ATP OIL & GAS CORP - 10-Q Quarterly Report

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-Q

þ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE

SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2002

¨ 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

(State or other jurisdiction of

incorporation or organization)

76-0362774

(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 þ No ¨

The number of shares outstanding of Registrant’s common stock, par value $0.001, as of November 13, 2002, was 20,316,267.

ATP OIL & GAS CORPORATION

TABLE OF CONTENTS

		Page
PART I.	FINANCIAL INFORMATION

ITEM 1.	FINANCIAL STATEMENTS

	Consolidated Balance Sheets: September 30, 2002 (unaudited) and December 31, 2001	3

	Consolidated Statements of Operations: For the three and nine months ended September 30, 2002 and 2001 (unaudited)	4

	Consolidated Statements of Cash Flows: For the nine months ended September 30, 2002 and 2001 (unaudited)	5

	Notes to Consolidated Financial Statements (unaudited)	6

ITEM 2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	12

ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	19

ITEM 4.	CONTROLS AND PROCEDURES	20

PART II.	OTHER INFORMATION	21

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(In Thousands, Except Share Amounts)

	September 30, 2002			December 31, 2001
	(unaudited)
Assets
Current assets
Cash and cash equivalents	$	5,494		$	5,294
Restricted cash		1,609			–
Accounts receivable (net of allowance of $1,430 and $1,423, respectively)		26,057			10,371
Derivative asset		–			1,936
Deferred tax asset		993			–
Other current assets		3,930			1,754

Total current assets		38,083			19,355

Oil and gas properties
Oil and gas properties (using the successful efforts method of accounting)		337,759			319,506
Less: Accumulated depreciation, depletion, impairment and amortization		(221,424	)		(186,473	)

Oil and gas properties, net		116,335			133,033

Furniture and fixtures (net of accumulated depreciation)		847			794
Deferred tax asset		20,089			19,228
Other assets, net		5,240			5,154

Total assets	$	180,594		$	177,564


Liabilities and Shareholders’ Equity
Current liabilities
Accounts payable and accruals	$	25,505		$	26,426
Current maturities of long-term debt		4,000			22,000
Derivative liability		8,048			–

Total current liabilities		37,553			48,426

Long-term debt		84,314			78,111
Derivative liability		541			671
Deferred revenue		1,158			1,296
Other long-term liabilities and deferred obligations		14,499			4,068

Total liabilities		138,065			132,572

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; 20,392,107 issued and 20,316,267 outstanding at September 30, 2002; 20,388,488 issued and 20,312,648 outstanding at December 31, 2001		20			20
Additional paid in capital		80,936			80,478
Accumulated deficit		(36,141	)		(34,614	)
Accumulated other comprehensive income (loss)		(1,375	)		19
Treasury stock		(911	)		(911	)

Total shareholders’ equity		42,529			44,992

Total liabilities and shareholders’ equity	$	180,594		$	177,564

See accompanying notes to consolidated financial statements.

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(In Thousands, Except Per Share Amounts)

(Unaudited)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2002			2001			2002			2001
Revenue:
Oil and gas production	$	23,159		$	19,571		$	69,511		$	87,081
Gas sold—marketing		1,509			1,312			4,258			6,280

Total revenues		24,668			20,883			73,769			93,361


Costs and operating expenses:
Lease operating expenses		4,908			2,454			12,265			9,707
Gas purchased—marketing		1,461			1,260			4,121			6,127
Geological and geophysical expenses		141			764			152			1,236
General and administrative expenses		2,614			2,663			7,648			6,713
Non-cash compensation expense (general and administrative)		(34	)		464			453			2,930
Depreciation, depletion and amortization		10,356			13,399			35,246			38,503
Impairment on oil and gas properties		–			3,655			–			17,838

Total costs and operating expenses		19,446			24,659			59,885			83,054

Income (loss) from operations		5,222			(3,776	)		13,884			10,307


Other income (expense):
Interest income		12			60			38			853
Interest expense		(2,673	)		(2,109	)		(7,953	)		(7,130	)
Loss on derivative instruments		–			(3,334	)		(8,319	)		(17,496	)

Total other income (expense)		(2,661	)		(5,383	)		(16,234	)		(23,773	)

