December 31,  
     2009     2008     2007     2006     2005  

Statement of Operations Data:

          

Revenues:

          

Oil and gas production

   $ 298,490      $ 584,823      $ 599,324      $ 414,182      $ 146,674   

Other (1)

     13,664        33,206        8,611        5,639        —     
                                        
     312,154        618,029        607,935        419,821        146,674   
                                        

Cost, operating expenses and other:

          

Lease operating

     84,956        91,196        91,693        72,446        23,629   

Exploration

     264        48        13,756        2,231        6,208   

General and administrative (2)

     44,211        41,653        32,018        32,976        24,331   

Depreciation, depletion and amortization

     152,780        246,434        247,378        169,704        64,069   

Impairment of oil and gas properties

     45,799        125,059        34,342        19,520        —     

Accretion of asset retirement obligation

     11,676        15,566        12,117        8,076        3,238   

(Gain) loss on abandonment

     2,872        13,289        18,649        9,603        (732

Gain on disposition of properties (3)

     (12,433     (119,233     —          —          (2,743

Other, net

     (742     (99     (3,706     (7     (419
                                        
     329,383        413,913        446,247        314,549        117,581   
                                        

Income (loss) from operations

     (17,229     204,116        161,688        105,272        29,093   
                                        

Other income (expense):

          

Interest income

     710        3,476        7,603        4,532        4,064   

Interest expense, net

     (40,884     (100,729     (121,302     (58,018     (35,720

Derivative income (expense)

     (712     89,035        —          —          —     

Loss on debt extinguishment

     —          (24,220     —          (28,115     —     
                                        
     (40,886     (32,438     (113,699     (81,601     (31,656
                                        

Income (loss) before income taxes

     (58,115     171,678        47,989        23,671        (2,563
                                        

Income tax (expense) benefit

     22,534        (49,973     631        (16,794     (153
                                        

Net income (loss)

     (35,581     121,705        48,620        6,877        (2,716

Less income attributable to the redeemable noncontrolling interest (4)

     (13,380     —          —          —          —     

Less preferred stock dividends

     (2,856     —          —          (46,225     (9,858
                                        

Net income (loss) attributable to common shareholders

   $ (51,817   $ 121,705      $ 48,620      $ (39,348   $ (12,574
                                        

Net income (loss) per share attributable to common shareholders:

          

Basic

   $ (1.24   $ 3.43      $ 1.58      $ (1.33   $ (0.43
                                        

Diluted

     (1.24     3.39        1.55        (1.33     (0.43
                                        

Preferred stock cash dividends per share:

   $ 2.04      $ —        $ —        $ —        $ —     
                                        

Weighted average number of common shares:

          

Basic

     41,853        35,457        30,793        29,693        29,080   

Diluted

     41,853        35,868        31,301        29,693        29,080   

 

     December 31,
     2009     2008    2007    2006    2005

Balance Sheet Data:

             

Cash and cash equivalents

   $ 108,961      $ 214,993    $ 199,449    $ 182,592    $ 65,566

Working capital (deficit)

     (26,394     36,459      96,888      77,504      567

Oil and gas properties, net

     2,485,772        1,872,203      1,830,580      1,095,645      627,421

Total assets

     2,803,147        2,275,610      2,307,133      1,447,058      823,763

Long-term debt, including current maturities

     1,216,685        1,366,630      1,404,011      1,071,441      340,989

Other long-term obligations

     274,942        2,582      —        —        —  

Capital lease, including current maturities

     —          —        —        23,699      43,116

Total liabilities

     2,067,618        1,959,261      1,997,267      1,411,140      606,252

Temporary equity (4)

     139,598        —        —        —        —  

Shareholders’ equity

     595,931        316,349      309,866      35,918      217,511

 

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(1) Other revenues are comprised of amounts realized under our loss of production income insurance policy as a result of disruptions caused by the 2008 and 2005 hurricanes.
(2) Effective January 1, 2006 we adopted the accounting standards for stock-based compensation using the modified prospective transition approach.
(3) Gain on disposition of properties consists of our sale of the deep rights on a Gulf of Mexico property in 2009 and our sale of 80% of our working interest in Tors and Wenlock in the UK North Sea in 2008.
(4) Represents the 49% noncontrolling interest in our consolidated limited partnership that holds the Innovator floating production facility.

 

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

Executive Overview

General

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

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

 

   

significant undeveloped reserves;

 

   

close proximity to developed markets for oil and natural gas;

 

   

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

 

   

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

 

   

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

Our focus is on acquiring properties that are noncore or nonstrategic to their current owners for a variety of reasons. For example, larger oil companies from time to time adjust their capital spending or shift their focus to exploration prospects they believe offer greater reserve potential. Some projects may provide lower economic returns to a company due to the cost structure and focus of that company. Also, due to timing or budget constraints, a company may be unwilling or unable to develop a property before the expiration of the lease. With our cost structure and acquisition strategy, it is not unusual for us to have an acquisition cost of a property that is less than the total development costs incurred by the previous owner. This strategy, coupled with our expertise in our areas of focus and our ability to develop projects, tend to make our oil and gas property acquisitions more financially attractive to us than to the seller. Given our strategy of acquiring properties that contain proved reserves, or where previous drilling by others indicates to us the presence of recoverable hydrocarbons, our operations typically are lower risk than exploration-focused Gulf of Mexico and North Sea operators.

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

In 2003 we made a concerted effort to expand our presence into the deeper water of the Gulf of Mexico. In 2003 we acquired MC 711 (now part of our Gomez Hub) in 3,000 feet of water, in 2005 we acquired Kings Peak (now part of our Canyon Express Hub) in 7,000 feet of water and in 2006 we acquired MC 941, MC 942 and AT 63 (now part of our Telemark Hub) in 4,000 feet of water. With these acquisitions and the subsequent development of these properties, as of December 31, 2009, our proved reserves in the deepwater Gulf of Mexico account for 62% of our total proved reserves. Our proved reserves on the Gulf of Mexico Shelf account for 6% of our total proved reserves with the remaining 32% in the North Sea.

 

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In conjunction with the move to the deeper water of the Gulf of Mexico, we also made the commitment to increase our investment in reusable floating infrastructure. We own interests in two floating production facilities, the ATP Innovator and the ATP Titan. The ATP Innovator is located in the Gulf of Mexico at our Gomez Hub and the ATP Titan is located in the Gulf of Mexico at our Telemark Hub. These floating production facilities are fundamental to our hub strategy and business plan. We believe the presence of these facilities allows us a competitive advantage for additional acquisitions in a large area surrounding each installation. A third floating production facility called an Octabuoy is under construction in China for initial deployment at our Cheviot Hub in the U.K. North Sea during 2012. We operate the ATP Innovator and the ATP Titan and also expect to operate the Octabuoy when it is placed in service. The floating production facilities have longer useful lives than the underlying reserves and are capable of redeployment to new producing locations upon depletion of the reserves. Accordingly they are expected eventually to be moved several times over their useful lives.

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. For example in 2008, we sold an 80% working interest in two of our properties in the U.K. North Sea. We received $471.2 million for these transactions and recognized a $119.1 million gain on sale on the U.K. transaction. In the Gulf of Mexico in 2008, we sold a limited-term overriding interest in our Gomez Hub for which we received $82.0 million or $85 per barrel of oil equivalent for the reserves sold. In 2009, we placed the ATP Innovator into a limited partnership. We are the general partner of the partnership and retain a 49% subordinated limited partner interest. The 49% Class A limited partner interest was sold for $150.0 million at closing. We also raised $14.5 million in 2009 through the sale of limited-term overriding royalty interests in our Gomez Hub properties.

Review of 2009

During 2009, we incurred $808.6 million in capital expenditures. With these expenditures we accomplished the following:

 

   

Completed and achieved initial production from wells at the Gomez Hub and South Marsh Island 190 in the Gulf of Mexico and two wells at Wenlock in the North Sea;

 

   

Discovered additional pay sands at the Telemark Hub;

 

   

In late 2009, our new deepwater drilling and production facility, the ATP Titan, sailed out of dry dock. As of March 2010, the ATP Titan is on location at the Telemark Hub undergoing final installation procedures to begin production;

 

   

Expanded our presence at our Gomez Hub by exchanging an ownership interest in one block for an ownership interest in two additional blocks, acquired an interest in an additional block around our Clipper property and acquired an interest in a new property, Skipper, in the U.K. North Sea;

 

   

Increased total proved reserves by 14% to 135.2 MMBoe;

A major portion of our capital expenditures, $631.8 million (78% of total capital), was incurred developing two major projects that did not impact production in 2009 but are scheduled for production in 2010 (Telemark) and 2012 (Cheviot). With oil and gas prices falling in the early part of 2009 and the capital markets still in turmoil, this proved to be one of the more interesting years in our history. Our revenues from oil and natural gas are highly dependent on the price of these commodities. The disarray among oil and natural gas prices that began in 2008 continued to a great extent into the early part of 2009. During 2008 domestic oil prices hit a high of $146.00 per Bbl in July 2008, only to close at $45.00 per Bbl on December 31, 2008. By March 2009, oil fell further to $33.98 per barrel. Natural gas followed a similar trend, falling from a high of $13.32 per MMBtu in July 2008 to close at $5.62 per MMBtu on December 31, 2008. After March 2009, the energy markets for oil began to recover, rising to a high for the year of $81.37 per barrel in October. Natural gas prices in 2009 were generally depressed and were volatile overall. They hit a high of $6.07 per MMBtu in February and a low of 2.51 per MMBtu in October. This dramatic reduction in energy prices during 2009 caused our realized oil price per barrel to decrease 21% in 2009 vs. 2008 and natural gas per MMBtu to fall 45% in the same period. Coupled with an overall 39% decrease in production in 2009, our oil and gas revenues fell 49% in 2009.

 

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In addition to our cash flows from operations which were significantly negatively impacted by the previously discussed reduction in oil and gas revenues, we have funded our acquisition and development activities through a combination of bank borrowings, proceeds from equity offerings, the sale or conveyance of interests in selected properties and financings with our suppliers. The malaise in the credit markets of 2008 continued into 2009. Capital market transactions were limited and, when possible to complete, were more expensive than similar transactions of the past three years. Despite this, during 2009, we raised $148.8 million of capital from the formation of ATP-IP and $306.2 million from issuance of common and preferred stock. We also completed monetizations for $74.5 million from the Gomez Pipeline transaction and a limited-term overriding royalty transaction that raised an additional $14.5 million.

