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ATP Oil & Gas 10-Q 2005

Documents found in this filing:

  1. 10-Q
  2. Ex-31.1
  3. Ex-31.2
  4. Ex-32.1
  5. Ex-32.2
  6. Ex-32.2
For the quarterly period ended March 31, 2005
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, 2005

 

OR

 

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

 

Commission file number: 000-32261

 


 

ATP OIL & GAS CORPORATION

(Exact name of registrant as specified in its charter)

 


 

Texas   76-0362774

(State 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 is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act)    Yes  x    No  ¨

 

The number of shares outstanding of Registrant’s common stock, par value $0.001, as of May 6, 2005, was 28,975,890.

 



Table of Contents

ATP OIL & GAS CORPORATION

TABLE OF CONTENTS

 

         Page

PART I. FINANCIAL INFORMATION     

ITEM 1.

  FINANCIAL STATEMENTS (Unaudited)     
   

Consolidated Balance Sheets: March 31, 2005 and December 31, 2004

   3
   

Consolidated Statements of Operations: For the three months ended March 31, 2005 and 2004

   4
   

Consolidated Statements of Cash Flows: For the three months ended March 31, 2005 and 2004

   5
   

Consolidated Statements of Comprehensive Loss: For the three months ended March 31, 2005 and 2004

   6
   

Notes to Consolidated Financial Statements

   7

ITEM 2.

 

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

   14

ITEM 3.

 

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

   19

ITEM 4.

 

CONTROLS AND PROCEDURES

   19

PART II. OTHER INFORMATION

   20

 

2


Table of Contents

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(In Thousands, Except Share Amounts)

(Unaudited)

 

     March 31,
2005


    December 31,
2004


 
Assets                 

Current assets

                

Cash and cash equivalents

   $ 70,784     $ 102,774  

Accounts receivable (net of allowance of $1,499)

     44,175       36,991  

Derivative asset

     5       791  

Other current assets

     6,065       3,788  
    


 


Total current assets

     121,029       144,344  
    


 


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

                

Proved properties

     479,751       439,887  

Unproved properties

     11,104       10,516  
    


 


       490,855       450,403  

Less: Accumulated depletion, impairment and amortization

     (257,207 )     (237,197 )
    


 


Oil and gas properties, net

     233,648       213,206  
    


 


Furniture and fixtures (net of accumulated depreciation)

     808       741  

Other assets, net

     13,092       13,856  
    


 


Total assets

   $ 368,577     $ 372,147  
    


 


Liabilities and Shareholders’ Equity                 

Current liabilities

                

Accounts payable and accruals

   $ 65,313     $ 68,573  

Current maturities of long term debt

     2,200       2,200  

Asset retirement obligation

     5,170       4,925  

Derivative liability

     369       316  
    


 


Total current liabilities

     73,052       76,014  

Long-term debt

     208,086       208,109  

Asset retirement obligation

     19,893       19,998  

Deferred revenue

     695       741  

Other long-term liabilities and deferred obligations

     9,615       10,121  
    


 


Total liabilities

     311,341       314,983  
    


 


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; 29,042,230 issued and 28,966,390 outstanding at March 31, 2005; 28,959,701 issued and 28,883,861 outstanding at December 31, 2004

     29       29  

Additional paid in capital

     141,350       140,628  

Accumulated deficit

     (87,759 )     (88,759 )

Accumulated other comprehensive income

     4,527       6,177  

Treasury stock

     (911 )     (911 )
    


 


Total shareholders’ equity

     57,236       57,164  
    


 


Total liabilities and shareholders’ equity

   $ 368,577     $ 372,147  
    


 


 

See accompanying notes to consolidated financial statements.

 

3


Table of Contents

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(In Thousands, Except Per Share Amounts)

(Unaudited)

 

     Three Months Ended
March 31,


 
     2005

    2004

 

Revenues

                

Oil and gas production

   $ 36,980     $ 24,011  
    


 


Costs and operating expenses

                

Lease operating expenses

     4,574       4,498  

Geological and geophysical expenses

     334       85  

General and administrative expenses

     4,191       4,083  

Credit facility and related expenses

     —         1,851  

Depreciation, depletion and amortization

     20,502       11,583  

Asset retirement accretion expense

     580       491  

Gain on abandonment

     —         (256 )

Gain on disposition of properties

     —         (2,982 )
    


 


Total costs and operating expenses

     30,181       19,353  
    


 


Income from operations

     6,799       4,658  
    


 


Other income (expense)

                

Interest income

     490       24  

Interest expense

     (6,289 )     (3,749 )

Loss on debt extinguishment

     —         (3,326 )
    


 


Total other expense

     (5,799 )     (7,051 )
    


 


Income (loss) before income taxes

     1,000       (2,393 )

Income tax (expense) benefit

     —         —    
    


 


Net income (loss)

   $ 1,000     $ (2,393 )
    


 


Basic and diluted income (loss) per common share:

   $ 0.03     $ (0.10 )
    


 


Weighted average number of common shares:

                

Basic

     28,924       24,523  
    


 


Diluted

     29,782       24,523  
    


 


 

See accompanying notes to consolidated financial statements.