Income (loss) before income taxes and extraordinary item		2,561			(9,159	)		(2,350	)		(13,466	)
Income tax (expense) benefit:
Current		(37	)		–			(37	)		–
Deferred		(859	)		2,660			860			3,907

Income (loss) before extraordinary item		1,665			(6,499	)		(1,527	)		(9,559	)
Extraordinary item, net of tax		–			–			–			(602	)

Net income (loss)	$	1,665		$	(6,499	)	$	(1,527	)	$	(10,161	)


Basic and diluted earnings (loss) per common share:
Income (loss) before extraordinary item	$	0.08		$	(0.32	)	$	(0.08	)	$	(0.49	)
Extraordinary item, net of tax		–			–			–			(0.03	)

Net income (loss) per common share	$	0.08		$	(0.32	)	$	(0.08	)	$	(0.52	)

Weighted average number of common shares:
Basic		20,316			20,297			20,315			19,499

Diluted		20,432			20,297			20,315			19,499

See accompanying notes to consolidated financial statements.

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In Thousands)

(Unaudited)

	Nine Months Ended September 30,
	2002			2001
Cash flows from operating activities
Net loss	$	(1,527	)	$	(10,161	)
Adjustments to reconcile net loss to net cash provided by operating activities –
Depreciation, depletion and amortization		35,246			38,503
Impairment of oil and gas properties		–			17,838
Amortization of deferred financing costs		1,110			494
Other comprehensive income		(1,845	)		(1,280	)
Extraordinary item		–			926
Deferred taxes		(861	)		(4,298	)
Non-cash compensation expense		453			2,930
Other non-cash items		454			220
Changes in assets and liabilities –
Accounts receivable and other		(16,403	)		15,459
Restricted cash		(1,609	)		–
Net (assets) liabilities from derivatives		8,861			(10,121	)
Accounts payable and accruals		(921	)		15,045
Other long-term assets		(2,570	)		(3,523	)
Other long-term liabilities and deferred credits		10,293			53

Net cash provided by operating activities		30,681			62,085


Cash flows from investing activities
Additions and acquisitions of oil and gas properties		(17,744	)		(108,378	)
Additions to furniture and fixtures		(250	)		(480	)

Net cash used in investing activities		(17,994	)		(108,858	)


Cash flows from financing activities
Proceeds from initial public offering		–			78,330
Payment of offering costs		–			(893	)
Proceeds from long-term debt		1,000			95,000
Payments of long-term debt		(13,000	)		(42,750	)
Proceeds from non-recourse borrowings		–			3,359
Payments of non-recourse borrowings		–			(92,138	)
Deferred financing costs		(492	)		(2,042	)
Treasury stock purchases		–			(911	)
Other		5			193

Net cash provided by (used in) financing activities		(12,487	)		38,148

Increase (decrease) in cash and cash equivalents		200			(8,625	)
Cash and cash equivalents, beginning of period		5,294			18,136

Cash and cash equivalents, end of period	$	5,494		$	9,511


Supplemental disclosures of cash flow information:
Cash paid during the period for interest	$	5,666		$	2,054

Cash paid during the period for taxes	$	–		$	–

See accompanying notes to consolidated financial statements.

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Note 1 — Organization

The accompanying financial statements and related notes present our consolidated financial position as of September 30, 2002 and December 31, 2001, the results of our operations for the three and nine months ended September 30, 2002 and 2001 and cash flows for the nine months ended September 30, 2002 and 2001. The financial statements have been prepared in accordance with the instructions to interim reporting as prescribed by the Securities and Exchange Commission (“SEC”). All adjustments, consisting only of normal recurring adjustments, that in the opinion of management were necessary for a fair statement of the results for the interim periods, have been reflected. All significant intercompany transactions have been eliminated. Certain reclassifications have been made to prior period amounts to conform to current period presentation. The results of operations for the three and nine months ended September 30, 2002 should not be taken as indicative of the results to be expected for the full year. The interim financial statements should be read in conjunction with our consolidated financial statements and notes thereto presented in our 2001 Annual Report on Form 10-K.

Note 2 — Accounting Pronouncements

In June 2001, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards (“SFAS”) No. 143 “Accounting for Asset Retirement Obligations” (“SFAS 143”). 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 statement is effective for fiscal years beginning after June 15, 2002 and we will adopt the statement for our fiscal year beginning January 1, 2003. The transition adjustment resulting from the adoption of SFAS 143 will be reported as a cumulative effect of a change in accounting principle. We are currently assessing the impact of SFAS 143 and therefore, at this time, cannot reasonably estimate the effect of this statement on our consolidated financial position or results of operations.

