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ATP Oil & Gas 10-Q 2009

Documents found in this filing:

  1. 10-Q
  2. Ex-21.1
  3. Ex-31.1
  4. Ex-31.2
  5. Ex-32.1
  6. Ex-32.2
  7. Ex-32.2
Form 10-Q
Table of Contents

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

 

 

FORM 10-Q

 

 

 

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

For the quarterly period ended March 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 or other jurisdiction of

incorporation or organization)

 

(I.R.S. Employer

Identification No.)

4600 Post Oak Place, Suite 200

Houston, Texas 77027

(Address of principal executive offices)

(Zip Code)

(713) 622-3311

(Registrant’s telephone number, including area code)

 

 

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 Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  ¨    No  ¨

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 definition of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

 

Large accelerated filer   x    Accelerated filer   ¨
Non-accelerated filer   ¨    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 number of shares outstanding of the issuer’s common stock, par value $0.001, as of May 1, 2009, was 36,017,614.

 

 

 


Table of Contents

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

TABLE OF CONTENTS

 

     Page

PART I. FINANCIAL INFORMATION

  

Item 1. Financial Statements (Unaudited)

  

Consolidated Balance Sheets: March 31, 2009 and December 31, 2008

   3

Consolidated Statements of Operations: For the three months ended March 31, 2009 and 2008

   4

Consolidated Statements of Cash Flows: For the three months ended March 31, 2009 and 2008

   5

Consolidated Statement of Equity: For the three months ended March 31, 2009

   6

Consolidated Statements of Comprehensive Income: For the three months ended March 31, 2009 and 2008

   7

Notes to Consolidated Financial Statements

   8

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

   18

Item 3. Quantitative and Qualitative Disclosures about Market Risks

   25

Item 4. Controls and Procedures

   26

PART II. OTHER INFORMATION

   27

 

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PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(In Thousands, Except Share and Per Share Amounts)

(Unaudited)

 

     March 31,
2009
    December 31,
2008
 
Assets     

Current assets:

    

Cash and cash equivalents

   $ 103,380     $ 214,993  

Restricted cash

     13,500       —    

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

     74,485       93,915  

Deferred tax asset

     36,167       39,150  

Derivative asset

     20,194       15,366  

Other current assets

     18,077       11,954  
                

Total current assets

     265,803       375,378  
                

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

    

Proved properties

     2,956,315       2,802,315  

Unproved properties

     15,593       14,705  
                
     2,971,908       2,817,020  

Less accumulated depletion, depreciation, impairment and amortization

     (977,545 )     (944,817 )
                

Oil and gas properties, net

     1,994,363       1,872,203  
                

Furniture and fixtures (net of accumulated depreciation)

     479       470  

Deferred financing costs, net

     12,556       13,493  

Other assets, net

     14,235       14,066  
                

Total assets

   $ 2,287,436     $ 2,275,610  
                
Liabilities and Shareholders’ Equity     

Current liabilities:

    

Accounts payable and accruals

   $ 192,735     $ 277,914  

Current maturities of long-term debt

     10,500       10,500  

Asset retirement obligation

     36,305       32,854  

Derivative liability

     460       8,114  

Deferred tax liability

     20       —    

Other current liabilities

     9,837       9,537  
                

Total current liabilities

     249,857       338,919  

Long-term debt

     1,324,927       1,356,130  

Asset retirement obligation

     97,548       99,254  

Deferred tax liability

     100,202       101,953  

Derivative liability

     2,703       1,194  

Deferred revenue

     47,870       59,229  

Other liabilities

     2,582       2,582  
                

Total liabilities

     1,825,689       1,959,261  
                

Commitments and contingencies (Note 11)

    

Shareholders’ equity:

    

Preferred stock: $0.001 par value, 10,000,000 shares authorized; none issued

     —         —    

Common stock: $0.001 par value, 100,000,000 shares authorized; 36,093,454 issued and 36,017,614 outstanding at March 31, 2009; 35,979,170 issued and 35,903,330 outstanding at December 31, 2008

     36       36  

Additional paid-in capital

     402,531       400,334  

Retained earnings

     31,280       29,644  

Accumulated other comprehensive loss

     (110,100 )     (112,754 )

Treasury stock, at cost

     (911 )     (911 )
                

Total shareholders’ equity

     322,836       316,349  

Noncontrolling interest

     138,911       —    
                

Total equity

     461,747       316,349  
                

Total liabilities and equity

   $ 2,287,436     $ 2,275,610  
                

See accompanying notes to consolidated financial statements.

 

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ATP OIL & GAS CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(In Thousands, Except Per Share Amounts)

(Unaudited)

 

     Three Months Ended
March 31,
 
     2009     2008  

Revenues:

    

Oil and gas production

   $ 68,256     $ 226,037  

Other revenues

     13,664       897  
                
     81,920       226,934  
                

Costs, operating expenses and other:

    

Lease operating

     20,214       24,618  

Exploration

     174       141  

General and administrative

     11,103       9,236  

Depreciation, depletion and amortization

     39,398       89,399  

Impairment of oil and gas properties

     8,049       —    

Accretion of asset retirement obligation

     2,904       4,300  

Loss on abandonment

     997       377  

Loss on disposition of properties

     148       —    

Other, net

     —         13  
                
     82,987       128,084  
                

Income (loss) from operations

     (1,067 )     98,850  
                

Other income (expense):

    

Interest income

     213       1,228  

Interest expense, net

     (12,623 )     (28,127 )

Derivative income

     16,245       40  
                
     3,835       (26,859 )
                

Income before income taxes

     2,768       71,991  
                

Income tax (expense) benefit:

    

Current

     (378 )     (12,436 )

Deferred

     1,252       (12,710 )
                
     874       (25,146 )
                

Net income

     3,642       46,845  

Less: Net income attributable to the noncontrolling interest

     (2,006 )     —    
                

Net income attributable to common shareholders

   $ 1,636     $ 46,845  
                

Net income per share attributable to common shareholders:

    

Basic

   $ 0.05     $ 1.31  
                

Diluted

   $ 0.05     $ 1.29  
                

Weighted average number of common shares:

    

Basic

     35,618       35,824  

Diluted

     35,706       36,247  

See accompanying notes to consolidated financial statements.