During this period we financed significant portions of our development program with transactions entered into with our suppliers and their affiliates. We have conveyed to certain suppliers net profits interests in our Telemark Hub and Clipper oil and gas properties in exchange for development services. We have also negotiated with certain other vendors involved in the development of the Telemark Hub and Clipper to partially defer payments until after production has begun. Development of our interest in the Cheviot field in the U.K. North Sea continues and we have arranged with the fabricator of the floating production and drilling facility to defer $99 million of payments until construction is complete. These types of financial arrangements preserve our current cash in exchange for reduced future cash flows from production.

Reserves

At December 31, 2009, we had proved reserves of 135.2 MMBoe, of which 68% are located in the Gulf of Mexico and the remaining 32% are in the North Sea. The PV-10 of our proved reserves at December 31, 2009 was approximately $2.0 billion. See “Item 2. Properties – Oil and Natural Gas Reserves” for reconciliation to our standardized measure of discounted future net cash flows of $1.8 billion. In addition to the areas with proved undeveloped reserves, we have scheduled for drilling or completion properties where previous drilling into the targeted reservoirs indicates the presence of commercially productive quantities of hydrocarbons, even though the reservoirs do not meet the current SEC definition of proved reserves. Upon completion of drilling, completing or testing wells on these blocks and similar properties in our portfolio, we anticipate that we may be able to record proved reserves associated with several of these properties.

In January 2010, the Financial Accounting Standards Board issued an accounting standard to be in alignment with the requirements in the SEC’s final rule, “Modernization of the Oil and Gas Reporting Requirements.” Key items in the new rules include changes to the pricing used to estimate reserves whereby a 12-month average price is used rather than a single day spot price, permitting the use of new technology when determining reserves, the ability to include nontraditional resources in reserves and permitting disclosure of probable and possible reserves. We adopted the accounting standard as of December 31, 2009.

Acquisitions

During 2009, we paid $0.2 million to acquire a 55.3% working interest in Green Canyon Block 344, a lease with unproved reserves south of our Green Canyon Block 300 (“Clipper”) property in the Gulf of Mexico. Also, in exchange for assumption of any property abandonment obligations and payment to us of $4.8 million, we acquired a partner’s working interests in certain properties in the Gulf of Mexico.

During January 2010, we consummated agreements for a cash-free swap of our interest in Mississippi Canyon (“MC”) Block 800, for a third party’s interests in MC Block 754 and MC Block 710. MC Block 710 is an exploratory prospect adjacent to our Gomez Hub in MC Block 711 and surrounding blocks.

Development

Gulf of Mexico – Development activities continued in 2009 at our Telemark Hub in the deepwater Gulf of Mexico. The ATP Titan sailed to location and moored during December 2009 and is currently in the final stages of completion. In the northern part of the Telemark Hub, the initial drilling of three wells was performed in 2008 at Mirage (MC Block 941) and Morgus (MC Block 942). Once placed in service, the ATP Titan will be used to complete the drilling of the three wells and to serve as the production platform for the life of the reserves. First production at the ATP Titan is expected during March 2010. Also in 2009, we began completion operations on a well at Telemark Field (Atwater Valley Block 63) which we expect to begin producing through the ATP Titan during 2010. The ATP Titan has a design capacity of 25 MBbls of oil per day, 60 MMcf of gas per day and a useful life of 40 years. We have a 100% working interest in the Telemark Hub.

 

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North Sea – In the North Sea, we completed and began producing two wells at Wenlock. We operate Wenlock with a 20% working interest.

Formation of Limited Partnership

On March 6, 2009, along with GE Energy Financial Services (“GE”), we formed Infrastructure Partners, L.P. (“ATP-IP”) to own the ATP Innovator, the floating production facility that currently serves our Mississippi Canyon Block 711 Gomez Hub properties. We contributed the ATP Innovator in exchange for a 49% subordinated limited partner interest and a 2% general partner interest. GE paid $150.0 million to ATP-IP for a 49% Class A limited partner interest. In accordance with our Term Loans, we used $36.4 million of net proceeds from this transaction to reduce the asset sale tranche of our Term Loans. We remain the operator and continue to hold a 100% working interest in the Gomez field and its oil and gas reserves. The transaction was effective June 1, 2008 and allows us exclusive use of the ATP Innovator during the term of the Platform Use Agreement (“PUA”), which is expected to be the economic life of the Gomez Hub reserves. One director and three officers of ATP also serve as three managers (the equivalent of directors) and the President of the General Partner, ATP IP-GP, LLC. Under certain circumstances there may be conflicts of interest between the general partner and ATP.

From an operational standpoint, during the term of the PUA, we are obligated to pay to ATP-IP a per unit fee for all hydrocarbons processed by the ATP Innovator, subject to a minimum throughput fee of $53,000 per day. Such minimum fees, if applicable, can be recovered by us in future periods whenever fees owed during a month exceed the minimum due. We may also be subject to a minimum fee of $53,000 per day for up to 180 days under certain circumstances, including if we fail to provide the minimum notification period before the Gomez field ceases production. We made no other performance guarantees to GE and the ultimate fees earned by ATP-IP beyond the minimum fees will be determined by the volumes of hydrocarbons processed through the facility. During the term of the PUA, we are responsible for all of the operating costs and periodic maintenance of the ATP Innovator. ATP-IP will pay us a monthly fee for certain administrative services we will provide to the partnership. Additionally, we will share in partnership net income and regular minimum quarterly cash distributions in accordance with the provisions of the ATP-IP partnership agreement. Partnership cash in excess of monthly distributions and operating needs is transferred to an account which is classified as restricted cash on the consolidated balance sheet. For financial statement purposes, we consolidate this entity as discussed more fully in Note 6, “Formation of Limited Partnership” to the Consolidated Financial Statements.

Transactions

During 2009, we financed significant portions of our development program with transactions entered into with our vendors and their affiliates. We have conveyed to certain vendors net profits interests in our Telemark Hub and Clipper oil and gas properties in exchange for development services. Certain of these net profits interests have specified rates of return. Because we have accounted for these NPI's as financing obligations on our consolidated balance sheet, the reserves and production revenues associated with the NPI interests are retained by the Company (See Note 9, “Other Long-term Obligations” to the Consolidated Financial Statements). We have also negotiated with certain other vendors involved in the development of the Telemark Hub and Clipper to partially defer payments until after Telemark Hub production has begun. Development of our interest in the Cheviot field in the U.K. North Sea continues and we have arranged with the fabricator of the floating production and drilling facility to defer $99 million of payments until construction is complete.

During June 2009, we issued 8.75 million shares of common stock at a price of $8.25 per share, before underwriters’ discounts and commissions and offering expenses. During September and October of 2009, we issued 5.8 million shares of common stock at a price of$18.50 per share before underwriters’ discounts and commissions and offering expenses. During September 2009, we issued 1.4 million shares of 8% convertible perpetual preferred stock with a per share liquidation preference of $100 and a cumulative dividend rate of 8%. We received total net proceeds of $305.8 million for these transactions. In accordance with our Term Loans, $76.5 million of the asset sale tranche of our Term Loans was repaid.

In September 2009, we executed an asset purchase and sale agreement for net proceeds of $74.5 million (“Gomez Pipeline Transaction”) for both the oil and natural gas export pipelines that service the Gomez Hub at Mississippi Canyon Block 711. In conjunction with the sale, we entered into agreements with the purchaser to

 

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transport oil and gas production for the remaining production life of the fields serviced by the ATP Innovator for a per unit fee that is subject to a minimum monthly payment through December 31, 2016. Such minimum fees, if applicable, can be recovered by us in future periods within the same calendar year whenever fees owed during a month exceed the minimum due. As a result of the retained asset retirement obligation and the purchaser's option to convey the pipeline back to ATP at the end of the life of the fields in the Gomez Hub, the transaction has been accounted for as a financing obligation equal to the net proceeds received. We remain the operator of the pipeline and are responsible for all of the related operating costs. In accordance with our Term Loans, we used $42.2 million of net proceeds to reduce the asset sale tranche of our Term Loans.

In October 2009 we sold a limited-term overriding royalty interest in our Gomez Hub properties for $15.0 million. The agreement provides for repayment of the proceeds plus an overall rate of return. Because of the dollar-denominated and limited payment terms of this overriding royalty interest, it is reflected in the accompanying financial statements as a financing obligation. In January 2010, we sold limited-term overriding royalty interests in our Gomez Hub properties for an aggregate $135.7 million, net of costs. In January 2010, we sold perpetual overriding royalty interests in our Gomez Hub properties for an aggregate $2.3 million, net of costs.

On November 2, 2009, we entered into an amendment (the “First Amendment”) to the Term Loans to maintain compliance with the covenants and to provide additional flexibility during the period from October 1, 2009 through December 31, 2010 (the “Amendment Period”). Among other provisions, the First Amendment expands the Net Debt to EBITDAX ratio from 3.0 to 4.0, the EBITDAX to Interest ratio from 2.5 times to 2.0 times and the current ratio from 1.0 to 0.8 for the duration of the Amendment Period. The interest rate on the first tranche balance of Term Loans will increase to 11.25% during the Amendment Period, at the end of which it will decrease to 9.5% for the remainder of the term. The First Amendment will further increase the rate on the asset sale tranche balance of Term Loans outstanding by 2.75% for the duration of the Amendment Period, at the end of which the rate will decrease by 1.75% from the rate at that time.

We paid an initial fee of 0.5% to each of the lender group and the administrative agent of the outstanding balance of the Term Loans at closing plus related expenses for a total of $12.6 million for the First Amendment. Additionally, two fees of up to 0.5% each may be due on the aggregate unpaid balance of Term Loans outstanding at June 30, 2010. Specifically, 0.5% will be due if any portion of the Asset Sale Facility remains outstanding as of that date, and an additional 0.5% will be due if the aggregate balance exceeds $800 million.

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

2010 Operational and Financial Objectives

Our goals for 2010 revolve around continuing development of our oil and gas properties, primarily Telemark. As of March 2010, we have completed one well at this location with plans for an additional three wells during 2010. The ATP Titan which will serve as the floating production facility at Telemark is on location and awaiting final connections for first production. We have also completed one well at Gomez with plans for an additional well later in 2010. Additional opportunities may be pursued at the Tors in the U.K. North Sea and our Clipper project in the Gulf of Mexico.

Thus far in 2010, we have completed a $138.0 million, net of costs, of overriding royalty interests monetization transactions. We may also attempt to monetize other assets, primarily the ATP Titan and related pipeline and infrastructure and potentially sell other overriding royalty interests. With available cash flow and proceeds from any monetizations, we plan to repay in its entirety the Asset Sale Facility of our Term Loans during 2010, (i.e. prior to its maturity in 2011). We anticipate our 2010 cash capital expenditures will range between $400 and $500 million, which is the level that we expect can be funded with cash on hand, cash flows from operations and completed monetizations.