In April 2002, the FASB issued SFAS No. 145, “Rescission of FASB Statement Nos. 4, 44 and 64, Amendment of FASB Statement No. 13, and Technical Corrections” (“SFAS 145”). SFAS 145 requires that gains and losses from extinguishment of debt be classified as extraordinary items only if they meet the criteria in Accounting Principles Board Opinion No. 30 (“Opinion No. 30”). Applying the provisions of Opinion No. 30 will distinguish transactions that are part of an entity’s recurring operations from those that are unusual and infrequent that meet the criteria for classification as an extraordinary item. The statement is effective for fiscal years beginning after May 15, 2002 and we will adopt the provisions of SFAS 145 for our fiscal year beginning January 1, 2003. The adoption of the provisions of SFAS 145 is not expected to affect our future financial position or liquidity. On or before January 1, 2003, gains or losses from the early extinguishment of debt recognized in our consolidated statements of operations for prior years will be reclassified to other revenues or other expense and included in the determination of the income (loss) from continuing operations of those periods.

In June 2002, the FASB issued SFAS No. 146, “Accounting for Costs Associated with Exit or Disposal Activities” (“SFAS 146”). SFAS 146 addresses financial accounting and reporting for costs associated with exit or disposal activities and nullified Emerging Issues Task Force Issue No. 94-3, “Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring”. SFAS 146 requires that a liability for a cost associated with an exit or disposal activity be recognized when the liability is incurred. SFAS 146 also establishes that fair value is the objective for initial measurement of the liability. The provisions of this statement are effective for exit or disposal activities that are initiated after December 31, 2002. We will adopt the provisions of SFAS 146 on January 1, 2003 and are currently assessing the impact of the statement on our financial position and results of operations, if any.

Note 3 — Assignment of U.K. Property Interest

In August 2002, we entered into an agreement, which was completed on September 30, 2002, whereby we assigned 50% of our working interest in the Helvellyn development in the U.K. North Sea to First Oil Expro Limited (“First Oil”). The terms of the agreement required First Oil to pay a disproportionate share of the development costs on the project. First Oil’s share of these costs totaled $17.3 million through September 30, 2002, of which $2.6 million was paid to us in cash, $12.6 million is included in accounts receivable and $2.1 million is included as a receivable in other long term assets. We retain a 50% working interest and continue as the operator of the field.

Note 4 — Long-Term Debt

Long-term debt as of the dates indicated was as follows (in thousands):

	September 30, 2002			December 31, 2001
Credit facility	$	58,000		$	70,000
Note payable, net of unamortized discount of $936 and $1,139, respectively		30,314			30,111

Total debt		88,314			100,111
Less current maturities		(4,000	)		(22,000	)

Total long-term debt	$	84,314		$	78,111

We have a $100.0 million senior-secured revolving credit facility which is secured by substantially all of our U.S. oil and gas properties, as well as by approximately two-thirds of the capital stock of our foreign subsidiaries and is guaranteed by our wholly owned subsidiary, ATP Energy, Inc. The amount available for borrowing under the amended facility is limited to the loan value, as determined by the bank, of oil and gas properties pledged under the facility. At September 30, 2002, the borrowing base was $60.0 million with a $2.0 million monthly borrowing base reduction. On November 5, 2002, the borrowing base was set at $56.0 million with a borrowing base reduction of $2.0 million on December 1, 2002. There is currently no further scheduled reduction. The $4.0 million of current maturities of long-term debt is based upon the borrowing base and reduction amounts which were established on November 5, 2002. The redetermination dates are scheduled during the first month of each calendar quarter at which time the lenders can increase or decrease the borrowing base and re-establish the monthly reduction amount. If our outstanding balance exceeds our borrowing base at any time, we are required to repay such excess within 30 days and our interest rate during the time an excess exists is increased by 2.00%. A material reduction in the borrowing base or a material increase in the monthly reduction amount by the lender would have a material negative impact on our cash flows and our ability to fund future operations.