 

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ATP OIL & GAS CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In Thousands)

(Unaudited)

 

     Three Months Ended
March 31,
 
     2009     2008  
           (Restated)  

Cash flows from operating activities

    

Net income

   $ 3,642     $ 46,845  

Adjustments to reconcile net income to net cash provided by operating activities –

    

Depreciation, depletion and amortization

     39,398       89,399  

Impairment of oil and gas properties

     8,049       —    

Accretion of asset retirement obligation

     2,904       4,300  

Deferred income taxes

     (1,252 )     12,710  

Derivative expense

     116       —    

Stock-based compensation

     2,195       2,923  

Amortization of deferred revenue

     (11,359 )     —    

Noncash interest expense

     3,734       4,526  

Other noncash items, net

     1,210       1,321  

Changes in assets and liabilities –

    

Accounts receivable and other current assets

     17,720       (6,097 )

Accounts payable and accruals

     (43,472 )     5,753  
                

Net cash provided by operating activities

     22,885       161,680  
                

Cash flows from investing activities

    

Additions to oil and gas properties

     (234,452 )     (250,052 )

Increase in restricted cash

     (13,500 )     —    

Additions to furniture and fixtures

     (88 )     (47 )
                

Net cash used in investing activities

     (248,040 )     (250,099 )
                

Cash flows from financing activities

    

Payments of long-term debt

     (33,812 )     (3,042 )

Net profits interest payments

     —         (3,583 )

Sale of noncontrolling interest

     148,751       —    

Exercise of stock options

     —         28  
                

Net cash provided by (used in) financing activities

     114,939       (6,597 )
                

Effect of exchange rate changes on cash and cash equivalents

     (1,397 )     139  
                

Decrease in cash and cash equivalents

     (111,613 )     (94,877 )

Cash and cash equivalents, beginning of period

     214,993       199,449  
                

Cash and cash equivalents, end of period

   $ 103,380     $ 104,572  
                

Noncash investing and financing activities

    

Decrease in accrued property additions

   $ 55,601     $ 61,036  

Asset retirement costs capitalized

     —         781  

See accompanying notes to consolidated financial statements.

 

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ATP OIL & GAS CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF EQUITY

(In Thousands)

(Unaudited)

 

     Three Months Ended
March 31, 2009
 
         Shares        Amount  

Preferred Stock

     

Balance, beginning of period

   —      $ —    
             

Balance, end of period

   —      $ —    
             

Common Stock

     

Balance, beginning of period

   35,903    $ 36  

Issuance of restricted stock

   115      —    
             

Balance, end of period

       36,018    $ 36  
             

Paid-in Capital

     

Balance, beginning of period

      $ 400,334  

Other

        2  

Stock-based compensation

        2,195  
           

Balance, end of period

      $ 402,531  
           

Retained Earnings

     

Balance, beginning of period

      $ 29,644  

Net income attributable to common shareholders

        1,636  
           

Balance, end of period

      $ 31,280  
           

Accumulated Other Comprehensive Loss

     

Balance, beginning of period

      $ (112,754 )

Other comprehensive income

        2,654  
           

Balance, end of period

      $ (110,100 )
           

Treasury Stock, at Cost

     

Balance, beginning of period

   76    $ (911 )
             

Balance, end of period

   76    $ (911 )
             

Total Shareholders’ Equity

      $ 322,836  
           

Noncontrolling Interest

     

Balance, beginning of period

      $ —    

Sale of Class A Limited Partner Interest, net of legal fees

        148,751  

Net income attributable to the noncontrolling interest

        2,006  

Distributions

        (11,846 )
           

Balance, end of period

      $ 138,911  
           

Total Equity

      $ 461,747  
           

See accompanying notes to consolidated financial statements.

 

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ATP OIL & GAS CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(In Thousands)

(Unaudited)

 

     Three Months Ended
March 31,
 
     2009     2008  

Net income

   $ 3,642     $ 46,845  
                

Other comprehensive income (loss):

    

Reclassification adjustment for settled hedge contracts (net of taxes of $(147), and $(1,079), respectively)

     147       1,472  

Changes in fair value of outstanding hedge positions (net of taxes of $(2,750) and $11,789, respectively)

     2,750       (14,264 )

Foreign currency translation adjustment

     (243 )     688  
                

Other comprehensive income (loss)

     2,654       (12,104 )
                

Comprehensive income

     6,296       34,741  

Less: Comprehensive income attributable to the noncontrolling interest

     (2,006 )     —    
                

Comprehensive income attributable to common shareholders

   $ 4,290     $ 34,741  
                

See accompanying notes to consolidated financial statements.

 

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ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 1 — Organization

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

The consolidated financial statements include our accounts, the accounts of our majority owned limited partnership, ATP Infrastructure Partners, L.P. (“ATP-IP”) and those of our wholly-owned subsidiaries; ATP Energy, Inc., ATP Oil & Gas (UK) Limited, or “ATP (UK),” ATP Oil & Gas (Netherlands) B.V. and three new wholly owned limited liability companies created to own our interests in ATP-IP. All intercompany transactions are eliminated in consolidation, and we separate in the accompanying statements the noncontrolling interest in ATP-IP.

The accompanying unaudited consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”) for interim financial information and reflect all adjustments (consisting of normal recurring adjustments) which are, in the opinion of management, necessary for a fair statement of the results of operations for the interim periods. The interim financial information and notes hereto should be read in conjunction with our 2008 Annual Report on Form 10-K. The results of operations for the quarter ended March 31, 2009 are not necessarily indicative of results to be expected for the entire year. We have reclassified certain amounts applicable to prior periods to conform to the current classifications. Such reclassifications do not affect earnings.

Statements of Cash Flows

During the fourth quarter of 2008, we discovered errors in each of our statements of cash flows included in our previously filed Form 10-Q’s for the quarters ended March 31, June 30 and September 30, 2008. This was the result of not properly considering the application of wire transfer payments in the determination of accrued capital expenditures. The net change in accrued capital expenditures is excluded as a noncash operating and investing activity. This resulted in an understatement of operating cash inflows and an understatement of investing cash outflows in each of the year-to-date cash flows statements included in the respective 10-Q filings.

The information about cash inflows and (outflows) that follows is for only those consolidated statement of cash flow line items affected by the restatement (in thousands):

 

     Three Months Ended
March 31, 2008
 
     As
Reported
    As
Restated
 

Accounts payable and accruals

   $ (29,278 )   $ 5,753  

Net cash provided by operating activities

     126,649       161,680  

Additions to oil and gas properties

     (215,021 )     (250,052 )

Net cash used in investing activities

     (215,068 )     (250,099 )

Note 2 — Recent Accounting Pronouncements

During December 2008, the SEC issued the final rule, “Modernization of Oil and Gas Reporting” (“Final Rule.”) The Final Rule adopts revisions to the SEC’s oil and gas reporting disclosure requirements and is effective for annual reports on Forms 10-K for years ending on or after December 31, 2009. The revisions are

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

 

intended to provide investors with a more meaningful and comprehensive understanding of oil and gas reserves to help investors evaluate their investments in oil and gas companies. The amendments are also designed to modernize the oil and gas disclosure requirements to align them with current practices and changes in technology. Revised requirements in the Final Rule include, but are not limited to:

 

   

Economic producibility of oil and gas reserves must be calculated using the unweighted arithmetic average of the first day of the month price for each month within the prior 12 month period, rather than year-end prices;

 

   

Companies will be allowed to report, on an optional basis, probable and possible reserves;

 

   

Non-traditional reserves, such as oil and gas extracted from coal and shales, will be included in the definition of “oil and gas producing activities;”

 

   

Companies will be permitted to use new technologies to determine proved reserves, as long as those technologies have been demonstrated empirically to lead to reliable conclusions with respect to reserve volumes;

 

   

Companies will be required to disclose, in narrative form, additional details on their proved undeveloped reserves (PUDs), including the total quantity of PUDs at year end, any material changes to PUDs that occurred during the year, investments and progress made to convert PUDs to developed oil and gas reserves and an explanation of the reasons why material concentrations of PUDs in individual fields or countries have remained undeveloped for five years or more after disclosure as PUDs; and

 

   

Companies will be required to report the qualifications and measures taken to assure the independence and objectivity of any business entity or employee primarily responsible for preparing or auditing the reserves estimates.