 

4


Table of Contents

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In Thousands)

(Unaudited)

 

     Three Months Ended
March 31,


 
     2005

    2004

 

Cash flows from operating activities

                

Net income (loss)

   $ 1,000     $ (2,393 )

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

                

Depreciation, depletion and amortization

     20,502       11,583  

Gain on disposition of properties

     —         (2,982 )

Accretion of asset retirement obligation

     580       491  

Amortization of deferred financing costs

     758       684  

Loss on extinguishment of debt

     —         3,326  

Ineffectiveness of cash flow hedges

     5       —    

Other non-cash items

     527       —    

Non-cash interest and credit facility expenses

     —         1,709  

Changes in assets and liabilities –

                

Accounts receivable and other assets

     (9,564 )     (16,479 )

Derivative liability

     —         (166 )

Accounts payable and accruals

     (3,082 )     (2,669 )

Other long-term assets

     —         —    

Other long-term liabilities and deferred obligations

     (10 )     (3,291 )
    


 


Net cash provided by (used in) operating activities

     10,716       (10,187 )
    


 


Cash flows from investing activities

                

Additions and acquisitions of oil and gas properties

     (42,315 )     (22,628 )

Proceeds from disposition of properties

     —         10,500  

Additions to furniture and fixtures

     (154 )     (109 )
    


 


Net cash used in investing activities

     (42,469 )     (12,237 )
    


 


Cash flows from financing activities

                

Proceeds from long-term debt

     —         227,000  

Payments of long-term debt

     (550 )     (164,668 )

Deferred financing costs

     —         (8,476 )

Repurchase of warrants

     —         (750 )

Exercise of stock options

     732       4  

Other

     (9 )     —    
    


 


Net cash provided by financing activities

     173       53,110  
    


 


Effect of exchange rate changes on cash

     (410 )     1,551  
    


 


Increase (decrease) in cash and cash equivalents

     (31,990 )     32,237  

Cash and cash equivalents, beginning of period

     102,774       4,564  
    


 


Cash and cash equivalents, end of period

   $ 70,784     $ 36,801  
    


 


Supplemental disclosures of cash flow information:

                

Cash paid during the period for interest

   $ 5,258     $ 5,783  
    


 


 

See accompanying notes to consolidated financial statements.

 

5


Table of Contents

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS

(In Thousands)

(Unaudited)

 

    

Three Months Ended

March 31,


 
     2005

    2004

 

Net income (loss)

   $ 1,000     $ (2,393 )
    


 


Other comprehensive income (loss):

                

Reclassification adjustment for settled contracts, net of tax

     (367 )     —    

Change in fair value of outstanding hedge positions

     (467 )     (775 )

Foreign currency translation adjustment

     (816 )     824  
    


 


Other comprehensive income (loss)

     (1,650 )     49  
    


 


Comprehensive loss

   $ (650 )   $ (2,344 )
    


 


 

See accompanying notes to consolidated financial statements.

 

6


Table of Contents

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

 

Note 1 — Organization

 

ATP Oil & Gas Corporation (“ATP”), a Texas corporation, was formed on August 8, 1991 and is engaged in the acquisition, development and production of oil and 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 gas properties with proved undeveloped reserves that are economically attractive to us but are not strategic to major or exploration-oriented independent oil and gas companies.

 

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 accruals) which are, in the opinion of management, necessary for a fair presentation of the results of operations for the interim periods. All intercompany transactions are eliminated upon consolidation. Certain reclassifications have been made to prior period amounts to conform to current period presentation. The interim financial information and notes hereto should be read in conjunction with our 2004 Annual Report on Form 10-K. The results of operations for the three months ended March 31, 2005 are not necessarily indicative of results to be expected for the entire year.

 

Note 2 — Recent Accounting Pronouncements

 

In November 2004, the Financial Accounting Standards Board (“FASB”) issued Revised Statement No. 123, “Accounting for Share-Based Payment” (“SFAS 123R”). This statement requires companies to measure and recognize compensation expense for all stock-based payments. In addition, companies will be required to calculate this compensation using the fair-value based method, versus the intrinsic value method previously allowed under SFAS No. 123, “Accounting for Stock-Based Compensation” (“SFAS 123”). As issued, this revision was effective for interim periods beginning after June 15, 2005. On April 14, 2005, the Securities and Exchange Commission (“SEC”) amended the compliance date for SFAS 123R to the beginning of the next fiscal year that begins after June 15, 2005. Accordingly, we will adopt this revised statement effective January 1, 2006. We are currently evaluating how we will adopt SFAS 123R and have not determined the method we will use to value stock based compensation.

 

In April 2005, the FASB issued Staff Position No. FAS 19-1, “Accounting for Suspended Well Costs” (“FSP 19-1”). FSP 19-1 amends SFAS No. 19, “Financial Accounting and Reporting by Oil and Gas Producing Companies”, (“SFAS 19”) to allow continued capitalization of exploratory well costs beyond one year from the date drilling was completed under circumstances where the well has found a sufficient quantity of reserves to justify its completion as a producing well and the enterprise is making sufficient progress assessing the reserves and the economic and operating viability of the project. FSP 19-1 also amends SFAS 19 to require enhanced disclosures of suspended exploratory well costs in the notes to the financial statements for annual and interim periods when there has been a significant change from the previous disclosure. The guidance in FSP 19-1 is effective for the first reporting period beginning after April 4, 2005. We will adopt the new requirements for the period ended June 30, 2005. The adoption of FAS 19-1 is not expected to have a material impact on our consolidated financial position or results of operations.