Advances under the credit facility can be in the form of either base rate loans or Eurodollar loans. The interest on a base rate loan is a fluctuating rate equal to the higher of the Federal funds rate plus 0.5% and the bank base rate, plus a margin of 0.25%, 0.50%, 0.75% or 1.00% depending on the amount outstanding under the credit agreement. The interest on a Eurodollar loan is equal to the Eurodollar rate, plus a margin of 2.25%, 2.50%, 2.875%, or 3.125% depending on the amount outstanding under the credit facility. The amended credit facility matures in May 2004. Our credit facility contains conditions and restrictive provisions, among other things, (1) limiting us to enter into any arrangement to sell or transfer any of our material property, (2) prohibiting a merger into or consolidation with any other person or sell or dispose of all or substantially all of our assets, and (3) maintaining certain financial ratios.

Effective June 29, 2001, we issued a note payable to a purchaser for a face principal amount of $31.3 million which matures in June 2005 and bears interest at a fixed rate of 11.5% per annum. The note is secured by second priority liens on substantially all of our U.S. oil and gas properties and is subordinated in right of payment to our existing senior indebtedness. We executed an agreement in connection with the note which contains conditions and restrictive provisions and requires the maintenance of certain financial ratios. Upon consent of the purchaser, which shall not be unreasonably withheld, the note may be repaid prior to the maturity date with an additional repayment premium based on the percentage of the principal amount paid, ranging from 4.5% during the first year to 16.5% in the final year of payment. If the note is paid at maturity, the maximum payment premium of 16.5% is required. The expected repayment premium is being amortized to interest expense straight-line, over the term of the note which approximates the effective interest method. The resulting liability is included in other long-term liabilities on the consolidated balance sheet. In July 2001, we received proceeds of $30.0 million in consideration for the issuance of the note. The discount of $1.3 million is being amortized to interest expense using the effective interest method. The amount available for borrowing under the note is limited to the loan value of oil and gas properties pledged under the note, as determined by the purchaser. The purchaser has the right to make a redetermination of the borrowing base at least once every six months. We have not been notified of any change in the borrowing base in 2002. If our outstanding balance exceeds the borrowing base at any time, we are required to repay such excess within 10 days subject to the provisions of the agreement. A material reduction in the borrowing base by the lender would have a material negative impact on our cash flows and our ability to fund future obligations. As of September 30, 2002, all of our borrowing base under the agreement was outstanding.

As of September 30, 2002, we were in compliance with all of the financial covenants of our credit facility and note payable agreements. We anticipate that we will be in compliance with all of the covenants for both agreements for the remainder of the year.

Note 5 — 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 September 30,					Nine Months Ended September 30,
	2002		2001			2002			2001
Net income (loss)	$	1,665	$	(6,499	)	$	(1,527	)	$	(10,161	)

Weighted average shares outstanding—basic		20,316		20,297			20,315			19,499
Effect of dilutive securities – stock options		116		–			–			–

Weighted average shares outstanding—diluted		20,432		20,297			20,315			19,499

Net income (loss) per share – basic and diluted	$	0.08	$	(0.32	)	$	(0.08	)	$	(0.52	)

Note 6 —Comprehensive Income

Comprehensive income consists of net income, as reflected on the consolidated statement of operations, and other gains and losses affecting shareholders’ equity that are excluded from net income. The change in accumulated other comprehensive income (loss), net of tax, for the three and nine months ended September 30, 2002 and 2001 is as follows (in thousands):

	Three Months Ended September 30,						Nine Months Ended September 30,
	2002			2001			2002			2001
Balance at beginning of period	$	(6	)	$	(5,335	)	$	19		$	–
Cumulative effect of change in accounting principle – January 1, 2001		–			–			–			(34,252	)
Reclassification adjustment for settled contracts		–			3,991			–			32,972
Change in fair value of derivative hedging instruments		(1,845	)		–			(1,845	)		–
Foreign currency translation adjustment		476			172			451			108

Balance at end of period	$	(1,375	)	$	(1,172	)	$	(1,375	)	$	(1,172	)

Total comprehensive income for the three months ended September 30, 2002 was $0.3 million and total comprehensive loss for the nine months ended September 30, 2002 was $2.9 million. Total comprehensive loss for the three and nine months ended September 30, 2001 was $2.3 million and $11.3 million, respectively.