While we do not expect to rely on the credit markets to fund our capital program in 2010, we desire to monetize additional assets during the year. To the extent we are successful in monetizing selected additional assets, we may use the proceeds to accelerate or add development opportunities, to further reduce our debt or for added liquidity. There can be no assurances that such monetizations can be completed on acceptable terms or that potential counterparties and market conditions will be favorable to such transactions.

 

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Risks and Uncertainties

As an independent oil and gas producer, our revenue, profitability, cash flows, and future rate of growth are substantially dependent on prevailing prices for oil and natural gas. Historically, the energy markets have been very volatile, and we expect such price volatility to continue. Any extended decline in oil or gas prices could have a material adverse effect on our financial position, results of operations, cash flows, the quantities of oil and gas reserves that we can economically produce, and may restrict our ability to obtain additional financing or to meet the contractual obligations required under our June 2008 senior secured term loan facility, as amended (“Term Loans”).

In addition, our estimates of proved oil and natural gas reserves and the estimated future net revenues from such reserves are based upon various assumptions, including assumptions relating to oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. 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. Estimates of our oil and natural gas reserves and the costs and timing associated with developing these reserves are subject to change, which could materially impact the quantities of oil and natural gas that we ultimately produce. As of December 31, 2009, approximately 87% 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 costs may exceed our estimates, any of which may materially affect our financial position, results of operations, cash flows and our ability to meet covenants under our Term Loans.

We are also vulnerable to certain concentrations that could expose our revenues, profitability, cash flows and access to capital to the risk of a near-term severe impact. The size of our operations and our capital expenditures budget limit the number of properties that we can develop in any given year and a substantial portion of our current production is contributed from relatively few wells located offshore in the Gulf of Mexico and in the North Sea. In 2008 and 2009, a significant amount of time and money has been spent by us on our Telemark Hub development. Our 2010 results of operations, financial position and cash flows will be significantly impacted by the timing and success at this development. We have also recently conveyed to certain vendors limited-term net profits interests in our Telemark Hub and Clipper (defined below) oil and gas properties in exchange for development services and equipment. We have also negotiated with certain other vendors involved in the development of the Telemark Hub to partially defer payments until after production has begun. These deferrals will burden the net cash flows available to us from Telemark Hub production activities until the obligations have been satisfied.

In addition to the numerous risks associated with offshore operations, some of which may not be covered by insurance, these properties are also characterized by rapid production declines, which require us to incur significant capital expenditures to replace declining production. Complications in the development of any single material well or infrastructure installation, including lack of sufficient capital, or if we were to experience operational problems, uninsured events, or prolonged adverse commodity prices resulting in the curtailment of production in any of these wells, our current and future production levels would be adversely affected, which may materially affect our financial condition, results of operations and cash flows.

Our Term Loans impose restrictions on us that increase our vulnerability in the current adverse economic and industry climate, and may limit our ability to obtain additional financing. We have recently obtained amendments to our credit facility, as discussed in Note 7, “Term Loans”, to maintain compliance with our covenants as of December 31, 2009 and to provide us more latitude in our covenants until December 31, 2010. Our ability to meet these covenants is primarily dependent on the adequacy of cash flows from operations. Our inability to satisfy the covenants or other contractual requirements contained in our Term Loans would constitute an event of default. An uncured default could result in our outstanding debt becoming immediately due and payable. If this were to occur, we might not be able to obtain waivers or secure alternative financing to satisfy our obligations, either of which would have a material adverse impact on our business. Given current market conditions, our ability to access the capital markets or consummate asset monetizations or other financings may be restricted at a time when we would need to raise additional capital. Further, the current economic conditions could also impact our lenders, customers and hedging counterparties and cause them to fail to meet their obligations to us with little or no warning.

 

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Although we believe that we will have adequate liquidity to meet our future capital requirements and to remain compliant with the covenants under our Term Loans, the factors described above create uncertainty. We consider the control and flexibility afforded by operating our properties under development to be key to our business plan and strategy. By operating our properties, we retain significant control over the development plans and their timing. Within certain constraints, we can conserve capital by delaying or eliminating capital expenditures. While postponing or eliminating capital projects will delay or reduce future cash flows from scheduled new production, this control and flexibility allows us to match our capital commitments to our available capital resources.

Results of Operations

For the years ended December 31, 2009, 2008 and 2007 we reported net income (loss) attributable to common shareholders of ($51.8) million, $121.7 million and $48.6 million, or $(1.24), $3.39 and $1.55 per diluted share, respectively.

Oil and Gas Production Revenues

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

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

 

     Year Ended December 31,     % Change
from 2008
to 2009
    % Change
from 2007
to 2008
 
     2009    2008     2007      

Production:

           

Oil and condensate (MBbls)

     3,353      4,267        4,498      (21 )%    (5 )% 

Natural gas (MMcf)

     15,119      31,862        37,013      (53 )%    (14 )% 

Total (MBoe)

     5,873      9,578        10,667      (39 )%    (10 )% 

GOM (MBoe)

     5,342      7,026        8,629      (24 )%    (19 )% 

North Sea (MBoe)

     531      2,553        2,038      (79 )%    25

Revenues from production (in thousands):

           

Oil and condensate

   $ 192,044    $ 308,910      $ 290,329      (38 )%    6

Effects of cash flow hedges

     —        (2,390     (1,549    

Amortization of deferred revenue

     32,649      18,976        —         
                           

Total

   $ 224,693    $ 325,496      $ 288,780      (31 )%    13
                           

Natural gas

   $ 64,834    $ 264,204      $ 309,572      (75 )%    (15 )% 

Effects of cash flow hedges

     1,719      (8,672     897       

Amortization of deferred revenue

     7,244      3,795        —         
                           

Total

   $ 73,797    $ 259,327      $ 310,469      (72 )%    (16 )% 
                           

Oil, condensate and natural gas

   $ 256,878    $ 573,114      $ 599,901      (55 )%    (4 )% 

Effects of cash flow hedges

     1,719      (11,062     (652    

Amortization of deferred revenue

     39,893      22,771        —         
                           

Total

   $ 298,490    $ 584,823      $ 599,249      (49 )%    (2 )% 
                           

Average realized sales price:

           

Oil and condensate (per Bbl)

   $ 56.98    $ 72.41      $ 64.54      (21 )%    12

Effects of cash flow hedges (per Bbl)

     —        (0.56     (0.34    
                           

Total (per Bbl)

   $ 56.98    $ 71.85      $ 64.20      (21 )%    12
                           

GOM (per Bbl)

     57.04      71.67        64.21      (20 )%    12

North Sea (per Bbl)

     34.67      95.53        61.35      (64 )%    56

Natural gas (per Mcf)

   $ 4.27    $ 8.29      $ 8.36      (48 )%    (1 )% 

Effects of cash flow hedges (per Mcf)

     0.11      (0.27     0.03       
                           

Total (per Mcf)

   $ 4.38    $ 8.02      $ 8.39      (45 )%    (4 )% 
                           

GOM (per Mcf)

     4.13      9.68        8.30      (57 )%    17

North Sea (per Mcf)

     5.34      6.18        8.57      (14 )%    (28 )% 

Oil, condensate and natural gas (per Boe)

   $ 43.50    $ 59.82      $ 56.22      (27 )%    6

Effects of cash flow hedges (per Boe)

     0.30      (1.14     (0.06    
                           

Total (per Boe)

   $ 43.80    $ 58.68      $ 56.16      (25 )%    4
                           

GOM (per Boe)

     44.94      66.24        57.30      (32 )%    16

North Sea (per Boe)

     32.10      37.86        51.54      (15 )%    (27 )% 

 

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

Revenues from production were essentially flat between 2008 and 2007 because the 10% decrease in overall production (19% decrease in GOM and 25% increase in North Sea (“N.S.”)) was offset by a 4% increase in average realized sales price (16% increase in GOM and 27% decrease in N.S.) The lower production in the GOM is primarily the result of decreases at the Gomez Hub associated with hurricanes. Offsetting this decrease is increased production from the Wenlock property in the N.S., which was brought online in the fourth quarter of 2007. During the fourth quarter of 2008, we sold 80% of our working interests in Tors and Wenlock in the N.S. and, accordingly, revenues from production during future periods will be significantly lower.

Other Revenues

Other revenues for 2009 and 2008 are comprised of amounts realized under our loss of production income insurance policy due to disruptions caused by Hurricane Ike. Other revenues for 2007 are comprised of amounts realized under our loss of production income insurance policy due to disruptions caused by Hurricanes Rita and Katrina in 2005.

Lease Operating

Lease operating expenses include costs incurred to operate and maintain wells. These costs include, among others, workover expenses, operator fees, processing fees and insurance. Lease operating expense was as follows:

 

     Year Ended December 31,    % Change
from 2008
to 2009
    % Change
from 2007
to 2008
 
     2009    2008    2007     

Lease operating (in thousands)

   $ 84,956    $ 91,196    $ 91,693    (7 )%    (1 )% 

Per Boe

     14.47      9.54      8.58    51   11

Gulf of Mexico

     14.03      9.60      8.46    45   13

North Sea

     18.80      9.36      9.30    101   1

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

 

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Lease operating expense for 2008 was essentially unchanged compared to 2007. The per unit cost has increased primarily due to the effect of fixed costs on lower production volumes.

Exploration

During 2007, exploration expense included costs related to an exploratory well at MC 667. This well found noncommercial quantities of hydrocarbons, resulting in exploration expense of approximately $10.3 million. Exploration expense also includes the costs of geological and geophysical studies.

General and Administrative

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

 

     Year Ended December 31,    % Change
from 2008
to 2009
    % Change
from 2007
to 2008
 
     2009    2008    2007     

General and administrative (in thousands)

   $ 44,211    $ 41,653    $ 32,018    6   30

Per Boe

     7.53      4.32      3.00    74   44

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

General and administrative expense for 2008 increased compared to 2007. The increase is primarily attributable to higher noncash stock-based compensation costs and to increases in other compensation costs.