 

Note 3 — Asset Retirement Obligations

 

SFAS No. 143, “Accounting for Asset Retirement Obligations,” (“SFAS 143”) provides accounting requirements for retirement obligations associated with tangible long-lived assets, including: 1) the timing of liability recognition; 2) initial measurement of the liability; 3) allocation of asset retirement cost to expense; 4) subsequent measurement of the liability; and 5) financial statement disclosures. SFAS 143 requires that an asset retirement cost should be capitalized as part of the cost of the related long- lived asset and subsequently allocated to expense using a systematic and rational method.

 

The reconciliation of the beginning and ending asset retirement obligation for the period ending March 31, 2005 is as follows (in thousands):

 

Asset retirement obligation at December 31, 2004

   $ 24,923  

Liabilities incurred

     (258 )

Liabilities settled

     (58 )

Accretion expense

     580  

Foreign currency translation

     (124 )
    


Asset retirement obligation at March 31, 2005

   $ 25,063  
    


 

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Note 4 — Long-Term Debt

 

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

 

     March 31,
2005


   

December 31,

2004


 

Term loan, net of unamortized discount of $7,602 and $8,129

   $ 210,286     $ 210,309  

Less current maturities

     (2,200 )     (2,200 )
    


 


Total long-term debt

   $ 208,086     $ 208,109  
    


 


 

At March 31, 2005, we have a $185.0 million term loan of which $150.0 million is a Senior Secured First Lien Term Loan Facility and $35.0 million is a Senior Secured Second Lien Term Loan Facility (“Term Loan”). The Term Loan matures in March 2009. It is secured by substantially all of our oil and gas assets in the Gulf of Mexico and the U.K. Sector – North Sea and is guaranteed by our wholly owned subsidiaries ATP Energy and ATP Oil & Gas (U.K.) Limited.

 

The $150.0 million term loan bears interest at the base rate plus a margin of 6.25% or LIBOR (with a 2% floor) plus a margin of 5.25% at the election of ATP. The $35.0 million term loan bears interest at the base rate plus a margin of 9.0% or LIBOR (with a 2% floor) plus a margin of 10.0% at the election of ATP.

 

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

 

On September 24, 2004, the lender consented to the repurchase by the borrower of 1,926,837 of the 2,432,336 outstanding second lien facility warrants for a price not to exceed $11,561,022. The warrants were repurchased on September 24, 2004 for $6.00 per warrant which, in management’s estimation, represented the current fair value of the unregistered warrants as of that date. The $11.6 million partial repurchase was recorded as a decrease to additional paid in capital while the debt discount will continue to be amortized over the life of the loan.

 

The terms of the Term Loan, as amended September 24, 2004, require us to maintain certain covenants. Capitalized terms are defined in the credit agreement for the Term Loan. The covenants include:

 

    Current Ratio of 1.0/1.0;

 

    Consolidated Net Debt to EBITDAX coverage ratio which is not greater than 3.25/1.0 through June 30, 2004 and 3.0/1.0 at each of the quarters ending thereafter;

 

    Consolidated EBITDAX to Interest Expense which is not less than 2.5/1.0 for any four consecutive fiscal quarters commencing with the quarter ended June 30, 2004 and at each of the quarters ending thereafter;

 

    Pre-tax PV10 of our Total Proved Developed Producing Oil and Gas Reserves to Net Debt of at least 0.5/1.0 at June 30 and December 31 of any fiscal year;

 

    Pre-tax PV10 of our Total Proved Oil and Gas Reserves to Net Debt of at least 2.5/1.0 at June 30 and December 31 of any fiscal year;

 

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Table of Contents
    Net Debt to Proved Developed Oil and Gas Reserves of less than $2.50/Mcfe at December 31, 2004 and at each of the years ending thereafter, and

 

    the requirement to maintain hedges on no less than 40% of the next twelve months of forecasted production attributable to our proved producing reserves.

 

On April 14, 2005 (the “Restatement Date”), we entered into an agreement to amend the First Lien Credit Agreement dated as of March 29, 2004, as amended. The amended agreement also effected the termination of our Second Lien Credit Agreement dated as of March 29, 2004, as amended. Capitalized terms are defined in the Term Loans, as amended.

 

The First Lien Credit Agreement was amended to effect the following:

 

    increase the secured term loan facility under the First Lien Credit Agreement to $350.0 million;

 

    terminate the Second Lien Credit Agreement and eliminate the secured term loan facility under that agreement;

 

    decrease the interest rate margin on any base rate loan from 5.25% to 4.50%;

 

    decrease the interest rate margin on any LIBOR loan from 6.25% to 5.50%;

 

    increase the limit on Capital Lease Obligations and Synthetic Lease Obligations from $5.0 million to $50.0 million at any time;

 

    increase the limit on Unsecured Indebtedness from $5.0 million to $30.0 million at any time, and

 

    extend the maturity date to April 2010.