Note 7 —Stock Option Compensation

For the nine months ended September 30, 2002, we recorded a non-cash charge to compensation expense of approximately $0.5 million for options granted since September 1999 through the date of our initial public offering on February 5, 2001 (the “measurement date”). The total expected expense as of the measurement date will be recognized in the periods in which the option vests. Each option is divided into three equal portions corresponding to the three vesting dates (April 10, 2001, February 9, 2002, and February 9, 2003), with the related compensation cost for each portion amortized straight-line over the period to the vesting date. For the nine months ended September 30, 2001, we recorded a non-cash compensation expense of $2.4 million for the above options and an additional non-cash compensation expense of $0.5 million related to certain options granted prior to September 1999 and exercised in the first nine months of 2001. The additional $0.5 million expense was recorded as a result of the manner in which those shares were exercised.

Note 8 —Derivative Instruments and Price Risk Management Activities

On January 1, 2001, we adopted SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (“SFAS 133”), as amended, and recorded a cumulative transition loss of $34.3 million, net of tax, to accumulated other comprehensive income to account for the effect of the change in accounting principle. The standard requires that all derivatives be recorded on the balance sheet at fair value and establishes criteria for documentation and measurement of hedging activities.

We regularly use derivative instruments with respect to a portion of our oil and gas production to manage our exposure to price volatility. These instruments, which are generally placed with counter parties which we believe to be of high credit quality, may take the form of futures contracts, swaps or options.

Prior to July 1, 2002, we had not attempted to qualify our derivatives for the hedge accounting provisions under SFAS 133. Accordingly, we accounted for the changes in market value of these derivatives through current earnings. Gains and losses on all derivative instruments prior to July 1, 2002 were included in other income (expense) on the consolidated financial statements.

Loss on derivative instruments is comprised of the following components for the periods indicated (in thousands):

	Three Months Ended September 30,					Nine Months Ended September 30,
	2002		2001			2002			2001
Gain (loss) on settled contracts during the period	$	–	$	3,883		$	(153	)	$	(22,665	)
Gain (loss) on open derivative positions at September 30		–		(7,217	)		(8,166	)		5,169

Total	$	–	$	(3,334	)	$	(8,319	)	$	(17,496	)

As of July 1, 2002, we performed the requisite steps to qualify our existing derivative instruments for hedge accounting treatment under the provisions of SFAS 133. Derivative instruments designated as cash flow hedges are reflected at fair value on our consolidated balance sheets. Changes in fair value, to the extent the hedge is effective, are recognized in other comprehensive income until the hedged item is settled and is recognized in earnings. Any ineffective portion of the derivative instrument’s change in fair value is recognized in revenues in the current period. Hedge effectiveness is measured at least quarterly.

Oil and gas revenues are comprised of the following components for the periods indicated (in thousands):

	Three Months Ended September 30,					Nine Months Ended September 30,
	2002			2001		2002			2001
Oil and gas production	$	23,008		$	19,571	$	69,360		$	87,081
Derivative settlements during the period		(998	)		–		(998	)		–

		22,010			19,571		68,362			87,081
Amounts previously recognized in earnings prior to July 1, 2002 qualification for hedge accounting (1)		998			–		998			–
Change in fair value of derivative hedging instruments (2)		58			–		58			–
Ineffective portion of derivative hedging instruments		93			–		93

Total	$	23,159		$	19,571	$	69,511		$	87,081

(1)

Represents the mark to market valuation of open positions at June 30, 2002 for the periods indicated which were previously recognized in other income (expense).

(2)

Represents the change in fair value of settled positions between the beginning and end of the period.

At September 30, 2002, a $2.7 million loss ($1.8 million after tax) was recorded to accumulated other comprehensive loss for the effective portion of the change in fair market value during the third quarter of 2002. Approximately $1.7 million of net deferred losses included in accumulated other comprehensive income at September 30, 2002 will be reversed during the next twelve months as the forecasted transactions actually occur, assuming no further changes in fair market value. All forecasted transactions currently being hedged are expected to occur by December 2003.