Depreciation, Depletion and Amortization

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

 

     Year Ended December 31,    %Change
from 2008
to 2009
    % Change
from 2007
to 2008
 
     2009    2008    2007     

DD&A (in thousands)

   $ 152,780    $ 246,434    $ 247,378    (38 )%    —     

Per Boe

     26.01      25.74      23.22    1   11

Gulf of Mexico

     24.11      21.66      21.42    11   1

North Sea

     45.20      36.90      30.72    22   20

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

DD&A expense in 2008 was flat compared to 2007 primarily due to decreased production offset by an 11% increase in average depletion rates to $24.11 per Boe in 2008. This per unit increase is primarily a result of higher costs incurred on our new developments relative to some of our older properties.

Impairment of Oil and Gas Properties

During 2009, we recorded impairment expense of $45.8 million related to seven proved and five unproved Gulf of Mexico properties. These impairments are primarily a result of reduced commodity prices, unfavorable operating performance and our decision to abandon further activities on certain unproven acreage. During 2008, we recorded impairment expense of $125.1 million related to certain Gulf of Mexico shelf properties. These impairments are primarily due to reductions in estimates of recoverable reserves resulting from reduced commodity prices and unfavorable operating performance of four properties. During 2007, we recorded impairment expense of $25.3 million and $9.0 million related to Gulf of Mexico and North Sea properties, respectively. These impairments are primarily due to unfavorable operating performance of four properties resulting in downward revisions of recoverable reserves.

 

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Accretion of Asset Retirement Obligation

Accretion expense in 2009 decreased to $11.7 million compared to $15.6 million in 2008 primarily due to the North Sea property sale noted above and changes in estimates of future abandonment obligations in 2008. Accretion expense of $15.6 million in 2008 is increased from $12.1 million in 2007 primarily due to increased asset retirement obligations associated with increased oil and gas property development and general vendor price increases.

Loss on Abandonment

We recognized aggregate loss on abandonment during 2009, 2008 and 2007 of $2.9 million, $13.3 million and $18.6 million, respectively. These amounts are primarily the result of actual abandonment operations requiring more work than originally estimated and unanticipated vendor price increases.

Gain on Disposition of Properties

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

As discussed above, during October 2008, we finalized a sale of 80% of our working interests in certain producing natural gas properties, leasehold acreage and gathering infrastructures, all located in the U.K. North Sea at the Tors and Wenlock fields. The sale is effective July 1, 2008. The closing of the transaction occurred on December 18, 2008, after which we own a 20% working interest in the Wenlock field and a 17% working interest in the Tors field. The cash received for the transaction was £258.2 million (approximately $389.2 million as of the closing date) after deducting £6.8 million for transaction costs and fees and adjustment for each party’s share of production proceeds received and expenses paid for periods after July 1, 2008. We recorded a $119.1 million gain on disposition of assets related to this sale.

Interest Income

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

Interest Expense

Interest expense decreased to $40.9 million in 2009 compared to $100.7 million in 2008 primarily due to 2009 capitalized interest of $110.1 million ($102.2 million related to the construction of the Telemark Hub development in the Gulf of Mexico and $7.9 million related to Cheviot in the U.K.) compared to capitalized interest of $44.6 million in 2008 ($42.7 million related to the Telemark Hub development and $1.9 million related to Cheviot). Capitalized interest increased due to higher average construction work-in-progress balances in 2009. Interest expense decreased to $100.7 million for 2008 compared to $121.3 million for 2007 primarily due to 2008 capitalized interest discussed above and lower interest rates experienced in the first half of 2008 and their effect on our floating-rate borrowings. This decrease was partially offset by interest related to the net $200.0 million increase in outstanding borrowings under our Term Loans beginning in the second quarter of 2008.

Derivative Income (Expense)

Derivative expense during 2009 was $0.7 million (losses of $9.8 million and gains of $9.1 million in the Gulf of Mexico and North Sea, respectively). The expense in 2009 is primarily related to net losses associated with our oil and gas fixed-price physical forward sales contracts.

Derivatives income in 2008 was $89.0 million (Gulf of Mexico, $96.5 million gain and North Sea, $7.5 million loss). As a result of the limited-term overriding royalty interest and changes in forecasts of production, we determined that it was no longer probable that forecasted production would be sufficient to satisfy amounts designated under certain of our cash flow commodity-price hedges. Consequently, we dedesignated some of these instruments as hedges and recognized expense of $40.5 million. During 2008, we terminated our oil puts, oil swaps and oil fixed-price physical forward sale contracts. We also entered into and subsequently terminated oil price collar derivatives. These terminations resulted in realized derivative income of $83.9 million. Due to termination of the oil fixed-price physical forward sale contracts for which we had claimed the normal sales derivative accounting exception provided by the accounting standards for derivatives and hedging, we determined that it was no longer appropriate to claim that exception for our gas fixed forwards. Consequently, we recorded the gas fixed forwards as derivative asset with an offset in derivative income of $14.4 million. The balance of the derivatives income is primarily related to changes in fair value of derivatives no longer designated as cash flow hedges.

 

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Loss on Extinguishment of Debt

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

Income Taxes

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

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

During 2007 we recognized net tax benefit of $0.6 million determined based on the results of operations for the year for each jurisdiction, the valuation allowance released and permanent differences affecting the overall tax rate in each jurisdiction, resulting in an overall effective tax rate of (1.3%).

Convertible Preferred Stock Dividends

Convertible preferred stock dividends in 2009 represent declared cash amounts due for the period from the September 2009 issue date of the preferred stock through December 31, 2009. The outstanding shares of convertible preferred stock accrue cumulative preferred dividends at the annual rate of 8% of liquidation value.

Liquidity and Capital Resources

Historically, we have funded our acquisition and development activities through a combination of bank borrowings, proceeds from equity offerings, cash from operations, the sale or conveyance of interests in selected properties and vendor financings. The disarray in the credit markets in 2008 continued into 2009. Capital market transactions are limited and when they can be completed they are more expensive than similar transactions in the past three years. Despite this, during 2009, we raised $148.8 million of capital from the formation of ATP-IP and $305.8 million from issuance of common stock and preferred stock.

During this period we also financed significant portions of our development program with transactions entered into with our vendors and their affiliates and $74.5 million from the Gomez Pipeline Transaction, which are discussed above. As discussed more fully in Note 9, ”Other Long-term Obligations” to the Consolidated Financial Statements, during 2009, we granted limited-term overriding royalty interests in the form of net profit interests in certain of our oil and gas properties in and around the Telemark Hub and Clipper to certain of our vendors in exchange for oil and gas property development services. The interests earned by the vendors will be paid solely from the net profits, as defined, of the subject properties. This type of financial arrangement preserves our current cash in exchange for reduced future cash flows from production. We have also negotiated with certain other vendors involved in the development of the Telemark Hub and Clipper to partially defer payments until after production has begun. Development of our interest in the Cheviot field in the U.K. North Sea continues and we have arranged with the fabricator of the floating production and drilling facility to defer $99 million of payments until construction is complete.

We anticipate our 2010 cash capital expenditures will range between $400 and $500 million, which is the level that we expect can be funded with cash on hand, cash flows from operations and completed monetizations. As operator of most of our projects under development, we have the ability to control the

 

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timing and extent of most of our capital expenditures should future market conditions warrant. Coupled with that control, we believe we have sufficient liquidity to enable us to meet our future capital and debt service requirements.

While we do not expect to rely on the credit markets to meet our goals in 2010, we desire to monetize selected assets during these periods, and the ability of potential buyers to access the credit markets and the commodity price outlook may be important factors to our success in doing so. For example, in January 2010 we closed on an overriding royalty interest transaction (primarily limited term) for cash proceeds of $138.0 million, net of costs. We are actively in discussions to monetize a portion of our interest in the ATP Titan. Still, we believe that we will be able to monetize more selected assets, providing us with additional capital to further reduce debt. In the near term, our revenues, profitability and cash flows are highly dependent upon many factors, particularly our ability to bring our major development project at Telemark on production, performance of other properties and the price of oil and natural gas. To mitigate future price volatility, we may continue to hedge the sales price of a portion of our future production.

For the longer term, we will continue to deploy the same or similar strategies. Operating our properties has always been a significant focus of our strategy. As stated previously, we believe operating our properties provides us the ability to control expenditures and adjust development timing and programs where needed. We do not expect to see a significant change in this focus over the next several years.

Cash Flows

 

      Year Ended December 31,  
     2009     2008     2007  

Cash provided by (used in) (in thousands):

      

Operating activities

   $ 159,827      $ 546,967      $ 329,388   

Investing activities

     (632,951     (432,010     (835,093

Financing activities

     358,673        (69,327     521,795   

As of December 31, 2009, we had a working capital deficit of approximately $26.4 million, a decrease of approximately $62.9 million from December 31, 2008. Our credit agreement covenants specify a minimum liquidity ratio whereby we include the availability under our revolving credit facility, and exclude current maturities of Term Loans, the current portion of derivative assets and liabilities and the current portion of asset retirement obligations. We were in compliance with all of the covenants under our Term Loans at December 31, 2009.

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

Cash provided by operating activities during 2008 and 2007 was $547.0 million and $329.4 million, respectively, primarily due to higher derivative income ($85.1 million) and from changes in working capital during 2008 compared to 2007 ($134.6 million).

Cash used in investing activities was $633.0 million and $432.0 million during 2009 and 2008, respectively. During 2009, cash expended in the Gulf of Mexico and North Sea for additions to oil and gas properties was approximately $551.4 million and $83.9 million, respectively. During 2008, cash expended in the Gulf of Mexico and North Sea for additions to oil and gas properties was approximately $750.8 million and $166.7 million, respectively. Also in 2008, cash received from investing activities includes proceeds, net of costs, from the sale of interests in North Sea properties for $389.2 million and the sale of proved reserves in the form of a limited-term overriding royalty interest for $82.0 million. In 2007, cash expended in the Gulf of Mexico and North Sea for additions to oil and gas properties was approximately $648.7 million and $200.8 million, respectively.

Cash provided by (used in) financing activities was $358.7 million and ($69.3) million during 2009 and 2008, respectively. The amount in 2009 includes proceeds, net of costs, from the sale of a redeemable noncontrolling interest in ATP-IP of $148.8 million, the issuance of common and preferred stock for $306.2 million, net of costs, the monetization of the Gomez hub pipeline for $74.5 million and $14.5 million from sale of an overriding royalty interest. These increases in cash flows were partially offset by $157.5 million of net debt repayments and $19.0 million of distributions to the Class A limited partner in ATP-IP. In 2008, proceeds from and payments of Term Loans in 2008 resulted from the refinancing of $1,202.2 million of borrowings under

 

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our former credit agreement and of $199.5 million of subordinated notes. Further, we repaid $273.3 million of Asset Sale Facility with a portion of the net proceeds from the North Sea property sale noted above. Proceeds from Term Loans are comprised of $1,593.3 million (net of issuance costs) of proceeds from the Term Loans and $31.0 million drawn under our revolving credit facility.