 

The amendments also adjusted several of the financial covenants. The adjustments:

 

    require us to maintain a Maximum Leverage Ratio of no more than 3.00 to 1.00 at the end of any fiscal quarter beginning April 14, 2005 through June 30, 2005, 3.50 to 1.00 from July 1, 2005 through December 31, 2005 and 3.00 to 1.00 thereafter;

 

    require us to maintain a Debt to Reserve Amount of no greater than $2.50 through maturity; provided, however, that if such amount is exceeded at the end of the fiscal year ending on December 31, 2005, any Default arising therefrom shall be waived and disregarded, and such amount shall be retested at June 30, 2006, and

 

    increase the amount of Permitted Business Investments from $25.0 million to $75.0 million in any fiscal year.

 

On April 14, 2005, we increased our aggregate borrowings under the Term Loans by $132.1 million (from the balance outstanding as of March 31, 2005) to an aggregate outstanding principal amount of $350.0 million. From this increase in borrowings, we received net proceeds of $117.8 million after deducting $3.6 million for accrued and unpaid interest on the Term Loans up to the Restatement Date and $10.7 million for fees and expenses.

 

As of March 31, 2005, we were in compliance with all of the financial covenants of our Term Loans. Significant adverse changes in our expected production levels, commodity prices and reserves or material delays or cost overruns could have a material adverse affect on our financial condition and results of operations and result in our non-compliance with these covenants. An event of non-compliance with any of the required covenants could result in a material mandatory repayment under the Term Loans.

 

Note 5 — Stock –Based Compensation

 

SFAS No. 123, “Accounting for Stock-Based Compensation” (“SFAS 123”), as amended by SFAS No. 148, “Accounting for Stock-Based Compensation – Transition and Disclosure,” (“SFAS 148”) outlines a fair value based method of accounting for stock options or similar equity instruments. We have continued using the intrinsic value based method, as allowed by Accounting Principles Board (“APB”) Opinion 25, to measure compensation cost for its stock option plans.

 

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Table of Contents

The following table illustrates the effect on net income (loss) and earnings per share if we had applied the fair value recognition provisions of SFAS 123 to stock-based employee compensation (in thousands):

 

    

Three Months Ended,

March 31,


 
     2005

   2004

 

Net income (loss) as reported

   $ 1,000    $ (2,393 )

Deduct: Total stock based employee compensation expense determined under fair value for all awards, net of related tax effects

     36      (80 )
    

  


Pro forma net income (loss)

   $ 1,036    $ (2,473 )
    

  


Earnings per share – as reported:

               

Basic

   $ 0.03    $ (0.10 )

Diluted

   $ 0.03    $ (0.10 )

Earnings per share – pro forma:

               

Basic

   $ 0.04    $ (0.10 )

Diluted

   $ 0.03    $ (0.10 )

 

Note 6 — Earnings Per Share

 

Basic earnings per share is computed by dividing net income (loss) available to common shareholders by the weighted average number of common shares outstanding during the period. Diluted earnings per share is determined on the assumption that outstanding stock options have been converted using the average price for the period. For purposes of computing earnings per share in a loss year, potential common shares have been excluded from the computation of weighted average common shares outstanding because their effect is antidilutive.

 

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

 

     Three Months Ended
March 31,


 
     2005

   2004

 

Net income (loss) available to common shareholders

   $ 1,000    $ (2,393 )
    

  


Weighted average shares outstanding - basic

     28,924      24,523  

Effect of dilutive securities - stock options

     512      —    

Effect of dilutive securities - warrants

     346      —    
    

  


Weighted average shares outstanding - diluted

     29,782      24,523  
    

  


Net income (loss) per share, basic and diluted

   $ 0.03    $ (0.10 )
    

  


 

Note 7 — Derivative Instruments and Price Risk Management Activities

 

Derivative financial instruments, utilized to manage or reduce commodity price risk related to our production are accounted for under the provisions of SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (“SFAS 133”) and related interpretations. Under this standard, all derivatives are carried on the balance sheet at fair value. If the derivative is designated as a fair value hedge, the changes in the fair value of the derivative and of the hedged item attributable to the hedged risk are recognized in earnings. If the derivative is designated as a cash flow hedge, the effective portions of changes in the fair value

 

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

 

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

 

At March 31, 2005, Accumulated Other Comprehensive Income included $0.3 million of unrealized losses on our cash flow hedges. Gains and losses are reclassified from Accumulated Other Comprehensive Income to the consolidated statement of operations as a component of oil and gas revenues in the period the hedged production occurs. If any ineffectiveness occurs, amounts are recorded directly to the consolidated statement of operations as a component of oil and gas revenues. All of this deferred loss will be reversed during the period in which the forecasted transactions actually occur.

 

At March 31, 2005, we had three natural gas derivatives that qualified as cash flow hedges with respect to our future natural gas production as follows:

 

Area


   Period

   Type

   Volumes

   Average
Price


   Floor
Price


   Net Fair Value
Asset (Liability)


 
               (MMBtu)    ($ per MMBtu)    ($ in thousands)  

Gulf of Mexico

   2005    Swap    150,000    5.62    —      (254 )

Gulf of Mexico

   2005    Put    856,000    —      5.01    5  

North Sea

   2006    Swap    1,800,000    10.52    —      (115 )

(1) During the first quarter of 2005, we entered into a cash flow hedge of our U.K. production at a price of £0.56 per therm. The price and net fair value liability have been translated at the March 31, 2005 translation rate of $1.879 to £1.0.