As of September 30, 2002, we had derivative contracts in place for the following natural gas and oil volumes:

Period	Volumes	Average Fixed Price
Natural gas (MMBtu):
Remainder of 2002	2,026,000	$	2.96
2003	6,080,000		3.02

Oil (Bbl):
Remainder of 2002	46,000	$	23.50
2003	182,500		24.10

In addition to these derivative instruments, we also manage our exposure to oil and gas price risks by periodically entering into fixed-price delivery contracts, which are exempt from the provisions of SFAS 133. As of September 30, 2002, we had fixed-price contracts in place for the following natural gas and oil volumes:

Period	Volumes	Average Fixed Price
Natural gas (MMBtu):
Remainder of 2002 (1)	887,000	$	3.80
2003 (1)	4,226,000		3.78

Oil (Bbl):
Remainder of 2002 (1)	136,016	$	26.00
2003	90,500		25.78

The following table summarizes all derivative instruments and fixed-price contracts as of September 30, 2002:

Period	Volumes	Average Fixed Price
Natural gas (MMBtu):
Remainder of 2002 (1)	2,913,000	$	3.21
2003 (1)	10,306,000		3.31

Oil (Bbl):
Remainder of 2002 (1)	182,016	$	25.31
2003	273,000		24.66

(1)

Includes the effect of fixed basis differentials on certain of our fixed-price contracts.

Note 9 —Commitments and Contingencies

ATP filed suit against Legacy Resources Co., LLP and agent (“Legacy”) in the District Court of Harris County, Texas in a dispute over a contract for the sale by Legacy of an oil and gas property to ATP. The court has abated the litigation pursuant to an arbitration provision in the contract. In the arbitration proceedings Legacy alleges that ATP owes it $12.3 million plus interest and expenses. ATP intends to vigorously defend against these claims. The arbitration is scheduled for February, 2003. Due to the uncertainties of the legal and arbitration proceedings, a prediction of the outcome cannot be made with any degree of certainty and we have not accrued any amount related to this matter. Payments totaling $3.0 million made to Legacy in October of 2001 under the original contract were charged to earnings in 2001 along with certain other costs related to this matter.

In August 2001, Burlington Resources Inc. filed suit against ATP alleging formation of a contract with ATP and our breach of the alleged contract. The complaint seeks compensatory damages of approximately $1.1 million. We believe that this claim is without merit, and we intend to defend it vigorously.

We are also, 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.

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Overview

ATP Oil & Gas Corporation (“ATP”), a Texas corporation, was formed on August 8, 1991 and is engaged in the acquisition, development and production of natural gas and oil properties in the Gulf of Mexico and in the North Sea. We primarily focus our efforts on natural gas and oil 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. We attempt to achieve a high return on our investment in these properties by limiting our up-front acquisition costs, developing the properties in a relatively short period of time and by operating the properties efficiently.

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 the instructions to interim reporting as prescribed by the Securities and Exchange Commission (“SEC”). 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. As of July 1, 2002, we performed the requisite steps to qualify our derivative instruments for hedge accounting treatment under the provisions of Financial Accounting Standards Board (“FASB”) Statement of Financial Accounting Standard (“SFAS”) No. 133, “Accounting for Derivative Instruments and Hedging Activities” (“SFAS 133”), as amended. Beginning July 1, 2002, unrealized gains and losses related to the effective portion of the change in fair market value of derivative contracts which qualify as hedges are recorded in other comprehensive income and such amounts are reclassified to oil and gas revenues as the associated production occurs. Prior to July 1, 2002, gains or losses from these instruments were included in other income (expense). Our 2001 Annual Report on Form 10-K includes a further discussion of our critical accounting policies.

Results of Operations

The following table sets forth selected financial and operating information for our natural gas and oil operations inclusive of the effects of price risk management activities:

	Three Months Ended September 30,					Nine Months Ended September 30,
	2002			2001		2002			2001
Production:
Natural gas (MMcf)		4,421			5,512		14,449			16,298
Oil and condensate (MBbls)		353			165		1,164			368

Total (Mmcfe)		6,536			6,504		21,435			18,505

Revenues (in thousands):
Natural gas	$	14,354		$	15,574	$	43,616		$	77,699
Effects of risk management activities (1)		(723	)		3,883		(751	)		(22,665	)

Total	$	13,631		$	19,457	$	42,865		$	55,034

Oil and condensate	$	8,654		$	3,997	$	25,744		$	9,382
Effects of risk management activities (1)		(275	)		–		(400	)		–

Total	$	8,379		$	3,997	$	25,344		$	9,382

Natural gas, oil and condensate	$	23,008		$	19,571	$	69,360		$	87,081
Effects of risk management activities (1)		(998	)		3,883		(1,151	)		(22,665	)