The amount for 2007 was primarily from increases in our Term Loans and issuance of Subordinated Notes of $560.3 million (net of issuance costs) and issuance of 5 million shares of common stock for $226.7 million (net of issuance costs), partially offset by the aggregate $268.2 million repayments of our first and second lien term loans and other debt repayments.

Term Loans

Term Loans consisted of the following (in thousands):

 

     December 31,  
     2009     2008  

Term Loans and revolving credit facility - net of unamortized discount of $28,266 and $35,833, respectively

   $ 1,216,685      $ 1,366,630   

Less current maturities

     (16,838     (10,500
                

Term Loans – noncurrent

   $ 1,199,847      $ 1,356,130   
                

On November 2, 2009, we entered into an amendment (the “First Amendment”) to the Term Loans to maintain compliance with our covenants as of December 31, 2009 and to provide additional flexibility during the Amendment Period. Among other provisions, the First Amendment expands the Net Debt to EBITDAX ratio from 3.0 to 4.0, the EBITDAX to Interest ratio from 2.5 times to 2.0 times and the minimum current ratio from 1.0 to 0.8 for the duration of the Amendment Period. The interest rate on the first tranche Term Loan balance is a minimum 11.25% during the Amendment Period, at the end of which it decreases to a minimum 9.5% for the remainder of the term. The interest rate on the asset sale tranche of Term Loans balance outstanding is a minimum 11.75%. Effective July 1, 2010, the minimum interest rate increases to 12.75% for the remainder of the term.

We paid an initial fee of 0.5% to each of the lender group and the administrative agent of the outstanding balance of the Term Loans at closing plus related expenses for a total of $12.6 million for the First Amendment. Additionally, two fees of up to 0.5% each may be due on the aggregate unpaid balance of Term Loans outstanding at June 30, 2010. Specifically, 0.5% will be due if any portion of the Asset Sale Facility remains outstanding as of that date, and an additional 0.5% will be due if the aggregate balance exceeds $800 million.

On January 29, 2010, we entered into a second amendment (the “Second Amendment”) to the credit agreement governing the Term Loans to maintain compliance with our covenants at December 31, 2009 and to provide us the right to issue unlimited indebtedness in the form of unsecured senior debt, provided that 75% of the net proceeds from any such additional indebtedness are used to repay the outstanding Term Loans.

Additionally, the calculation of trailing-twelve-months EBITDAX, as defined in the Term Loans, was expanded to include, in addition to any amount calculated under the terms of the Term Loans, (i) with respect to, and for any period that includes, the fiscal quarter ended March 31, 2009, $32,086,261, (ii) with respect to, and for any period that includes, the fiscal quarter ended September 30, 2009, $35,767,712, (iii) with respect to, and for any period that includes, the fiscal quarter ended December 31, 2009, $10,926,115 and (iv) with respect to, and for any period that includes, the fiscal quarter ending March 31, 2010, $44,272,499. These amounts represent realized economic gains from certain property transactions during the current and preceding three calendar quarters that did not qualify for gain accounting treatment.

We paid a fee of 0.5% of the outstanding balance of the Term Loans to the lender group and 0.25% of the outstanding balance of the Term Loans and Revolver to the administrative agent at closing, plus related expenses, for a total of $9.2 million for the Second Amendment.

 

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Certain of our financial covenants for 2010 are presented below (also see Note 7, “Term Loans” to the Consolidated Financial Statements):

 

Covenant

   Requirement during the
Amendment Period (4)

1. Minimum Current Ratio (1)(5)

   Greater than 0.8 to 1.0

2. Ratio of Net Debt to EBITDAX (2)(5)

   Less than 4.0 to 1.0

3. Ratio of EBITDAX to Interest Expense (5)

   Greater than 2.0 to 1.0

4. Ratio of PV-10 of Total Proved Developed Producing Reserves based on future prices to Net Debt (3)

   Greater than 0.5 to 1.0

5. Ratio of PV-10 of Total Proved Reserves plus 50% of Pre-tax Probable Reserves based on future prices to Net Debt

   Greater than 2.5 to 1.0

 

(1) The minimum current ratio excludes current maturities of Term Loans, the current portion of assets and liabilities from derivatives and the current portion of asset retirement obligations.
(2) EBITDAX is net income excluding interest, taxes, depletion, impairment, certain exploration costs and other noncash items and is determined based on a trailing twelve month average.
(3) Net Debt is total debt less cash on hand.
(4) Covenants 1-3 are tested at the end of each calendar quarter. Covenants 4 and 5 are tested at year end and at June 30. Covenants 1, 2 and 3 revert to 1.0, 3.0 and 2.5, respectively after the Amendment Period (October 2009 through December 31, 2010).
(5) Reflects the amendments to our Term Loans set forth in the First Amendment and Second Amendment.

Our most restrictive covenants are the minimum current ratio, ratio of net debt to EBITDAX, and ratio of EBITDAX to interest expense. As of December 31, 2009, our actual ratios were 1.2 to 1.0, 3.8 to 1.0 and 2.2 to 1.0, respectively. After considering the First and Second Amendment, we were in compliance with these ratios as of December 31, 2009 and expect to maintain compliance with all of our covenants for the next twelve months. However, significant adverse changes in our expected production levels, commodity prices and reserves or material delays or cost overruns (including our significant development activities at the Telemark Hub) could have a material adverse affect on our financial condition and results of operations and our ability to maintain future compliance with these covenants. An event of noncompliance with any of the required covenants could result in a mandatory repayment under the Term Loans.

An event of default would occur under the Term Loans if there are one or more judgments rendered against us of at least $25 million or that provide for injunctive relief reasonably expected to result in a material adverse effect (“MAE”). A MAE includes (a) a material adverse effect on the business, assets, operations, condition (financial or otherwise) or prospects of us and our subsidiaries, taken as a whole, (b) a material impairment of our ability to perform our obligations under the Term Loans, or (c) a material impairment of the rights of or benefits available to the lenders under the Term Loans. If such a judgment resulting in an MAE were to occur, we would be in default under the Term Loans, which could cause all of our existing indebtedness to become immediately due and payable.

As of December 31, 2009, we were in compliance with the covenants of the Term Loans. However, we entered into the amendments above as the Telemark Hub project is nearing completion, to protect our interests from unforeseen economic hazards, such as project delays, cost overruns, adverse changes to operating conditions or erosion of commodity prices. With the First Amendment and Second Amendment described above, we believe that we will maintain compliance throughout 2010 and beyond.

Recently Issued Accounting Pronouncements

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

 

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Contractual Obligations

The following table summarizes certain contractual obligations at December 31, 2009 (in thousands):

 

Contractual Obligations

   Total    Less than
1 year
   1 – 3
years
   3 – 5
years
   More than
5 years

Term Loans

   $ 1,244,951    $ 16,838    $ 185,363    $ 1,042,750    $ —  

Interest on Term Loans (1)

     470,754      155,214      204,269      111,271      —  

Other long-term obligations (2)

     202,767      30,825      128,608      20,000      23,334

Other trade commitments

     27,412      21,450      5,962      —        —  

Noncancelable operating leases

     1,721      839      882      —        —  
                                  

Total contractual obligations

   $ 1,947,605    $ 225,166    $ 525,084    $ 1,174,021    $ 23,334
                                  

 

(1) Interest is based on rates and principal repayment requirements in effect at December 31, 2009, which were amended on November 2, 2009. (See Term Loan discussion above.)
(2) Omitted from other long-term obligations in this table are $180.8 million of net profits interests payable and overriding royalty interest of $14.9 million as of December 31, 2009 that are payable only from the future cash flows of specified properties. The ultimate amount and timing of the payments will depend on production from the properties and future commodity prices and operating costs. Included in the table above are $87.5 million of contractual commitments that are expected to be paid that are not yet incurred.

Our liabilities include asset retirement obligations (“ARO”) ($43.4 million current and $106.8 million long term) that represent the amount at December 31, 2009 of our obligations with respect to the retirement/plugging and abandonment of our oil and gas properties. The ultimate settlement amounts and the timing of the settlements of such obligations are uncertain because they are subject to, among other things, federal, state and local regulation, economic and operational factors. Consequently, ARO is not reflected in the table above.

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

Based on a critical assessment of our accounting policies discussed below and the underlying judgments and uncertainties affecting the application of those policies, management believes that our consolidated financial statements provide a meaningful and fair 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. Development costs relating to producing properties are depleted on the unit-of-production method on the basis of total estimated units of proved developed reserves. When significant development costs (such as the cost of an offshore production platform) are incurred in connection with a planned group of development wells before all of the planned wells have been drilled, it is occasionally necessary to exclude a portion of those development costs in determining the unit-of-production amortization rate until the additional development wells are drilled. However, in no case are future development costs anticipated in computing our amortization rate. Estimated dismantlement, restoration and abandonment costs and estimated residual salvage values are taken into account in calculating DD&A provisions. Expenditures for geological and geophysical testing costs are generally charged to expense unless the costs can be specifically attributed to mapping a proved reservoir and determining the optimal placement for future developmental well locations. Expenditures for repairs and maintenance are charged to expense as incurred; renewals and betterments are capitalized. The costs and related accumulated DD&A and impairment of properties sold or otherwise retired are eliminated from the accounts, and gains or losses on disposition are reflected in the statements of operations.

 

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

Oil and Gas Reserves

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

Asset Retirement Obligations

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

Other Long-term Obligations

We have significant obligations primarily related to placing the ATP Titan in service and completing and commencing production from the underlying Telemark Hub oil and gas wells. A significant portion of these costs will be paid from net profits interests in the underlying reserves, or under vendor payment deferral arrangements. The recorded liabilities for these costs are affected by some significant estimates, including the

 

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ultimate cost of the obligations, the ultimate reserves produced and the timing of production, which dictates the timing of the future cash payments. Such estimated amounts are discounted so that they are reflected on the consolidated balance sheet at present value. Revisions to these estimates may be required which will result in upward or downward revisions in the recorded long-term obligations on a prospective basis.

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 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.