We are currently evaluating the potential impact of adopting the Final Rule.

In February 2009, the Financial Accounting Standards Board (“FASB”) issued Staff Position (“FSP”) FAS 141(R)-1, “Accounting for Assets Acquired and Liabilities Assumed in a Business Combination That Arise from Contingencies,” which will amend the provisions related to the initial recognition and measurement, subsequent measurement and disclosure of assets and liabilities arising from contingencies in a business combination under Statement of Financial Accounting Standards No. 141(R), “Business Combinations.” This standard has no impact on our financial statements at this time.

In April 2009, the FASB issued FSP FAS 107-1 and APB 28-1, “Interim Disclosures about Fair Value of Financial Instruments,” which requires that the fair value disclosures in SFAS No. 107, “Disclosures about the Fair Value of Financial Instruments,” be included in interim financial statements. We will adopt this FSP in the second quarter 2009.

Note 3 — 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 there can be no assurance that oil and gas prices will not be subject to wide fluctuations in the future. Prices for oil and gas have recently declined materially. Any continued and 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 (“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,

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

 

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 ultimate quantity of oil and natural gas that we ultimately produce. Approximately 84% 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 and cash flows.

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 limits 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 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 a continuation of 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 to the adverse economic and industry conditions, and limit our ability to obtain the additional financing required to successfully operate our business. Our inability to satisfy the covenants or other contractual requirements contained in our Term Loans would constitute an event of default. A 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. Given current market conditions, 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 additional capital. Further, the current economic conditions 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.

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 intend to finance our near-term development projects utilizing cash on hand and cash flows from operations. To the extent we are successful in selling selected assets, we may use the proceeds in excess of our required debt repayments to fund additional development opportunities, to further reduce our debt or for added liquidity. 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 concept and its 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.

Note 4 — Income Taxes

Income tax expense during interim periods is based on the estimated annual effective income tax rate plus any significant, unusual or infrequently occurring items that are recorded in the period the specific item occurs. 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 financial basis and the tax basis of those assets and liabilities. We recognized income tax benefit of $0.9 million and income tax expense of $25.1 million for the three months ended March 31, 2009 and 2008, respectively. The worldwide effective tax rates for the first three months of 2009 and 2008 were (31.6%) and 34.9%, respectively.

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

 

Note 5 — Oil and Gas Properties

Acquisitions

During the first quarter of 2009, we were the high bidder on Green Canyon Block 344, a lease south of our Green Canyon Blocks 299 and 300 (collectively “Clipper”) properties in the Gulf of Mexico. The acquisition is expected to cost $0.3 million and is expected to close in June 2009, subject to U.S. Department of Interior Minerals Management Service (“MMS”) approval. We will have a working interest in the lease of between 100% and 55.3%, depending on whether other parties with working interests in nearby leases elect to exercise their right to share in this acquisition.

During the first quarter of 2008, we were awarded leases for 100% of the working interests in Viosca Knoll Block 863 and De Soto Canyon Block 355 by the MMS. The aggregate cash acquisition price for these leases was $0.7 million.

Formation of Limited Partnership

On March 6, 2009, along with GE Energy Financial Services (“GE”), we formed 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. At March 31, 2009, $13.5 million of that cash remained restricted and was released to us in April 2009 once certain conditions agreed to at closing were met. 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. 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 and may be subject to a minimum fee of $53,000 per day for up to 180 days. Such minimum fees, if applicable, can be recovered in future periods whenever fees owed during a month exceed the minimum due. We made no 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 pro rata in partnership net income and regular minimum quarterly cash distributions in accordance with the provisions of the ATP-IP partnership agreement.

We created three wholly owned limited liability companies (the “LLCs”) to own our interests in ATP-IP, and as the General Partner we consolidate ATP-IP and the LLCs. The contribution of the ATP Innovator was accounted for as a transfer of assets between entities under common control. Accordingly, ATP-IP recorded the ATP Innovator at its carryover cost basis and no gain or loss was recognized. We have historically subjected the ATP Innovator costs to units-of-production depletion over the proved reserves attributable to our Gomez Hub. ATP-IP owns no reserves and recognizes depreciation expense for the ATP Innovator on a straight-line basis over an estimated useful life of 25 years. We incurred costs associated with the formation of the partnership of approximately $3.4 million which were charged to general and administrative expense.

Under U.S. federal income tax laws, ATP-IP is not a taxable entity and all distributable items of income and deductible expenses flow through to the partners in accordance with the agreements. Additionally, the new LLCs we formed are all wholly owned, and as such are disregarded entities for U.S. federal income tax purposes.

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

 

Impairment of oil and Gas Properties

During first quarter 2009, we recorded impairment expense of $8.0 million related to a Gulf of Mexico shelf property. The impairment was primarily due to relinquishment of a lease related to poor operating performance. All of the carrying costs related to this property have been written off to impairment expense. We also recorded a $1.0 million loss on abandonment related to this property.

Note 6 — Asset Retirement Obligation

Following are reconciliations of the beginning and ending asset retirement obligation for the following periods (in thousands):

 

     Three Months Ended
March 31,
 
     2009     2008  

Asset retirement obligation, beginning of period

   $ 132,108     $ 186,771  

Liabilities incurred

     36       1,158  

Liabilities settled

     (1,521 )     (2,683 )

Property dispositions

     (292 )     —    

Changes in estimates

     618       202  

Accretion expense

     2,904       4,300  
                

Total asset retirement obligation

     133,853       189,748  

Less current portion

     36,305       26,417  
                

Total long-term asset retirement obligation, end of period

   $ 97,548     $ 163,331  
                

Note 7 — Long-Term Debt

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

 

     March 31,
2009
    December 31,
2008
 

Term Loans – tranche B-1

   $ 1,042,124     $ 1,044,749  

Term Loans – Asset Sale Facility

     295,527       326,714  

Term Loans – revolving credit facility

     31,000       31,000  

Unamortized discount

     (33,224 )     (35,833 )
                