Total	$	22,010		$	23,454	$	68,209		$	64,416

Table and footnote continued on following page

	Three Months Ended September 30,					Nine Months Ended September 30,
	2002			2001		2002			2001
Average sales price per unit:
Natural gas (per Mcf)	$	3.25		$	2.83	$	3.02		$	4.77
Effects of risk management activities (per Mcf)		(0.16	)		0.70		(0.05	)		(1.39	)

Total	$	3.09		$	3.53	$	2.97		$	3.38


Oil and condensate (per Bbl)	$	24.55		$	24.20	$	22.11		$	25.50
Effects of risk management activities (per Bbl)		(0.78	)		–		(0.34	)		–

Total	$	23.77		$	24.20	$	21.77		$	25.50


Natural gas, oil and condensate (per Mcfe)	$	3.52		$	3.01	$	3.24		$	4.71
Effects of risk management activities (per Mcfe)		(0.15	)		0.60		(0.05	)		(1.22	)

Total	$	3.37		$	3.61	$	3.19		$	3.49


Expenses (per Mcfe):
Lease operating expense	$	0.75		$	0.38	$	0.57		$	0.52
General and administrative		0.40			0.41		0.36			0.36
Depreciation, depletion and amortization		1.58			2.06		1.64			2.08

(1)

Represents the loss on the settlement of derivatives attributable to third quarter 2002 and 2001 production of 6.5 Bcfe each and first nine months 2002 and 2001 production of 21.4 Bcfe and 18.5 Bcfe, respectively.

Three Months Ended September 30, 2002 Compared with Three Months Ended September 30, 2001

For the three months ended September 30, 2002, we reported net income of $1.7 million, or $0.08 per share on total revenue of $24.7 million, as compared with net loss of $6.5 million, or $0.32 per share on total revenue of $20.9 million in the third quarter of 2001.

Oil and Gas Revenue. Our revenue from natural gas and oil production (excluding effects of price risk management activities) for the third quarter of 2002 increased from the same period in 2001 by approximately 18%, from $19.6 million to $23.0 million. This increase was primarily due to an approximate 17% increase in our average sales price per Mcfe from $3.01 per Mcfe in the third quarter of 2001 to $3.52 in the comparable quarter of 2002.

Marketing Revenue. Revenues from natural gas marketing activities increased to $1.5 million in the third quarter of 2002 as compared to $1.3 million in the third quarter of 2001. This increase was due to an increase in the sales price per MMBtu. The average sales price per MMBtu increased from $2.85 in the third quarter of 2001 to $3.28 in the third quarter of 2002.

Lease Operating Expense. Lease operating expenses for the third quarter of 2002 increased to $4.9 million from $2.5 million in the third quarter of 2002. This increase was attributable to workover activities on three of our properties in the third quarter of 2002 as compared to the third quarter of 2001 when no such expenses were incurred. In addition, start up expenses on two of our properties were recorded in the third quarter of 2002 as well as major repairs required on another property.

Gas Purchased-Marketing. Our cost of purchased gas was $1.5 million for the third quarter of 2002 compared to $1.3 million for the third quarter of 2001. The average cost increased from $2.74 per MMBtu in 2001 to $3.18 per MMBtu in 2002.

General and Administrative Expense. General and administrative expense decreased to $2.6 million for the third quarter of 2002 compared to $2.7 million for the same period in 2001. A charge for bad debts and certain public company related expenses recognized in the third quarter of 2001 partially offset an increase in 2002 costs related to our enhanced activity in the U.K. and an increase in certain compensation related costs.

Non-Cash Compensation Expense. In the third quarter of 2002, we recorded a minor non-cash adjustment to compensation expense for options forfeited during the period. In the third quarter of 2001, we recorded a non-cash charge to compensation expense of $0.5 million, for options granted since September 1999 through the date of our initial public offering on February 5, 2001 (the “measurement date”). The total expected expense as of the measurement date will be recognized in the periods in which the option vests. Each option is divided into three equal portions corresponding to the three vesting dates (April 10, 2001, February 9, 2002, and February 9, 2003), with the related compensation cost for each portion amortized straight-line over the period to the vesting date.