Price Risk-Management Activities

We periodically enter into commodity derivative contracts and fixed-price physical forward contracts to manage our exposure to oil and natural gas price volatility. We primarily utilize fixed-price physical forward contracts, price swaps and put options, which are generally placed with major financial institutions or with counterparties of high credit quality to minimize our credit risks. The oil and natural gas reference prices of these commodity derivative contracts are based upon oil and natural gas market exchanges, which have a high degree of historical correlation with actual prices we receive. All derivative instruments, unless designated as normal purchases and sales, are recorded on the balance sheet at fair value. Due to a series of net settlements during the fourth quarter of 2008, we determined that we could no longer assert the normal purchase normal sale exception on any of our remaining fixed-price physical forward contracts. As a result, we are now accounting for these contracts as derivatives under the accounting standards for derivatives and hedging, similar to our financial swaps and options contracts, with gains and losses recorded as a component of derivative income (expense) in our consolidated statement of operations.

Changes in the derivative’s fair value are recognized currently in earnings unless specific hedge accounting criteria are met. For qualifying cash flow hedges, hedge accounting rules provide that the gain or loss on the derivative is deferred in accumulated other comprehensive income to the extent the hedge is effective, and such deferred gains or losses are reclassified to oil and natural gas sales revenue in the period that the related production is delivered. At December 31, 2009, we had no derivative contracts in place that qualified for hedge accounting.

Valuation of Deferred Tax Asset

We compute income taxes using an asset and liability approach which results in the recognition of deferred tax liabilities and assets for the expected future tax consequences of temporary differences between the carrying amounts and the tax basis of those assets and liabilities. We also record a valuation allowance if it is more likely than not that some or all of a deferred tax asset will not be realized. In determining whether a valuation allowance is appropriate, we weigh positive and negative evidence that suggests whether a deferred tax asset is likely to be recoverable. As of December 31, 2009, we have a valuation allowance of $4.3 million primarily related to tax benefits from stock options and restricted stock prior to implementation of the accounting standards for stock-based compensation.

Stock-Based Compensation

We recognize compensation expense as vesting occurs for stock-based compensation granted after January 1, 2006, and for share awards that were outstanding and not vested 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.

 

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Off-Balance Sheet Arrangements

The Company has no off-balance sheet arrangements at December 31, 2009.

 

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

Commodity Price Risk

Our revenues, profitability and future growth depend substantially on prevailing prices for oil and natural gas. Prices also affect the amount of cash flow available for capital expenditures and our ability to borrow and raise additional capital. Lower prices may also reduce the amount of oil and natural gas that we can economically produce. We currently sell a portion of our oil and natural gas production under market price contracts. We periodically use derivative instruments to hedge our commodity price risk. We hedge a portion of our projected oil and natural gas production through a variety of financial and physical arrangements intended to support oil and natural gas prices at targeted levels and to manage our exposure to price fluctuations. We may use futures contracts, swaps, put options and fixed-price physical forward contracts to hedge our commodity prices. See Note 15, “Derivative Instruments and Price Risk Management Activities” to the Consolidated Financial Statements.

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 required by the terms of our existing credit agreements. We do not initially hold or issue derivative instruments for speculative purposes.

At March 11, 2010, we had derivative contracts in place for the following oil and natural gas volumes:

 

Period

  

Type

   Volumes    Price
               $/Unit (1)

Oil (Bbl) – Gulf of Mexico

        

2010

   Puts    306,000    24.70

2010

   Swaps    1,316,000    77.18

2011

   Swaps    1,368,750    78.76

2010

   Swaps (2)    612,000    70.00

2011

   Swaps (2)    911,000    78.41

Natural Gas (MMBtu)

        

North Sea

        

2010

  

Fixed-price

physicals

   918,000    6.58

2010

   Swaps    1,375,000    5.43

2011

   Swaps    450,000    5.43

Gulf of Mexico

        

2010

   Fixed-price
physicals
   6,085,000    5.55

2011

   Fixed-price
physicals
   900,000    5.42

2010

   Collars    4,280,000    4.72-7.92

2011

   Collars    1,350,000    4.75-7.95

 

(1) Unit prices for collars reflect the floor and ceiling prices, respectively.
(2) These swaps have been matched with call options to allow us to reparticipate in per barrel price increases above $110.00 and $110.99 in 2010 and 2011, respectively.

Interest Rate Risk

We are exposed to changes in interest rates on our Term Loans described in Management’s Discussion and Analysis of Financial Condition and Results of Operations: Liquidity and Capital Resources, and on the earnings from cash and cash equivalents. See the discussion of our Term Loans in Note 7 to the Consolidated Financial Statements.

 

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Foreign Currency Risk

The net assets, net earnings and cash flows from our wholly owned subsidiaries in the U.K. and the Netherlands are based on the U.S. dollar equivalent of such amounts measured in the applicable functional currency. These foreign operations have the potential to impact our financial position due to fluctuations in the value of the local currency arising from the process of re-measuring the local functional currency in U.S. dollars.

 

Item 8. Financial Statements and Supplementary Data.

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

 

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

None.

 

ITEM 9A. Controls and Procedures

Disclosure Controls and Procedures

Our management, under the supervision of and with the participation of our Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of ATP Oil & Gas Corporation’s disclosure controls and procedures, as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Securities and Exchange Act of 1934, as amended (the “Exchange Act”) as of December 31, 2009. Disclosure controls and procedures are those controls and procedures designed to provide reasonable assurance that the information required to be disclosed in our Exchange Act filings is (1) recorded, processed, summarized and reported within the time periods specified in Securities and Exchange Commission’s rules and forms, and (2) accumulated and communicated to management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.

Based on that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that, as of December 31, 2009, our disclosure controls and procedures were not effective, at the reasonable assurance level, because of the material weakness in internal control over financial reporting described in Management’s Report on Internal Control over Financial Reporting.

In preparing our Exchange Act filings, including this Annual Report on Form 10-K, we implemented additional processes and procedures to provide reasonable assurance that the identified material weakness in our internal control over financial reporting was mitigated with respect to the information that we are required to disclose. As a result, we believe the Company’s consolidated financial statements included in this Annual Report on Form 10-K present fairly, in all material respects, the Company’s financial position, results of operations and cash flows for the periods presented. Our Chief Executive Officer and Chief Financial Officer have certified to their knowledge that this Annual Report on Form 10-K does not contain any untrue statements of material fact or omit to state any 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 in this Annual Report.

Management’s Report on Internal Control over Financial Reporting

Management of the Company is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act. Internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America (“GAAP”). Internal control over financial reporting includes those policies and procedures that (a) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the Company; (b) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with GAAP, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and directors of the Company; and (c) 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 interim or annual consolidated financial statements. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Our management conducted an evaluation of the effectiveness of our internal control over financial reporting as of December 31, 2009 based on the criteria established in “Internal Control — Integrated Framework” issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

Based on the evaluation performed, we identified the following material weakness in our internal control over financial reporting as of December 31, 2009. A material weakness is a deficiency, or combination of deficiencies, such that there is a reasonable possibility that a material misstatement of the annual or interim financial statements will not be prevented or detected on a timely basis.

We did not maintain effective controls over accounting for outstanding liabilities. Specifically, our procedures were not adequate to ensure proper cut-off associated with goods received or services rendered by our vendors and that liabilities were recorded in the appropriate periods. This control deficiency resulted in an audit adjustment to the 2009 consolidated financial statements within accounts payable, accounts receivable from partners, and oil and gas properties. This deficiency could result in a material misstatement to the aforementioned accounts that would result in material misstatement to the annual or interim consolidated financial statements that would not be prevented or detected. Accordingly, management has concluded that this control deficiency constituted a material weakness.

Because of the above described material weakness in internal control over financial reporting, management concluded that our internal control over financial reporting was not effective as of December 31, 2009 based on the criteria set forth in “Internal Control — Integrated Framework” issued by the COSO.

PricewaterhouseCoopers LLP, an independent registered public accounting firm, has audited the effectiveness of our internal control over financial reporting as of December 31, 2009, as stated in their report, which appears in Item 8.

Changes in Internal Control Over Financial Reporting

There were no changes in internal control over financial reporting during the quarter ended December 31, 2009 that materially affected, or are reasonably likely to materially affect our internal control over financial reporting.

Remediation Plan

We believe that the material weakness described above is attributable to factors caused by the substantial activity at year-end 2009 focused on the completion of our major development project at our Telemark Hub.

In order to remediate the material weakness described above, we plan to enhance our process to address such changes in activity by implementing new procedures to seek out additional information from major vendors at each balance sheet date to ensure that we have adequate information to ensure proper cut-off when preparing capital accruals.

 

Item 9B. Other Information.

None.

 

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PART III

 

Item 10. Directors, Executive Officers and Corporate Governance.

Executive Officers of the Company and Other Key Employees

Set forth below are the names, ages (as of February 28, 2010) and titles of the persons currently serving as executive officers of the Company. There are no term limits for the executive officers.

 

Name

  

Age

  

Position

T. Paul Bulmahn

   66    Chairman and Chief Executive Officer

Leland E. Tate

   62    President

Albert L. Reese Jr.

   60    Chief Financial Officer

George R. Morris

   55    Chief Operating Officer

John E. Tschirhart

   59    Senior Vice President, International, General Counsel

Isabel M. Plume

   49    Chief Communications Officer

Keith R. Godwin

   42    Chief Accounting Officer

T. Paul Bulmahn has served as our Chairman and Chief Executive Officer since May 2008 and before that as Chairman and President since he founded the company in 1991. From 1988 to 1991, Mr. Bulmahn served as President and Director of Harbert Oil & Gas Corporation. From 1984 to 1988, Mr. Bulmahn served as Vice President, General Counsel of Plumb Oil Company. From 1978 to 1984, Mr. Bulmahn served as counsel for Tenneco's interstate gas pipelines and as regulatory counsel in Washington, D.C. From 1973 to 1978, he served the Railroad Commission of Texas, the Public Utility Commission and the Interstate Commerce Commission as an administrative law judge.

Leland E. Tate has served as our President since May 2008, before that as Chief Operating Officer since December 2003 and Sr. Vice President, Operations since August 2000. Prior to joining us, Mr. Tate worked for over 30 years with Atlantic Richfield Company (“ARCO”). From 1998 until July 2000, Mr. Tate served as the President of ARCO North Africa. He also was Director General of Joint Ventures at ARCO from 1996 to 1998. From 1994 to 1996, Mr. Tate served as ARCO's Vice President Operations & Engineering, where he led technical negotiations in field development. Prior to 1994, Mr. Tate's positions with ARCO included Director of Operations, ARCO British Ltd.; Vice President of Engineering, ARCO International; Senior Vice President Marketing and Operations, ARCO Indonesia; and for three years was Vice President and District Manager in Lafayette, Louisiana.