Total debt

     1,335,427       1,366,630  

Less current maturities

     10,500       10,500  
                

Total long-term debt

   $ 1,324,927     $ 1,356,130  
                

The Term Loans include a tranche B-1 Loan of, initially, $1.05 billion, maturing July 2014, and a tranche B-2 Loan of, initially, $600.0 million (the “Asset Sale Facility”), maturing January 2011. The Term Loans were issued with an original issue discount of 2.5% and bear interest at LIBOR plus 5.25% (with a LIBOR floor of 3.25%). The $1.05 billion tranche requires a $2.63 million principal repayment per calendar quarter until September 2013, and four quarterly repayments of $249.4 million thereafter. The Asset Sale Facility is due in full at maturity and allows for prepayment at any time at par. The Term Loans are secured by substantially all of our oil and gas assets in the Gulf of Mexico and a pledge of 65% of the common stock of our wholly owned subsidiaries, ATP Oil & Gas (UK) Limited and ATP Oil and Gas (Netherlands) B.V. The Term Loans—revolving credit facility has a final maturity of July 2013. During the first quarter 2009, we repaid $31.2 million of the Asset Sale Facility in accordance with our Term Loans agreement related to amounts received from the sale of the noncontrolling interest discussed above.

The combined effective annual interest rate under the Term Loans at March 31, 2009 and December 31, 2008 was approximately 9.34% and 9.86%, respectively.

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

 

Note 8 — Stock–Based Compensation

We recognized stock option compensation expense of $0.8 million, and $0.7 million for the three months ended March 31, 2009 and 2008, respectively. We recognized restricted stock compensation expense of $1.4 million, and $2.2 million for the three months ended March 31, 2009 and 2008, respectively.

There were no options granted during the three months ended March 31, 2009. The fair values of options granted during the three months ended March 31, 2008 were estimated at the date of grant using a Black-Scholes option-pricing model assuming no dividends and with the following weighted average assumptions:

 

Weighted average volatility

     39.2 %

Expected term (in years)

     3.8  

Risk-free rate

     2.3 %

Weighted average fair value of options – grant date

   $ 11.40  

The following table sets forth a summary of option transactions for the three months ended March 31, 2009:

 

     Number of
Options
    Weighted
Average
Grant
Price
   Aggregate
Intrinsic
Value (1)
($000)
   Weighted
Average
Remaining
Contractual
Life
                     (in years)

Outstanding at beginning of period

   1,405,355     $ 26.18      

Forfeited

   (1,375 )     47.77      

Expired

   (3,500 )     6.28      
              

Outstanding at end of period

   1,400,480       26.21    $ —      3.3
                    

Vested and expected to vest

   1,273,360       26.20    $ —      3.2
                    

Options exercisable at end of period

   403,063       30.36    $ —      1.8
                    
 
  (1) Based upon the difference between the market price of the common stock on the last trading day of the period and the option exercise price of in-the-money options.

At March 31, 2009, unrecognized compensation expense related to nonvested stock option grants totaled $4.0 million. Such unrecognized expense will be recognized as vesting occurs over a weighted average period of 2.8 years.

At March 31, 2009, unrecognized compensation expense related to restricted stock totaled $5.9 million. Such unrecognized expense will be recognized as vesting occurs over a weighted average period of 2.1 years. The following table sets forth the changes in nonvested restricted stock for the three months ended March 31, 2009:

 

     Number of
Shares
    Weighted
Average
Grant-date
Fair Value
   Aggregate
Intrinsic
Value (1)
($000)

Nonvested at beginning of period

   345,705     $ 43.44   

Granted

   114,284       5.85   

Vested

   (66,017 )     48.80   
           

Nonvested at end of period

   393,972       31.64    $ 2,021.0
               
 
  (1) Based upon the closing market price of the common stock on the last trading day of the period.

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

 

Note 9 — Earnings Per Share

Basic earnings per share (“EPS”) is computed by dividing net income or loss attributable to common shareholders by the weighted average number of shares of common stock (other than nonvested restricted stock) outstanding during the period. Weighted average shares outstanding for diluted EPS also includes a hypothetical number of shares assuming all in-the-money options and warrants would have been exercised and vesting of restricted stock. Potential common shares are excluded from the computation of weighted average common shares outstanding when their effect is antidilutive. In the table below, stock-based awards for 1,753,000 and 318,000 average shares of common stock for the three months ended March 31, 2009 and 2008, respectively, were excluded from the diluted EPS calculation because their inclusion would have been antidilutive.

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

 

     Three Months Ended
March 31,
     2009    2008

Net income attributable to common shareholders

   $ 1,636    $ 46,845
             

Shares outstanding:

     

Weighted average shares outstanding - basic

     35,618      35,824

Effect of potentially dilutive securities - stock options and warrants

     —        304

Nonvested restricted stock

     88      119
             

Weighted average shares outstanding - diluted

     35,706      36,247
             

Net income per share attributable to common shareholders:

     

Basic

   $ 0.05    $ 1.31
             

Diluted

   $ 0.05    $ 1.29
             

Note 10 — Derivative Instruments and Risk Management Activities

We periodically enter into commodity derivative contracts and fixed-price physical contracts to manage our exposure to oil and natural gas price volatility. We primarily utilize fixed-price physical forward contracts, price swaps, price collars and put options which are generally placed with major financial institutions or with counterparties of high credit quality in order to minimize our credit risks. The oil and natural gas reference prices of these commodity derivative contracts are based upon oil and natural gas market exchanges which have a high degree of historical correlation with the actual prices we receive. All derivative instruments are recorded on the balance sheet at fair value.

Gains and losses for derivatives which have not been designated as hedges under FAS 133 are recorded as components of derivative income (expense) in our consolidated statement of operations. Gains and losses for derivatives which have been designated as hedges under FAS 133 are recorded instead to accumulated other comprehensive income until the period in which the forecasted hedged transactions occur, at which time the gains and losses are reclassified from accumulated other comprehensive income to the consolidated statement of operations as components of the revenue or expense items to which they relate. Hedge ineffectiveness is recorded directly to the consolidated statement of operations. Settlements of commodity derivative instruments are included in cash flows from operating activities in our consolidated statement of cash flows.