 

We also manage our exposure to oil and gas price risks by periodically entering into fixed-price delivery contracts. These physical contracts qualified and have been designated for the normal purchase and sale exemption under SFAS 133, as amended. This exemption permits, at our option, the use of the accrual basis of accounting as opposed to fair value accounting for the contracts. At March 31, 2005, we had fixed-price contracts in place for the following natural gas and oil volumes:

 

Period


   Volumes

   Average
Fixed
Price (1)


Natural gas (MMBtu):

           

2005

   6,817,000    $ 6.34

2006

   1,710,000      7.40

Oil (Bbl):

           

2005

   320,750      42.02

2006

   300,500      47.96

(1) Includes the effect of basis differentials.

 

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Note 8 — Commitments and Contingencies

 

Contingencies

 

In December 2004, our Board of Directors approved and we announced ambitious company targets coupled with a unique incentive program applicable to our employees. If the company targets are met, under the ATP Employee Volvo Challenge Plan (the “Plan”), we will award each employee other than our president, a 2006 Volvo S60. Following the end of each fiscal quarter, we will evaluate our performance with respect to the stated targets and accrue the earned future cost of any expected benefits pursuant to the Plan.

 

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

 

In February 2003, we acquired a 50% working interest in a block located in the Dutch Sector - North Sea. The remaining 50% interest is owned by a Dutch company who participates on behalf of the Dutch state. In April 2003, we received €7.4 million from the partner related to development costs on this block. We agreed to develop the property within 60 months from receipt of the funds or return the funds with interest if commercial production is not achieved at the expiration of such time. At March 31, 2005 and December 31, 2004, the U.S recorded balance is reflected as a long-term liability of $9.6 million and $10.2 million, respectively, in the financial statements.

 

At the time of receipt, we determined the payment was not taxable at that time due to the substantial obligation to perform in the future. During a recent tax audit of our Netherlands subsidiary, the tax authorities suggested that receipt of the payment may have been a taxable event at the time of receipt and taxes may be currently due on this payment. We do not agree with the position that has been suggested and, if necessary, we will defend our position vigorously.

 

Litigation

 

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

 

Note 9 — Segment Information

 

We follow SFAS No. 131, “Disclosures About Segments of an Enterprise and Related Information,” which requires that companies disclose segment data based on how management makes decisions about allocating resources to segments and measuring their performance. We manage our business and identify our segments based on geographic areas. We have two reportable segments: our operations in the Gulf of Mexico and our operations in the North Sea. Both of these segments involve oil and gas producing activities. Segment activity for the three months ended March 31, 2005 and 2004 is as follows (in thousands):

 

     Gulf of
Mexico


   North Sea

    Total

For the three months ended March 31, 2005:

                     

Revenues

   $ 32,670    $ 4,310     $ 36,980

Depreciation, depletion and amortization

     18,324      2,178       20,502

Income from operations

     6,450      349       6,799

Total assets

     296,750      71,827       368,577

Additions to oil and gas properties

     27,091      15,224       42,315

For the three months ended March 31, 2004:

                     

Revenues

   $ 20,812    $ 3,199     $ 24,011

Depreciation, depletion and amortization

     9,127      2,456       11,583

Income (loss) from operations

     5,595      (937 )     4,658

Total assets

     215,498      61,586       277,084

Additions to oil and gas properties

     17,867      4,761       22,628

 

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

 

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

 

    significant undeveloped reserves;

 

    close proximity to developed markets for oil and gas;

 

    existing infrastructure of oil and gas pipelines and production / processing platforms, and

 

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

 

Source of Revenue

 

We derive our revenues from the sale of oil and gas that is produced from our oil and gas properties. Revenues are a function of the volume produced and the prevailing market price at the time of sale. The price of oil and natural gas is the primary factor affecting our revenues. To achieve more predictable cash flows and to reduce our exposure to downward price fluctuations, we utilize derivative instruments to hedge future sales prices on a significant portion of our oil and natural gas production. The use of certain types of derivative instruments may prevent us from realizing the full benefit of upward price movements.

 

First Quarter 2005 Highlights

 

Our financial and operating performance for the first quarter of 2005 included the following highlights:

 

    production of 5.8 Bcfe, an increase of 24% over the comparable period in 2004;

 

    revenues of $37.0 million, an increase of 54% over the comparable period in 2004;

 

    a net profit of $1.0 million compared to a $2.4 million net loss in the first quarter of 2004;

 

    a $21.0 million improvement in cash flows from operating activities, and

 

    continued development operations in the Gulf of Mexico and North Sea, including initial production from the West Cameron 432 No. 1 well and the Eugene Island 71 A1 well.

 

A more complete overview and discussion of full year expectations can be found in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our 2004 Annual Report on Form 10-K.

 

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Table of Contents

Results of Operations

 

Three Months Ended March 31, 2005 Compared to Three Months Ended March 31, 2004

 

For the three months ended March 31, 2005, we reported net income of $1.0 million, or $0.03 per share on total revenue of $37.0 million as compared with a net loss of $2.4 million, or $0.10 per share, on total revenue of $24.0 million for the three months ended March 31, 2004.

 

Oil and Gas Revenues

 

Revenues presented in the table and the discussion below represent revenue from sales of our oil and natural gas production volumes. Production sold under fixed price delivery contracts, which have been designated for the normal purchase and sale exemption under SFAS 133, are also included in these amounts. Approximately 59% and 31% of our oil production was sold under these contracts for the three months ended March 31, 2005 and 2004, respectively. Approximately 43% and 53% of our natural gas production was sold under these contracts for the comparable periods. The realized prices below may differ from the market prices in effect during the periods depending on when the fixed price delivery contract was executed.