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

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

John E. Tschirhart joined us in November 1997 and has served as our General Counsel since March 1998 and Assistant Corporate Secretary since 2007. Mr. Tschirhart was named Senior Vice President International in July 2001 and served as Managing Director of ATP Oil & Gas (UK) Limited from May 2000 to May 2001. He has served on the board of directors of ATP Oil & Gas (UK) Limited and ATP Oil & Gas

 

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(Netherlands) B.V. since the formation of those corporations and currently serves as the Managing Director of ATP Oil & Gas (Netherlands) B.V. From 1993 to November 1997, Mr. Tschirhart worked as a partner at the law firm of Tschirhart and Daines, a partnership in Houston, Texas. From 1985 to 1993 Mr. Tschirhart was in private practice handling civil litigation matters including oil and gas and employment law. From 1979 to 1985, he was with Coastal Oil & Gas Corporation and from 1974 to 1979 he was with Shell Oil Company.

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

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

Except for the information relating to Executive Officers of the Registrant set forth above, the information required by Item 10 of Form 10-K is incorporated herein by reference to the definitive proxy statement for the Company's Annual Meeting of Shareholders to be held on June 4, 2010 (the “Proxy Statement.”)

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

 

Item 11. Executive Compensation.

Incorporated by reference to the Company’s Proxy Statement.

 

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

Incorporated by reference to the Company’s Proxy Statement.

 

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

Incorporated by reference to the Company’s Proxy Statement.

 

Item 14. Principal Accounting Fees and Services.

Incorporated by reference to the Company’s Proxy Statement.

 

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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    Statement of Resolutions Establishing the 8.00% Convertible Perpetual Preferred Stock of ATP Oil & Gas Corporation, incorporated by reference to Exhibit 4.4 of Registration Statement No. 333-162574 on Form S-3 of ATP filed October 19, 2009.
    3.3    Third Amended and Restated Bylaws of ATP Oil & Gas Corporation, incorporated by reference to Exhibit 3.1 of ATP's Current Report on Form 8-K filed December 15, 2009.
    4.1    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.
    4.4    Form of Stock Certificate for 8.00% Convertible Perpetual Preferred Stock, incorporated by reference to Exhibit 4.1 of ATP’s Form 8-K dated September 29, 2009.
†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    Credit Agreement, dated as of June 27, 2008, among ATP, the lenders named therein, and Credit Cuisse, as Administrative Agent and Collateral Agent, incorporated by reference to Exhibit 99.1 to ATP’s Form 8-K dated June 27, 2008.
  10.3    First Amendment, dated as of November 2, 2009, to the Credit Agreement, dated as of June 27, 2008, among ATP Oil & Gas Corporation, the lenders party thereto, and Credit Suisse, Cayman Islands Branch, as Administrative Agent and Collateral Agent, incorporated by reference to Exhibit 99.1 to ATP’s Form 8-K dated November 2, 2009.
  10.4    Second Amendment, dated as of January 29, 2010, to the Credit Agreement, dated as of June 27, 2008, among ATP Oil & Gas Corporation, the lenders party thereto, and Credit Suisse, Cayman Islands Branch, as Administrative Agent and Collateral Agent, incorporated by reference to Exhibit 99.1 to ATP’s Form 8-K dated January 29, 2010.
  10.5    Sale and Purchase Agreement between ATP Oil & Gas (UK) Limited and EDF Production UK Ltd., as amended and restated on October 23, 2008, incorporated by reference to Exhibit 10.1 to ATP's Report on Form 10-Q for the quarter ended September 30, 2008.
†10.6    Employment Agreement between ATP and 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.
†10.7    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.
†10.8    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.

 

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†10.9    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.
†10.10    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.
†10.11    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.
†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.
†10.17    Employment Agreement between ATP and George R. Morris, dated May 27, 2008, incorporated by reference to Exhibit 99.1 to ATP’s Form 8-K dated May 21, 2008.
†10.18    All Employee Bonus Policy, incorporated by reference to exhibit 10.16 to ATP’s Annual Report on Form 10-K for the year ended December 31, 2008.
†10.19    Discretionary Bonus Policy, incorporated by reference to exhibit 10.17 to ATP’s Annual Report on Form 10-K for the year ended December 31, 2008.
  10.20    Purchase Agreement dated September 23, 2009 among the Company, J.P. Morgan Securities Inc. and Credit Suisse Securities (USA) LLC, as representatives of the several Initial Purchasers named therein, incorporated by reference to Exhibit 10.1 of ATP’s Form 8-K dated September 29, 2009.
  21.1    Subsidiaries of ATP, incorporated by reference to Exhibit 21.1 to ATP’s Report on Form 10-Q for the quarter ended March 31, 2009.
*23.1    Consent of PricewaterhouseCoopers LLP.
*23.2    Consent of Deloitte & Touche LLP.
*23.3    Consent of Collarini Associates.
*23.4    Consent of Ryder Scott Company, L.P.
*23.5    Management report of third party engineers – Collarini Associates
*23.6    Management report of third party engineers – Ryder Scott Company, L.P. – Gulf of Mexico
*23.7    Management report of third party engineers – Ryder Scott Company, L.P. - Netherlands
*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

 

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SIGNATURES

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

 

ATP Oil & Gas 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 16, 2010.

 

Signature

    

Title

/S/    T. PAUL BULMAHN        

     Chairman, Chief Executive Officer and Director
T. Paul Bulmahn      (Principal Executive Officer)

/S/    ALBERT L. REESE JR.        

     Chief Financial Officer
Albert L. Reese Jr.      (Principal Financial Officer)

/S/    KEITH R. GODWIN        

     Chief Accounting Officer
Keith R. Godwin      (Principal Accounting Officer)

/S/    CHRIS A. BRISACK        

     Director
Chris A. Brisack     

/S/    ARTHUR H. DILLY        

     Director
Arthur H. Dilly     

/S/    GERARD J. SWONKE        

     Director
Gerard J. Swonke     

/S/    WALTER WENDLANDT        

     Director
Walter Wendlandt     

/S/    BURT A. ADAMS        

     Director
Burt A. Adams     

/S/    ROBERT J. KAROW        

     Director
Robert J. Karow     

/S/    GEORGE R. EDWARDS        

     Director
George R. Edwards     

/S/    LADY BARBARA JUDGE        

     Director
Lady Barbara Judge     

 

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Index to Financial Statements

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

 

     Page

Reports of Independent Registered Public Accounting Firms

   F-2

Consolidated Balance Sheets as of December 31, 2009 and 2008

   F-5

Consolidated Statements of Operations for the years ended December 31, 2009, 2008 and 2007

   F-6

Consolidated Statements of Cash Flows for the years ended December 31, 2009, 2008 and 2007

   F-7

Consolidated Statements of Shareholders’ Equity and Noncontrolling Interest for the years ended December 31, 2009, 2008 and 2007

   F-8

Consolidated Statements of Comprehensive Income for the years ended December 31, 2009, 2008 and 2007

   F-9

Notes to Consolidated Financial Statements

   F-10

Supplemental Disclosures About Oil and Gas Producing Activities (Unaudited)

   F-36

Schedule II – Valuation and Qualifying Accounts for the years ended December  31, 2009, 2008 and 2007

   S-1

 

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Report of Independent Registered Public Accounting Firm

To the Board of Directors and Shareholders of

ATP Oil & Gas Corporation:

In our opinion, the accompanying consolidated balance sheets, and the related consolidated statements of operations, of shareholders’ equity and noncontrolling interest, of comprehensive income and of cash flows present fairly, in all material respects, the financial position of ATP Oil & Gas Corporation and its subsidiaries at December 31, 2009 and 2008, and the results of their operations and their cash flows for each of the two years in the period ended December 31, 2009 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the accompanying index presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. Also in our opinion, the Company did not maintain, in all material respects, effective internal control over financial reporting as of December 31, 2009, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) because a material weakness in internal control over financial reporting related to accounting for outstanding liabilities associated with goods received or services rendered by vendors existed as of that date. A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the annual or interim financial statements will not be prevented or detected on a timely basis. The material weakness referred to above is described in Management’s Report on Internal Control Over Financial Reporting appearing under Item 9A. We considered this material weakness in determining the nature, timing, and extent of audit tests applied in our audit of the December 31, 2009 consolidated financial statements, and our opinion regarding the effectiveness of the Company’s internal control over financial reporting does not affect our opinion on those consolidated financial statements. 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 included in management’s report referred to above. Our responsibility is to express opinions on these financial statements, on the financial statement schedule, and on the Company’s internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

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

 

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

 

/S/ PricewaterhouseCoopers LLP

Houston, Texas

March 16, 2010

 

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Index to Financial Statements

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of

ATP Oil & Gas Corporation

Houston, Texas

We have audited the accompanying consolidated statements of operations, shareholders’ equity, comprehensive income (loss), and cash flows for the year in the period ended December 31, 2007 of ATP Oil & Gas Corporation and subsidiaries (the “Company”). These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the financial statements based on our audit.

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

In our opinion, such consolidated financial statements present fairly, in all material respects, the results of the Company’s operations and cash flows for the year ended December 31, 2007, in conformity with accounting principles generally accepted in the United States of America.

 

/S/ DELOITTE & TOUCHE LLP

Houston, Texas

March 7, 2008

 

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ATP OIL & GAS CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(In Thousands, Except Share Amounts)

 

     December 31,  
     2009     2008  
Assets     

Current assets:

    

Cash and cash equivalents

   $ 108,961      $ 214,993   

Restricted cash

     10,504        —     

Accounts receivable (net of allowance of $291 and $352, respectively)

     52,551        93,915   

Deferred tax asset

     101,956        39,150   

Derivative asset

     1,321        15,366   

Other current assets

     10,615        11,954   
                

Total current assets

     285,908        375,378   

Oil and gas properties (using the successful efforts method of accounting):

    

Proved properties

     3,609,131        2,802,315   

Unproved properties

     13,910        14,705   
                
     3,623,041        2,817,020   

Less accumulated depletion, depreciation, impairment and amortization

     (1,137,269     (944,817
                

Oil and gas properties, net

     2,485,772        1,872,203   

Furniture and fixtures (net of accumulated depreciation)

     342        470   

Deferred financing costs, net

     16,378        13,493   

Other assets, net

     14,747        14,066   
                

Total assets

   $ 2,803,147      $ 2,275,610   
                

Liabilities and Equity

    

Current liabilities:

    

Accounts payable and accruals

   $ 212,736      $ 277,914   

Current maturities of term loans

     16,838        10,500   

Asset retirement obligation

     43,418        32,854   

Derivative liability

     16,216        8,114   

Other current liabilities

     23,094        9,537   
                

Total current liabilities

     312,302        338,919   

Term loans

     1,199,847        1,356,130   

Other long-term obligations

     274,942        2,582   

Asset retirement obligation

     106,781        99,254   

Deferred tax liability

     146,764        101,953   

Derivative liability

     7,646        1,194   

Deferred revenue

     19,336        59,229   
                

Total liabilities

     2,067,618        1,959,261   

Commitments and contingencies (Note 14)

    

Temporary equity – redeemable noncontrolling interest

     139,598        —     

Shareholders’ equity:

    

8% convertible perpetual preferred stock: $0.001 par value, 10,000,000 shares authorized; 1,400,000 issued and outstanding at December 31, 2009; none issued at December 31, 2008; at liquidation value

     140,000        —     

Common stock: $0.001 par value, 100,000,000 shares authorized; 50,755,310 issued and 50,679,470 outstanding at December 31, 2009; 35,979,170 issued and 35,903,330 outstanding at December 31, 2008

     51        36   

Additional paid-in capital

     571,595        400,334   

Retained earnings (accumulated deficit)

     (19,317     29,644   

Accumulated other comprehensive loss

     (95,487     (112,754

Treasury stock, at cost

     (911     (911
                

Total shareholders’ equity

     595,931        316,349   
                

Total liabilities and equity

   $ 2,803,147      $ 2,275,610   
                

See accompanying notes to the consolidated financial statements.