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

 

At March 31, 2009, we had derivative contracts for the following natural gas and oil volumes:

 

                    Net Fair Value Asset
(Liability) (2)
 

Period

  

Type

   Volumes    Price    Current     Noncurrent  
               $/Unit (1)    ($000)     ($000)  

Oil (Bbl) – Gulf of Mexico

             

Remainder of 2009

   Puts    1,375,000    $ 29.75    $ —       $ 435  

2010

   Puts    365,000      24.70      —         73  

Natural Gas (MMBtu)

             

North Sea

             

Remainder of 2009

   Swaps (2)    1,674,000      5.41      40       —    

2010

   Collars    1,825,000      5.40-8.12      (501 )     (1,092 )

2011

   Collars    270,000      5.40-8.12      —         (616 )

Gulf of Mexico

             

Remainder of 2009

   Fixed-price physicals    8,225,000      6.83      20,145       —    

2010

   Fixed-price physicals    900,000      5.02      (650 )     —    

Remainder of 2009

   Collars    1,375,000      4.00-7.00      428       —    

2010

   Collars    4,575,000      4.68-7.86      272       (596 )

2011

   Collars    1,350,000      4.75-7.95      —         (907 )
                         

Total

            $ 19,734     $ (2,703 )
                         

Derivative asset

            $ 20,194     $ —    

Derivative liability

              (460 )     (2,703 )
                         

Total

            $ 19,734     $ (2,703 )
                         

 

(1) Unit price for price collars reflects the floor and the ceiling prices, respectively.
(2) None of the derivatives outstanding as of March 31, 2009 are designated as hedges under SFAS No. 133 for accounting purposes, except for the North Sea natural gas swap contracts.

The following table shows where gains and losses (net of taxes) on cash flow hedge derivatives have been reported for the three months ended March 31, 2009 (in thousands). Within the 12-month period ended March 31, 2010, the entire March 31, 2009 accumulated other comprehensive income (loss) (“AOCI”) balance is estimated to be reclassified to earnings based on forecasted gas production:

 

AOCI for cash flow hedges - beginning of period

   $ (2,877 )

Designated derivatives’ gains

     2,750  

Losses reclassified from AOCI to oil and gas revenues

     147  
        

AOCI for cash flow hedges – end of period

   $ 20  
        

Nondesignated derivatives gains in derivative income

   $ 16,245  
        

Our derivative income for the quarter ended March 31, 2009 consists of the following (in thousands):

 

Realized gains from:

  

Settlements of natural gas contracts

   $ 13,627  

Early terminations of natural gas contracts

     2,734  

Unrealized loss on open contracts

     (116 )
        
   $ 16,245  
        

Note 11 — Commitments and Contingencies

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

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

 

During the term of our Platform Use Agreement, we are obligated to pay to ATP-IP a a minimum fee or a per unit fee for all hydrocarbons processed by the ATP Innovator and we are responsible for all of the operating costs and periodic maintenance of the ATP Innovator.

In the normal course of business we occasionally purchase oil and gas properties for little or no up-front costs and instead commit to pay consideration contingent upon the successful development and operation of the properties. The contingent consideration generally includes amounts to be paid upon achieving specified operational milestones, such as first commercial production and again upon achieving designated cumulative sales volumes. At March 31, 2009 the aggregate amount of such contingent commitments was $9.4 million.

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

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

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

Note 12 — Segment Information

The Company’s operations are focused in the Gulf of Mexico and in the North Sea. Management reviews and evaluates separately the operations of its Gulf of Mexico segment and its North Sea segment. The operations of both segments include natural gas and liquid hydrocarbon production and sales. Segment activity for the three months ended March 31 2009 and 2008 is as follows (in thousands):

 

     Gulf of
Mexico
    North Sea     Total  

For the Three Months Ended –

      

March 31, 2009:

      

Revenues

   $ 78,721     $ 3,199     $ 81,920  

Depreciation, depletion and amortization

     34,063       5,335       39,398  

Income (loss) from operations

     4,004       (5,071 )     (1,067 )

Interest income

     213       —         213  

Interest expense, net

     12,623       —         12,623  

Derivative income

     12,167       4,078       16,245  

Income tax (expense) benefit

     (145 )     1,019       874  

Additions to oil and gas properties

     158,451       10,405       168,856  

Total assets

     2,047,377       240,059       2,287,436  

March 31, 2008:

      

Revenues

   $ 179,789     $ 47,145     $ 226,934  

Depreciation, depletion and amortization

     56,175       33,224       89,399  

Income from operations

     93,273       5,577       98,850  

Interest income

     594       634       1,228  

Interest expense, net

     28,061       66       28,127  

Income tax expense

     23,575       1,571       25,146  

Additions to oil and gas properties

     179,003       11,042       190,045  

Total assets

     1,641,954       637,622       2,279,576  

 

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ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

 

Note 13 — Fair Value Measurements

The fair value of our derivative contracts is classified as Level 3 based on the significant unobservable inputs into our expected present value model. The following table sets forth a reconciliation of changes in the fair value of these financial assets (liabilities) during the first quarter of 2009 (in thousands):

 

     Gas Fixed-
Price
Physical
U.S.
    Gas Price
Collar
U.S.
    Oil Put
U.S.
    Financial
Gas Swap
U.K.
    Gas Price
Collar
U.K.
    Total  

Balance at beginning of period

   $ 15,366     $ —       $ —       $ (8,361 )   $ —       $ 7,005  

Total gain included in other comprehensive income

     —         —         —         5,500       —         5,500  

Derivative income (expense)

     14,202       (803 )     (1,232 )     6,232       (2,209 )     16,190  

Settlements, terminations and purchases

     (10,073 )     —         1,740       (3,331 )     —         (11,664 )
                                                

Balance at end of period

   $ 19,495     $ (803 )   $ 508     $ 40     $ (2,209 )   $ 17,031  
                                                

Changes in unrealized income (loss) included in derivative income relating to derivatives still held at March 31, 2009

   $ 11,618     $ (803 )   $ (1,232 )   $ —       $ (2,209 )   $ 7,374  
                                                

 

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ATP OIL & GAS CORPORATION AND SUBSIDIARIES

 

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

Executive Overview

General

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

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

 

   

significant undeveloped reserves and reservoirs;

 

   

close proximity to developed markets for oil and natural gas;

 

   

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

 

   

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

Our focus is on acquiring properties that 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 which they believe offer greater reserve potential. Some projects may provide lower economic returns to a company due to its cost structure within that company. Also, due to timing or budget constraints, a company may be unwilling or unable to develop a property before the expiration of the lease. 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 costs of the previous owner. This strategy coupled with our expertise in our areas of focus and our ability to develop projects may make the acquired oil and gas properties more financially attractive to us than to the seller. Given our strategy of acquiring properties that contain proved reserves, or where previous drilling indicates to us the presence of recoverable hydrocarbons, our operations typically are lower risk than exploration-focused Gulf of Mexico and North Sea operators.

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 already defined targeted reservoirs, which eliminates 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. 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.

First Quarter 2009 Highlights

 

   

Net income of $1.6 million or $0.05 per basic and diluted share;

 

   

Production of 10.0 Bcfe (55% oil);

 

   

Completed and achieved initial production from two wells, one at the Gomez Hub in the Gulf of Mexico and one at Wenlock in the North Sea;

 

   

Formed a new infrastructure partnership, ATP Infrastructure Partners, L.P. (“ATP-IP”), to own the ATP Innovator;

 

   

Repaid $31.2 million of debt in March 2009 and an additional $5.2 million of debt in May 2009 with the proceeds received relating to ATP-IP.