 

     Three Months Ended
March 31,


  

% Change
from 2004

to 2005


 
     2005

   2004

  

Production:

                    

Natural gas (MMcf)

     4,594      3,617    27 %

Oil and condensate (MBbls)

     198      172    15 %

Total (MMcfe)

     5,779      4,646    24 %

Revenues (in thousands):

                    

Natural gas

   $ 28,637    $ 18,442    55 %

Effects of cash flow hedges

     412      48    758 %
    

  

      

Total

   $ 29,049    $ 18,490    57 %
    

  

      

Oil and condensate

   $ 7,930    $ 5,339    49 %

Effects of cash flow hedges

     —        —      —    
    

  

      

Total

   $ 7,930    $ 5,339    49 %
    

  

      

Natural gas, oil and condensate

   $ 36,567    $ 23,781    54 %

Effects of cash flow hedges

     412      48    758 %
    

  

      

Total

   $ 36,979    $ 23,829    55 %
    

  

      

Average sales price per unit:

                    

Natural gas (per Mcf)

   $ 6.23    $ 5.10    22 %

Effects of cash flow hedges (per Mcf)

     0.09      0.01    592 %
    

  

      

Total (per Mcf)

   $ 6.32    $ 5.11    24 %
    

  

      

Oil and condensate (per Bbl)

   $ 40.15    $ 31.13    29 %

Effects of cash flow hedges (per Bbl)

     —        —      —    
    

  

      

Total (per Bbl)

   $ 40.15    $ 31.13    29 %
    

  

      

Natural gas, oil and condensate (per Mcfe)

   $ 6.33    $ 5.12    24 %

Effects of cash flow hedges (per Mcfe)

     0.07      0.01    590 %
    

  

      

Total (per Mcfe)

   $ 6.40    $ 5.13    25 %
    

  

      

 

Oil and gas revenue increased 54% in the first quarter of 2005 compared to the same period in 2004 as the result of ten properties brought on line subsequent to the first quarter of 2004. Another component of the increase was a 24% increase in our sales price per Mcfe in 2005 as compared to 2004.

 

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Table of Contents

Lease Operating Expense. Lease operating expenses for the first quarter of 2005 decreased to $4.6 million ($0.79 per Mcfe) from $4.5 million ($0.97 per Mcfe) in the first quarter of 2004. The decrease per Mcfe was primarily attributable to the aforementioned increase in production while certain costs remained fixed.

 

General and Administrative Expense. General and administrative expense increased $0.1 million to $4.2 million from the first quarter of 2004. An increase in compensation costs in 2005 was offset by a decrease in professional fees from the first quarter of 2004.

 

Credit Facility and Related Expenses. In the first quarter of 2004, we incurred substantial non-recurring costs of $1.9 million to maintain compliance with the requirements of our previous lender. These costs primarily consisted of legal fees of $0.8 million and professional fees of $0.8 million.

 

Depreciation, Depletion and Amortization Expense. Depreciation, depletion and amortization expense increased $8.9 million (77%) during the first quarter of 2005 to $20.5 million from $11.6 million for the same period in 2004. The average DD&A rate was $3.55 per Mcfe in the first quarter of 2005 compared to $2.49 per Mcfe in the same quarter of 2004.

 

Loss on Extinguishment of Debt. In the first quarter of 2004, we recognized a non-cash loss of $3.3 million on the extinguishment of debt related to our prior credit facility agreement

 

Gain on Disposition of Properties. In the first quarter of 2004, we recognized a gain of $3.0 million on the sale of interests in certain GOM properties.

 

Income Taxes. In the first quarter of 2005, we recorded income tax expense of $1.6 million which was completely offset by a reduction in the valuation allowance recorded against our deferred tax assets. Tax expense relative to net income has increased compared to the first quarter of 2004 due to the effect of foreign operations on our U.S. taxes and certain changes in previous estimates made during the current period. The balance of the valuation allowance will remain until management determines that the recognition criteria for realization has been met.

 

Liquidity and Capital Resources

 

At March 31, 2005, we had working capital of approximately $48.0 million, a decrease of approximately $20.3 million from December 31, 2004.

 

We have financed our acquisition and development activities through a combination of bank borrowings and proceeds from our equity offerings, as well as cash from operations and the sale on a promoted basis of interests in selected properties. We intend to finance our near-term development projects in the Gulf of Mexico and North Sea through available cash flows, remaining proceeds from our new term loan and the potential sell down of a portion of our interests in the development projects. As operator of all of our projects in development, we have the ability to significantly control the timing of most of our capital expenditures. We believe the cash flows from operating activities combined with our ability to control the timing of substantially all of our future development and acquisition requirements will provide us with the flexibility and liquidity to meet our future planned capital requirements.

 

Cash Flows

 

     Three Months Ended,
March 31,


 
     2005

    2004

 
     (in thousands)  

Cash provided by (used in)

                

Operating activities

   $ 10,716     $ (10,187 )

Investing activities

     (42,469 )     (12,237 )

Financing activities

     173       53,110  

 

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Cash provided operating activities in the first quarter of 2005 was $10.7 million and cash used operations in the first quarter of 2004 was $10.2 million, respectively. Cash flow from operations increased primarily due to higher oil and gas revenues during the first quarter of 2005 compared to the first quarter of 2004. Gas sales increased by $10.2 million, or 55%, and oil sales increased by $2.6 million, or 49%. The increase in sales revenue was attributable to higher gas production and higher average oil and gas prices during the first quarter of 2005.