 

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ATP OIL & GAS CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(In Thousands, Except Per Share Amounts)

 

     Year Ended December 31,  
     2009     2008     2007  

Revenues:

      

Oil and gas production

   $ 298,490      $ 584,823      $ 599,324   

Other

     13,664        33,206        8,611   
                        
     312,154        618,029        607,935   
                        

Costs, operating expenses and other:

      

Lease operating

     84,956        91,196        91,693   

Exploration

     264        48        13,756   

General and administrative

     44,211        41,653        32,018   

Depreciation, depletion and amortization

     152,780        246,434        247,378   

Impairment of oil and gas properties

     45,799        125,059        34,342   

Accretion of asset retirement obligation

     11,676        15,566        12,117   

Loss on abandonment

     2,872        13,289        18,649   

Gain on disposition of properties

     (12,433     (119,233     —     

Other, net

     (742     (99     (3,706
                        
     329,383        413,913        446,247   
                        

Income (loss) from operations

     (17,229     204,116        161,688   
                        

Other income (expense):

      

Interest income

     710        3,476        7,603   

Interest expense, net

     (40,884     (100,729     (121,302

Derivative income (expense)

     (712     89,035        —     

Loss on debt extinguishment

     —          (24,220     —     
                        
     (40,886     (32,438     (113,699
                        

Income (loss) before income taxes

     (58,115     171,678        47,989   
                        

Income tax (expense) benefit:

      

Current

     (545     (1,969     1,179   

Deferred

     23,079        (48,004     (548
                        
     22,534        (49,973     631   
                        

Net income (loss)

     (35,581     121,705        48,620   

Less income attributable to the redeemable noncontrolling interest

     (13,380     —          —     

Less convertible preferred stock dividends

     (2,856     —          —     
                        

Net income (loss) attributable to common shareholders

   $ (51,817   $ 121,705      $ 48,620   
                        

Net income (loss) per share attributable to common shareholders:

      

Basic

   $ (1.24   $ 3.43      $ 1.58   
                        

Diluted

   $ (1.24   $ 3.39      $ 1.55   
                        

Weighted average number of common shares:

      

Basic

     41,853        35,457        30,793   

Diluted

     41,853        35,868        31,301   

See accompanying notes to the consolidated financial statements.

 

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Table of Contents
Index to Financial Statements

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In Thousands)

 

     Year Ended December 31,  
     2009     2008     2007  

Cash flows from operating activities

      

Net income (loss)

   $ (35,581   $ 121,705      $ 48,620   

Adjustments to reconcile net income (loss) to net cash provided by operating activities –

      

Depreciation, depletion and amortization

     152,780        246,434        247,378   

Impairment of oil and gas properties

     45,799        125,059        34,342   

Gain on disposition of properties

     (12,433     (119,233     —     

Accretion of asset retirement obligation

     11,676        15,566        12,117   

Deferred income tax expense (benefit)

     (23,079     48,004        548   

Dry hole costs

     —          —          10,251   

Derivative (income) expense

     39,648        (3,976     (86

Loss on debt extinguishment

     —          15,370        —     

Stock-based compensation

     7,951        12,018        7,108   

Amortization of deferred revenue

     (39,893     (22,771     —     

Noncash interest expense

     13,262        14,998        9,874   

Other noncash items, net

     2,443        13,630        13,705   

Changes in assets and liabilities –

      

Accounts receivable and other current assets

     50,402        32,546        (42,766

Accounts payable and accruals

     (53,168     49,658        (2,195

Other assets and liabilities

     20        (2,041     (9,508
                        

Net cash provided by operating activities

     159,827        546,967        329,388   
                        

Cash flows from investing activities

      

Additions to oil and gas properties

     (635,300     (917,523     (849,491

Proceeds from disposition of properties

     13,000        471,846        650   

Decrease (increase) in restricted cash

     (10,504     13,837        14,096   

Additions to furniture and fixtures

     (147     (170     (348
                        

Net cash used in investing activities

     (632,951     (432,010     (835,093
                        

Cash flows from financing activities

      

Proceeds from term loans

     19,000        1,639,750        574,500   

Payments of term loans

     (176,512     (1,680,190     (244,287

Deferred financing costs

     (6,490     (15,523     (14,148

Issuance of common stock, net of costs

     170,629        —          226,706   

Issuance of preferred stock, net of costs

     135,549        —          —     

Net profits interests payments

     (1,929     (13,397     —     

Sale of redeemable noncontrolling interest, net of costs

     148,751        —          —     

Partner distributions

     (18,970     —          —     

Proceeds from pipeline transaction

     74,511        —          —     

Proceeds from dollar-denominated overriding royalty transaction

     14,500        —          —     

Principal payments – dollar-denominated overriding royalty transaction

     (369     —          —     

Payments of capital lease

     —          —          (23,950

Exercise of stock options

     3        33        2,974   
                        

Net cash provided by (used in) financing activities

     358,673        (69,327     521,795   
                        

Effect of exchange rate changes on cash and cash equivalents

     8,419        (30,086     767   
                        

Increase (decrease) in cash and cash equivalents

     (106,032     15,544        16,857   

Cash and cash equivalents, beginning of year

     214,993        199,449        182,592   
                        

Cash and cash equivalents, end of year

   $ 108,961      $ 214,993      $ 199,449   
                        

See accompanying notes to the consolidated financial statements.

 

F-7


Table of Contents
Index to Financial Statements

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY

AND NONCONTROLLING INTEREST

(In Thousands)

 

     2009     2008     2007  
     Shares    Amount     Shares    Amount     Shares    Amount  

Temporary Equity – Redeemable Noncontrolling Interest

               

Balance, beginning of year

      $ —           $ —           $ —     

Sale of Class A Limited Partner Interest, net of formation costs

        148,751           —             —     

Income attributable to the redeemable noncontrolling interest

        13,380           —             —     

Limited partner distributions

        (22,533        —             —     
                                 

Balance, end of year

      $ 139,598         $ —           $ —     
                                 

Shareholders’ Equity:

               

8% Convertible Perpetual Preferred Stock, liquidation value

               

Balance, beginning of year

   —      $ —        —      $ —        —      $ —     

Issuance of preferred stock

   1,400      140,000      —        —        —        —     
                                       

Balance, end of year

   1,400    $ 140,000      —      $ —        —      $ —     
                                       

Common Stock

               

Balance, beginning of year

   35,903    $ 36      35,732    $ 36      30,196    $ 30   

Issuances of common stock

               

Secondary offerings

   14,565      15      —        —        5,000      5   

Exercise of stock options/warrants

   —        —        8      —        302      1   

Restricted stock, net of forfeitures

   211      —        163      —        234      —     
                                       

Balance, end of year

   50,679    $ 51      35,903    $ 36      35,732    $ 36   
                                       

Paid-in Capital

               

Balance, beginning of year

      $ 400,334         $ 388,250         $ 151,467   

Issuances of capital stock

               

Common stock

        179,750           —             226,702   

Costs of issuances

        (13,588        —             —     

Exercise of stock options/warrants

        4           66           2,973   

Stock-based compensation

        7,951           12,018           7,108   

Preferred stock dividends

        (2,856        —             —     
                                 

Balance, end of year

      $ 571,595         $ 400,334         $ 388,250   
                                 

Retained Earnings (Accumulated Deficit)

               

Balance, beginning of year

      $ 29,644         $ (92,061      $ (140,681

Net income (loss)

        (35,581        121,705           48,620   

Income attributable to the redeemable noncontrolling interest

        (13,380        —             —     
                                 

Balance, end of year

      $ (19,317      $ 29,644         $ (92,061
                                 

Accumulated Other Comprehensive Income (Loss)

               

Balance, beginning of year

      $ (112,754      $ 14,552         $ 26,013   

Other comprehensive income (loss)

        17,267           (127,306        (11,461
                                 

Balance, end of year

      $ (95,487      $ (112,754      $ 14,552   
                                 

Treasury Stock, at Cost

               

Balance, beginning of year

   76    $ (911   76    $ (911   76    $ (911
                                       

Balance, end of year

   76    $ (911   76    $ (911   76    $ (911
                                       

Total Shareholders’ Equity

      $ 595,931         $ 316,349         $ 309,866   
                                 

See accompanying notes to the consolidated financial statements.

 

F-8


Table of Contents
Index to Financial Statements

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(In Thousands)

 

     Year Ended December 31,  
     2009     2008     2007  

Net income (loss)

   $ (35,581   $ 121,705      $ 48,620   
                        

Other comprehensive income (loss):

      

Reclassification adjustment for settled hedge contracts (net of taxes of $859, ($5,083) and ($271), respectively)

     (859     5,890        888   

Change in fair value of outstanding hedge positions (net of taxes of ($3,736), $12,237 and $15,281, respectively)

     3,736        (12,677     (17,266

Reclassification adjustment for dedesignated hedge contracts (net of taxes of $0, ($19,288) and $0, respectively)

     —          21,258        —     

Foreign currency translation adjustment, net of tax

     14,390        (141,777     4,917   
                        

Other comprehensive income (loss)

     17,267        (127,306     (11,461
                        

Comprehensive income (loss)

     (18,314     (5,601     37,159   

Less comprehensive income attributable to the redeemable noncontrolling interest

     (13,380