 

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On March 6, 2009, along with GE Energy Financial Services (“GE”), we formed 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. At March 31, 2009, $13.5 million of that cash remained restricted and was released to us in April 2009 once certain conditions agreed to at closing were met. 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. 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 and may be subject to a minimum fee of $53,000 per day for up to 180 days. Such minimum fees, if applicable, can be recovered in future periods whenever fees owed during a month exceed the minimum due. We made no 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 pro rata in partnership net income and regular minimum quarterly cash distributions in accordance with the provisions of the ATP-IP partnership agreement.

Additional discussion of our expectations for 2009 can be found in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our 2008 Annual Report on Form 10-K.

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 there can be no assurance that oil and gas prices will not be subject to wide fluctuations in the future. Prices for oil and gas have recently declined materially. Any continued and 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 (“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 ultimate quantity of oil and natural gas that we ultimately produce. Approximately 84% 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 and cash flows.

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 limits 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 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 a continuation of adverse commodity prices

 

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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 to the adverse economic and industry conditions, and limit our ability to obtain the additional financing required to successfully operate our business. Our inability to satisfy the covenants or other contractual requirements contained in our Term Loans would constitute an event of default. A 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. Given current market conditions, 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 additional capital. Further, the current economic conditions 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.

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 intend to finance our near-term development projects utilizing cash on hand and cash flows from operations. To the extent we are successful in selling selected assets, we may use the proceeds in excess of our required debt repayments to fund additional development opportunities, to further reduce our debt or for added liquidity. 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 concept and its 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

Three Months Ended March 31, 2009 Compared to Three Months Ended March 31, 2008

For the three months ended March 31, 2009 and 2008 we reported net income attributable to common shareholders of $1.6 million and $46.8 million, or net income of $0.05 and $1.29 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 under fixed-price delivery contracts which have been designated for the normal purchase and sale exception under Statement of Financial Accounting Standards (“SFAS”) No. 133 are also included in these amounts for the three months ended March 31, 2008. For that period, deliveries under the fixed-price contracts are approximately 73% of our oil production and 83% of our natural gas production. 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 fair value during the period are reflected as derivative income instead of oil and gas revenues in our consolidated statement of operations.

The table below includes oil and gas production revenues from amortization of deferred revenue related to second quarter 2008 sale of the limited-term overriding royalty interest. We do not reflect any production associated with those revenues.

 

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     Three Months Ended
March 31,
    % Change
from 2008

to 2009
 
     2009     2008    

Production:

      

Natural gas (MMcf)

     4,474       11,844     (62 )%

Oil and condensate (MBbl)

     915       1,622     (44 )%

Total (MMcfe)

     9,963       21,574     (54 )%

Gulf of Mexico (MMcfe)

     9,370       16,122     (42 )%

North Sea (MMcfe)

     594       5,451     (89 )%

Revenues from production (in thousands):

      

Natural gas

   $ 21,530     $ 107,340     (80 )%

Effects of cash flow hedges

     (296 )     (1,242 )  

Amortization of deferred revenue

     1,956       —      
                  

Total

   $ 23,190     $ 106,098     (78 )%
                  

Oil and condensate

   $ 35,662     $ 121,248     (71 )%

Effects of cash flow hedges

     —         (1,309 )  

Amortization of deferred revenue

     9,404       —      
                  

Total

   $ 45,066     $ 119,939     (62 )%
                  

Natural gas, oil and condensate

   $ 57,192     $ 228,588     (75 )%

Effects of cash flow hedges

     (296 )     (2,551 )  

Amortization of deferred revenue

     11,360       —      
                  

Total

   $ 68,256     $ 226,037     (70 )%
                  

Average realized sales price:

      

Natural gas (per Mcf)

   $ 4.81     $ 9.06     (49 )%

Effects of cash flow hedges (per Mcf)

     (0.07 )     (0.10 )  
                  

Average realized price (per Mcf)

   $ 4.74     $ 8.96     (47 )%
                  

Oil and condensate (per Bbl)

   $ 38.97     $ 74.77     (48 )%

Effects of cash flow hedges (per Bbl)

     —         (0.81 )  
                  

Average realized price (per Bbl)

   $ 38.97     $ 73.96     (47 )%
                  

Natural gas, oil and condensate (per Mcfe)

   $ 5.74     $ 10.60     (47 )%

Effects of cash flow hedges (per Mcfe)

     (0.03 )     (0.12 )  
                  

Average realized price (per Mcfe)

   $ 5.71     $ 10.48     (46 )%
                  

Revenues from production decreased in first quarter 2009 compared to first quarter 2008 due to a 54% decrease in overall production and a 46% decrease in average realized sales price (48% price decrease in Gulf of Mexico and 38% price decrease in North Sea) The lower production in the Gulf of Mexico is primarily the result of decreases at the Gomez Hub associated with the hurricanes in 2008 and the second quarter 2008 sale of a 15% limited-term overriding royalty interest in production. 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. The lower average realized sales price is due to decreased commodity market prices.

Other Revenues

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

Lease Operating

Lease operating expenses include costs incurred to operate and maintain wells and related equipment and facilities. These costs include, among others, workover expenses, operator fees, processing fees, insurance and transportation. Lease operating expense for the quarters ended March 31, 2009 and 2008 was as follows:

 

     Three Months Ended
March 31,
   % Change
from 2008

to 2009
 
     2009    2008   

Lease operating (in thousands)

   $ 20,214    $ 24,618    (18 )%

Per Mcfe

     2.03      1.14    78 %

Gulf of Mexico

     1.95      1.09    79 %

North Sea

     3.33      1.28    160 %

 

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Lease operating expense for first quarter 2009 decreased compared to first quarter 2008 primarily due to due to the sale of 80% of our working interest in Tors and Wenlock in fourth quarter 2008. The per unit cost has increased primarily due to the effect of fixed costs on lower production volumes.

General and Administrative

General and administrative expenses are overhead-related expenses, including employee compensation, legal and accounting fees, insurance, and investor relations expenses. General and administrative expense for the quarters ended March 31, 2009 and 2008 was as follows:

 

     Three Months Ended
March 31,
   % Change
from 2008

to 2009
 
     2009    2008   

General and administrative (in thousands)

   $ 11,103    $ 9,236    20 %

Per Mcfe

     1.11      0.43    158 %

The general and administrative expense increase for first quarter 2009 compared to first quarter 2008 is primarily attributable to $3.4 million in costs associated with formation of the limited liability partnership discussed above.

Depreciation, Depletion and Amortization

Depreciation, depletion and amortization (“DD&A”) expense for the quarters ended March 31, 2009 and 2008 was as follows:

 

     Three Months Ended
March 31,
   % Change
from 2008

to 2009
 
     2009    2008   

DD&A (in thousands)

   $ 39,398    $ 89,399    (56 )%

Per Mcfe

     3.95      4.14    (5 )%

DD&A expense first quarter 2009 decreased compared to first quarter 2008 primarily due to decreased production.