 

Cash used in investing activities in the first quarter of 2005 and 2004 was $42.5 million and $12.2 million, respectively. Developmental capital expenditures in the Gulf of Mexico and North Sea were approximately $27.1 million and $15.2 million in first quarter of 2005. Developmental capital expenditures in the Gulf of Mexico and North Sea were approximately $17.9 million and $4.7 million in first quarter of 2004, offset by the receipt of $10.5 million in proceeds for the sale of certain interests in seven of our properties.

 

Cash provided by financing activities in the first quarter of 2005 consisted of payments on our Term Loan of $0.6 million and proceeds from the exercise of options of $0.7 million. Cash provided by financing activities in the first quarter of 2004 consisted of net payments of $117.1 million related to our prior credit facility and net proceeds of $179.5 million related to our new term loan and warrants issued. We also incurred deferred financing costs of approximately $8.5 million related to the new term loan.

 

Term Loan

 

At March 31, 2005, we have a $185.0 million term loan of which $150.0 million is a Senior Secured First Lien Term Loan Facility and $35.0 million is a Senior Secured Second Lien Term Loan Facility (“Term Loan”). The Term Loan matures in March 2009. It is secured by substantially all of our oil and gas assets in the Gulf of Mexico and the U.K. Sector – North Sea and is guaranteed by our wholly owned subsidiaries ATP Energy and ATP Oil & Gas (U.K.) Limited.

 

The $150.0 million term loan bears interest at the base rate plus a margin of 6.25% or LIBOR (with a 2% floor) plus a margin of 5.25% at the election of ATP. The $35.0 million term loan bears interest at the base rate plus a margin of 9.0% or LIBOR (with a 2% floor) plus a margin of 10.0% at the election of ATP.

 

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

 

On September 24, 2004, the lender consented to the repurchase by the borrower of 1,926,837 of the 2,432,336 outstanding second lien facility warrants for a price not to exceed $11,561,022. The warrants were repurchased on September 24, 2004 for $6.00 per warrant which, in management’s estimation, represented the current fair value of the unregistered warrants as of that date. The $11.6 million partial repurchase was recorded as a decrease to additional paid in capital while the debt discount will continue to be amortized over the life of the loan.

 

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Table of Contents

The terms of the Term Loan, as amended September 24, 2004, require us to maintain certain covenants. Capitalized terms are defined in the credit agreement for the Term Loan. The covenants include:

 

    Current Ratio of 1.0/1.0;

 

    Consolidated Net Debt to EBITDAX coverage ratio which is not greater than 3.25/1.0 through June 30, 2004 and 3.0/1.0 at each of the quarters ending thereafter;

 

    Consolidated EBITDAX to Interest Expense which is not less than 2.5/1.0 for any four consecutive fiscal quarters commencing with the quarter ended June 30, 2004 and at each of the quarters ending thereafter;

 

    Pre-tax PV10 of our Total Proved Developed Producing Oil and Gas Reserves to Net Debt of at least 0.5/1.0 at June 30 and December 31 of any fiscal year;

 

    Pre-tax PV10 of our Total Proved Oil and Gas Reserves to Net Debt of at least 2.5/1.0 at June 30 and December 31 of any fiscal year;

 

    Net Debt to Proved Developed Oil and Gas Reserves of less than $2.50/Mcfe at December 31, 2004 and at each of the years ending thereafter, and

 

    the requirement to maintain hedges on no less than 40% of the next twelve months of forecasted production attributable to our proved producing reserves.

 

On April 14, 2005 (the “Restatement Date”), we entered into an agreement to amend the First Lien Credit Agreement dated as of March 29, 2004, as amended. The amended agreement also effected the termination of our Second Lien Credit Agreement dated as of March 29, 2004, as amended. Capitalized terms are defined in the Term Loans, as amended.

 

The First Lien Credit Agreement was amended to effect the following:

 

    increase the secured term loan facility under the First Lien Credit Agreement to $350.0 million;

 

    terminate the Second Lien Credit Agreement and eliminate the secured term loan facility under that agreement;

 

    decrease the interest rate margin on any base rate loan from 5.25% to 4.50%;

 

    decrease the interest rate margin on any LIBOR loan from 6.25% to 5.50%;

 

    increase the limit on Capital Lease Obligations and Synthetic Lease Obligations from $5.0 million to $50.0 million at any time;

 

    increase the limit on Unsecured Indebtedness from $5.0 million to $30.0 million at any time, and

 

    extend the maturity date to April 2010.

 

The amendments also adjusted several of the financial covenants. The adjustments:

 

    require us to maintain a Maximum Leverage Ratio of no more than 3.00 to 1.00 at the end of any fiscal quarter beginning April 14, 2005 through June 30, 2005, 3.50 to 1.00 from July 1, 2005 through December 31, 2005 and 3.00 to 1.00 thereafter;

 

    require us to maintain a Debt to Reserve Amount of no greater than $2.50 through maturity; provided, however, that if such amount is exceeded at the end of the fiscal year ending on December 31, 2005, any Default arising therefrom shall be waived and disregarded, and such amount shall be retested at June 30, 2006, and

 

    increase the amount of Permitted Business Investments from $25.0 million to $75.0 million in any fiscal year.