Impairment of Oil and Gas Properties

During first quarter 2009, we recorded impairment expense of $8.0 million related to a Gulf of Mexico shelf property. The impairment was primarily due to relinquishment of a lease related to poor operating performance. All of the carrying costs related to this property have been written off to impairment expense.

Accretion of Asset Retirement Obligation

Accretion expense of $2.9 million in first quarter 2009 is decreased compared to $4.3 million in first quarter 2008 primarily due to extension of the forecasted productive lives of our oil and gas properties.

Loss on Abandonment

We recognized aggregate loss on abandonment during first quarter 2009 and first quarter 2008 which were the result of actual abandonment costs exceeding the previously accrued estimates, due to unforeseen circumstances that required additional work or the use of equipment more expensive than anticipated and unanticipated vendor price increases. In addition in 2009 we recorded a loss due to acceleration of the timing of abandonment activities on an impaired property.

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.

 

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Interest Expense

Interest expense decreased to $12.6 million for first quarter 2009 compared to $28.1 million for first quarter 2008 primarily due to 2009 capitalized interest of $20.9 million ($19.7 million related to the construction of the ATP Titan and $1.2 million related to Cheviot in the U.K.) compared to capitalized interest of $5.9 million in first quarter 2008.

Derivative Income

Derivative income in first quarter 2009 was $16.2 million (gains of $12.2 million and $4.0 million in the Gulf of Mexico and North Sea, respectively). The income in 2009 is primarily related to realized gains associated with settlement and termination of certain gas contracts.

Income Taxes

We recorded income tax benefit of $0.9 million during first quarter 2009 resulting in an overall effective tax rate of (31.6%). In each jurisdiction, the rates were determined based our expectations of net income or loss for the year, taking into consideration permanent differences. In the comparable quarter of 2008 we recorded tax expense of $25.1 million resulting in an overall effective tax rate of 34.9%.

Net Income Attributable to the Noncontrolling Interest

Net income attributable to the noncontrolling interest represents the 49% Class A limited partner interest owned by GE in ATP-IP for the period from inception of the partnership (March 6, 2009) through March 31, 2009.

Liquidity and Capital Resources

Historically, we have financed our acquisition and development activities through a combination of bank borrowings, proceeds from equity offerings, cash from operations and the sale of interests in selected properties. The disarray in the credit markets in 2008 has 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 the first quarter 2009, we raised $148.8 million of capital from the formation of a limited partnership as discussed above.

We intend to utilize cash on hand and cash flows generated from our operations to fund our near term capital expenditures, which are currently estimated to be between $300 million and $400 million in 2009. As operator of most of our projects under development, we have the ability to significantly control the 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 2009, we desire to sell selected assets during 2009, 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. Still, we believe that we will be able to sell selected assets in 2009, allowing us to meet our debt reduction goals and providing us with additional capital for general corporate purposes or additional development, if appropriate. Our revenues, profitability and cash flows are highly dependent upon many factors, particularly our production results and the price of oil and natural gas. To mitigate future price volatility, we may hedge the sales price of our future production.

For the longer term, we will continue to deploy the same or similar tactics. 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 see a significant change in this focus over the next several years. We believe this flexibility coupled with our hedging program and our success in selling assets, provides us the financial resources needed to fully fund our future development programs.

Cash Flows

 

     Three Months Ended
March 31,
 
     2009     2008  

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

    

Operating activities

   $ 22,885     $ 161,680  

Investing activities

     (248,040 )     (250,099 )

Financing activities

     114,939       (6,597 )

 

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As of March 31, 2009, we had working capital of approximately $15.9 million, a decrease of approximately $20.6 million from December 31, 2008.

Cash provided by operating activities during first quarter 2009 and 2008 was $22.9 million and $161.7 million, respectively. Cash flow from operations decreased primarily due to lower net income and from changes in working capital in first quarter 2009 compared to first quarter 2008. Net income in first quarter 2009 decreased primarily due to lower production and lower commodity prices discussed above.

Cash used in investing activities was $248.0 million and $250.1 million during first quarter 2009 and 2008, respectively. Cash expended in the Gulf of Mexico and North Sea for additions to oil and gas properties was approximately $201.4 million and $33.1 million, respectively, in first quarter 2009. Cash expended in the Gulf of Mexico and North Sea for additions to oil and gas properties was approximately $184.5 million and $65.6 million, respectively, in first quarter 2008.

Cash provided by (used in) financing activities was $114.9 million and ($6.6) million during first quarter 2009 and 2008, respectively. The amount in first quarter 2009 is from sale of a noncontrolling interest in our limited partnership partially offset by $33.8 million of debt repayments. The amount for first quarter 2008 was from the $3.0 million scheduled periodic repayment of our previous term loans and $3.6 million net profits interest payments related to a 2007 property acquisition.

Long-term Loans

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

 

     March 31,
2009
   December 31,
2008

Term Loans and revolving credit facility - net of unamortized discount of $33,224 and $35,833, respectively

   $ 1,335,427    $ 1,366,630

Less current maturities

     10,500      10,500
             

Total long-term debt

   $ 1,324,927    $ 1,356,130
             

Our Term Loans contain certain financial covenants, the most restrictive of which include the following (Also see Note 7, “Long-Term Debt.”):

 

Covenant   

Requirement (4)

1.   

Minimum Current Ratio (1)

   Greater than 1.0 to 1.0
2.   

Ratio of Net Debt to EBITDAX (2)

   Less than 3.0 to 1.0
3.   

Ratio of EBITDAX to Interest Expense

   Greater than 2.5 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 long-term debt, 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.

The Term Loans also contain a condition to borrowing and a representation that no material adverse effect (“MAE”) has occurred, which includes (a) a material adverse effect on the business, assets, operations, condition (financial or otherwise) or prospects of the Company and its subsidiaries, taken as a whole, (b) a material impairment of the ability of the Company to perform its obligation under the Term Loans, or (c) a

 

24


Table of Contents

material impairment of the rights of or benefits available to the lenders under the Term Loans. If a 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.

Upon closing the transaction to form ATP-IP discussed above, we repaid $31.2 million of our Asset Sale Facility in accordance with our Term Loan agreement leaving a balance of $295.5 million at March 31, 2009. If we complete other Asset Sales, as defined by the Term Loans, we will continue to apply 75% of the Net Cash Proceeds as defined in our Term Loans of the Asset Sale toward the repayment of the Asset Sale Facility as long as there is a balance outstanding. Any Asset Sale Facility balance still outstanding is due in its entirety in January 2011.

We also have a $50.0 million revolving credit facility which has the same interest obligations as the Term Loans and has a final maturity of July 2013. Borrowings under the Revolver at March 31, 2009 were $31.0 million, and the balance of the borrowing capacity was reserved by $19.0 million of outstanding letters of credit secured by the facility.