 

On April 14, 2005, we increased our aggregate borrowings under the Term Loans by $132.1 million (from the balance outstanding as of March 31, 2005) to an aggregate outstanding principal amount of $350.0 million. From this increase in borrowings, we received net proceeds of $117.8 million after deducting $3.6 million for accrued and unpaid interest on the Term Loans up to the Restatement Date and $10.7 million for fees and expenses.

 

17


Table of Contents

As of March 31, 2005, we were in compliance with all of the financial covenants of our Term Loans. Significant adverse changes in our expected production levels, commodity prices and reserves or material delays or cost overruns could have a material adverse affect on our financial condition and results of operations and result in our non-compliance with these covenants. An event of non-compliance with any of the required covenants could result in a material mandatory repayment under the Term Loans.

 

Commitments and Contingencies

 

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 Note 8 to the Consolidated Financial Statements, we are involved in actions from time to time, which if determined adversely, could have a material negative impact on our financial position, results of operations and cash flows. Management, with the assistance of counsel makes estimates, if determinable, of ATP’s probable liabilities and records such amounts in the consolidated financial statements. Such estimates may be the minimum amount of a range of probable loss when no single best estimate is determinable. Disclosure is made, when determinable, of any additional possible amount of loss on these claims, or if such estimate cannot be made, that fact is disclosed. Along with our counsel, we monitor developments related to these legal matters and, when appropriate, we make adjustments to recorded liabilities to reflect current facts and circumstances. Although it is difficult to predict the ultimate outcome of these matters, management believes that the recorded amounts, if any, are reasonable.

 

Contractual Obligations

 

We have various commitments primarily related to leases for office space, other property and equipment and other agreements. The following table summarizes certain contractual obligations at March 31, 2005 (in thousands):

 

     Payments Due By Period

Contractual Obligation


   Total

  

Less Than

1 Year


   1-3 Years

   4-5 Years

   After
5 Years


Long-term debt

   $ 217,888    $ 2,200    $ 215,688    $ —      $ —  

Interest on long-term debt (1)

     49,192      19,849      29,343      —        —  

Non-cancelable operating leases

     3,957      635      1,802      631      889
    

  

  

  

  

Total contractual obligations

   $ 271,037    $ 22,684    $ 246,833    $ 631    $ 889
    

  

  

  

  


(1) Interest is based on rates and quarterly principal payments in effect at March 31, 2005.

 

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 2004 Annual Report on Form 10-K includes a discussion of our critical accounting policies.

 

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Table of Contents

Item 3. Quantitative and Qualitative Disclosures about Market Risks

 

Interest Rate Risk

 

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

 

Foreign Currency Risk.

 

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

 

Commodity Price Risk

 

Our revenues, profitability and future growth depend substantially on prevailing prices for oil and 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 gas that we can economically produce. We currently sell a portion of our oil and gas production under price sensitive or market price contracts. We periodically use derivative instruments to hedge our commodity price risk. We hedge a portion of our projected oil and gas production through a variety of financial and physical arrangements intended to support oil and gas prices at targeted levels and to manage our exposure to price fluctuations. We may use futures contracts, swaps and fixed price physical contracts to hedge our commodity prices. Realized gains and losses from our price risk management activities are recognized in oil and gas sales when the associated production occurs. For derivatives designated as cash flow hedges, the unrecognized gains and losses are included as a component of other comprehensive income (loss) to the extent the hedge is effective. See Note 7 to the Consolidated Financial Statements for additional information. We do not hold or issue derivative instruments for speculative purposes.

 

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

 

Item 4. Controls and Procedures

 

Our principal executive officer and principal financial officer performed an evaluation of our disclosure controls and procedures, which have been designed to permit us to effectively identify and timely disclose important information. They concluded that the controls and procedures were effective as of March 31, 2005, to ensure that material information was accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding required disclosure. During the three months ended March 31, 2005, 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.

 

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Table of Contents

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 2004 Form 10-K.

 

PART II. OTHER INFORMATION

 

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

 

Item 6 – Exhibits and Reports on Form 8-K

 

  A. Exhibits

 

  31.1 Certification of Chief Executive Officer pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934, filed under Exhibit 31 of Item 601 of Regulation S-K.

 

  31.2 Certification of Chief Financial Officer pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934, filed under Exhibit 31 of Item 601 of Regulation S-K.

 

  32.1 Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, furnished under Exhibit 32 of Item 601 of Regulation S-K.

 

  32.2 Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, furnished under Exhibit 32 of Item 601 of Regulation S-K.

 

  B. Reports on Form 8-K

 

Current Report on Form 8-K filed on April 20, 2005, pursuant to Item 1.01 announcing the amendment to the Company’s term loan.

 

Current Report on Form 8-K filed on March 18, 2005, pursuant to Item 2.02, announcing the Company’s earnings results for the fourth quarter of 2004.

 

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Table of Contents

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 10, 2005

 

By:

 

/s/ Albert L. Reese, Jr.


       

Albert L. Reese, Jr.

       

Chief Financial Officer

 

21

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