As of March 31, 2009, we were in compliance with the covenants of the Term Loans and we believe we will remain in compliance with all financial covenants throughout 2009. Significant adverse changes in our expected production levels, commodity prices and reserves or material delays or cost overruns could have a material adverse affect on our financial condition and results of operations and 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.

Commitments and Contingencies

Management is periodically faced with uncertainties, the outcomes of which are not within its control and will not be known for a long time. We are involved in actions from time to time, which if determined adversely, could have a material negative impact on our financial position, results of operations and cash flows. Management, with the assistance of counsel makes estimates, if determinable, of ATP’s probable liabilities and records such amounts in the consolidated financial statements. Such estimates may be the minimum amount of a range of probable loss when no single best estimate is determinable. Disclosure is made, when determinable, of any additional possible amount of loss on these claims, or if such estimate cannot be made, that fact is disclosed. Along with our counsel, we monitor developments related to these legal matters and, when appropriate, we make adjustments to recorded liabilities to reflect current facts and circumstances. Although it is difficult to predict the ultimate outcome of these matters, management is not aware of any amounts that need to be recorded and believes that the recorded amounts, if any, are reasonable. See Note 11 to the consolidated financial statements for additional discussion of commitments and contingencies.

Accounting Pronouncements

See Note 2 to our Consolidated Financial Statements for a discussion of recently issued accounting pronouncements.

Critical Accounting Policies

Our discussion and analysis of our financial condition and results of operations are based on consolidated financial statements which have been prepared in accordance with generally accepted accounting principles in the United States. The preparation of these financial statements requires us to make estimates and judgments that affect the reported amounts or assets, liabilities, revenues and expenses. We believe that certain accounting policies affect our more significant judgments and estimates used in the preparation of our consolidated financial statements. Our 2008 Annual Report on Form 10-K includes a discussion of our critical accounting policies.

 

Item 3. Quantitative and Qualitative Disclosures about Market Risks

Interest Rate Risk

We are exposed to changes in interest rates on our Term Loans as 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 presentation of our Term Loans in Note 7 to the consolidated financial statements.

 

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Table of Contents

Foreign Currency Risk

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

Commodity Price Risk

Our revenues, profitability and future growth depend substantially on prevailing prices for oil and natural gas. Prices also affect the amount of cash flow available for capital expenditures and our ability to borrow and raise additional capital. Lower prices may also reduce the amount of oil and natural gas that we can economically produce. We currently sell a portion of our oil and natural gas production under market price contracts. We periodically use derivative instruments to hedge our commodity price risk. We hedge a portion of our projected oil and natural gas production through a variety of financial and physical arrangements intended to support oil and natural gas prices at targeted levels and to manage our exposure to price fluctuations. We may use futures contracts, swaps, put options, price collars and fixed-price physical forward contracts to hedge our commodity prices. See Note 10, “Derivative Instruments and 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 deemed necessary by the terms of our existing credit agreements. We do not initially hold or issue derivative instruments for speculative purposes.

 

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

Our chief executive officer and chief financial officer have reviewed and evaluated the effectiveness of our disclosure controls and procedures, as defined in Exchange Act Rules 13a-15(e) and 15d-15(e), as of March 31, 2009 (the “Evaluation Date”). Based on this evaluation, the chief executive officer and chief financial officer have concluded that ATP’s disclosure controls and procedures were effective as of the Evaluation Date to ensure that information that is required to be disclosed by ATP in the reports it files or submits under the Exchange Act is (i) recorded, processed, summarized and reported, within the time periods specified in the Securities and Exchange Commission’s rules and forms and (ii) accumulated and communicated to ATP’s management, including our chief executive officer and chief financial officer, as appropriate to allow timely decisions regarding required disclosure.

Changes in Internal Control Over Financial Reporting

During the three months ended March 31, 2009, we have made no change to our internal controls over financial reporting that has materially affected, or is reasonably likely to materially affect, our internal controls over financial reporting.

Forward-Looking Statements and Associated Risks

This Quarterly Report contains projections and other forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934. These projections and statements reflect the Company’s current views with respect to future events and financial performance. No assurances can be given, however, that these events will occur or that these projections will be achieved and actual results could differ materially from those projected as a result of certain factors. A discussion of these factors is included in the Company’s 2008 Annual Report on Form 10-K.

 

26


Table of Contents

PART II. OTHER INFORMATION

Items 1, 2, 3, 4 and 5 are not applicable and have been omitted.

 

Item 6. Exhibits

 

    3.1    Amended and Restated Articles of Incorporation, incorporated by reference to Exhibit 3.1 of Registration Statement No. 333-46034 on Form S-1 of ATP Oil & Gas Corporation (“ATP”).
    3.2    Amended and Restated Bylaws of ATP, incorporated by reference to Exhibit 3.1 of ATP’s Report on Form 10-Q for the quarter ended September 30, 2006.
    4.1    Warrant Shares Registration Rights Agreement dated as of March 29, 2004 between ATP and each of the Holders set forth on the execution pages thereof, incorporated by reference to Exhibit 4.5 of ATP’s Form 10-K for the year ended December 31, 2003.
    4.2    Warrant Agreement dated as of March 29, 2004 by and among ATP and the Holders from time to time of the warrants issued hereunder, incorporated by reference to Exhibit 4.6 of ATP’s Form 10-K for the year ended December 31, 2003.
    4.3    Rights Agreement dated October 11, 2005 between ATP and American Stock Transfer & Trust Company, as Rights Agent, specifying the terms of the Rights, which includes the form of Statement of Designations of Junior Participating Preferred Stock as Exhibit A, the form of Right Certificate as Exhibit B and the form of the Summary of Rights to Purchase Preferred Shares as Exhibit C, incorporated by reference to Exhibit 1 to the Company’s Registration Statement on Form 8-A filed with the Securities and Exchange Commission on October 14, 2005.
†10.1    ATP Oil & Gas Corporation 2000 Stock Plan, incorporated by reference to Exhibit 10.11 of ATP’s Form 10-K for the year ended December 31, 2000.
  10.2    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    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.
†10.4    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.
†10.5    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.
†10.6    Employment Agreement between ATP and Leland E. Tate, dated December 29, 2005, incorporated by reference to Exhibit 10.3 to ATP’s Form 8-K dated December 30, 2005.
†10.7    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.
†10.8    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.
†10.9    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.
†10.10    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.
†10.11    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.
†10.12    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.

 

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Table of Contents
†10.13    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.
†10.14    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.
†10.15    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.
†10.16    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.
†10.17    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.
*21.1    Subsidiaries of ATP.
*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

 

Management contract or compensatory plan or arrangement
* Filed herewith

 

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned and thereunto duly authorized.

 

      ATP Oil & Gas Corporation
Date:  

May 11, 2009

    By:  

/s/ Albert L. Reese Jr.

        Albert L. Reese Jr.
        Chief Financial Officer

 

29

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