Depreciation, Depletion and Amortization Expense. Depreciation, depletion and amortization expense decreased 23% from the third quarter 2001 amount of $13.4 million to the third quarter 2002 amount of $10.4 million. The average DD&A rate was $1.58 per Mcfe in the third quarter of 2002 compared to $2.06 per Mcfe in the same quarter of 2001. This decrease in the rate for the quarter was attributable to (1) impairments taken in the prior year, (2) significantly lower production on two of our higher rate properties, (3) higher than expected costs of a an abandonment completed in 2001 and (4) a new property brought on line in 2002 with a lower average rate than those properties producing in 2001.

Impairment Expense. We recorded no impairments in the third quarter of 2002. For the third quarter of 2001, we recorded impairments of $3.7 million due primarily to reductions in expected future cash flows on two depletable units due to reserve adjustments at September 30, 2001.

Other Income (Expense). In the third quarter of 2001, we recorded a loss on derivative instruments of $3.3 million. The net loss in the third quarter of 2001 was comprised of a realized gain of $3.9 million for derivative contracts settled in the quarter and an unrealized loss of $7.2 million representing the change in fair market value of the open derivative positions at September 30, 2001. Upon qualifying for the hedge accounting provisions of SFAS 133 on July 1, 2002, all prospective gains and losses on settled derivative contracts are recorded as a component of oil and gas revenues and the effective portion of any changes in the fair market value of open positions is recorded in other comprehensive income.

Interest expense increased to $2.7 million in the third quarter of 2002 from $2.1 million in the comparable quarter of 2001 primarily due to higher borrowing levels and increased amortization resulting from higher debt financing costs.

Nine Months Ended September 30, 2002 Compared with Nine Months Ended September 30, 2001

For the nine months ended September 30, 2002, we reported a net loss of $1.5 million, or $0.08 per share, on total revenue of $73.8 million, as compared with a net loss of $10.2 million, or $0.52 per share, on total revenue of $93.4 million in the first nine months of 2001.

Oil and Gas Revenue. Our revenue from natural gas and oil production (excluding effects of price risk management activities) for the first nine months of 2002 decreased approximately 20% from the same period in 2001, from $87.1 million to $69.4 million. This decrease was primarily due to an approximate 31% decrease in our average sales price per Mcfe from $4.71 per Mcfe in the first nine months of 2001 to $3.24 per Mcfe in the first nine months of 2002. This decrease was partially offset by a 16% increase in production from 18.5 Bcfe to 21.4 Bcfe due primarily to two properties that were completed in 2002 and made no contribution in 2001. Additionally, one property was completed in September 2001 but contributed a full nine months production in 2002.

Marketing Revenue. Revenues from natural gas marketing activities decreased to $4.3 million in the first nine months of 2002 as compared to $6.3 million in the first nine months of 2001. This decrease was due to a decrease in the sales price per MMBtu. The average sales price per MMBtu decreased from $4.60 in the first nine months of 2001 to $3.12 in the first nine months of 2002.

Lease Operating Expense. Lease operating expenses for the first nine months of 2002 increased to $12.3 million from $9.7 million in the first nine months of 2001 due primarily to an overall production increase resulting from three properties completed in 2001 and 2002.

Gas Purchased-Marketing. Our cost of purchased gas was $4.1 million for the first nine months of 2002 compared to $6.1 million for the first nine months of 2001. The average cost decreased from $4.49 per MMBtu in 2001 to $3.02 per MMBtu in 2002.

General and Administrative Expense. General and administrative expense increased to $7.6 million for the first nine months of 2002 compared to $6.7 million for the same period in 2001. The increase was primarily due to higher compensation related costs, enhanced activities in our U.K. office, and bank charges connected with financing arrangements.

Non-cash Compensation Expense. In the first nine months of 2002, we recorded a non-cash charge to compensation expense of approximately $0.5 million for options granted since September 1999 through the date of our initial public offering on February 5, 2001 (the “measurement date”). The total expected expense as of the measurement date will be recognized in the periods in which the option vests. Each option is divided into three equal portions corresponding to the three vesting dates (April 10, 2001, February 9, 2002, and February 9, 2003), with the related compensation cost for each portion amortized straight-line over the period to the vesting date. In the first nine months of 2001, we recorded a non-cash compensation expense of $2.4 million for the above options and an additional non-cash compensation expense of $0.5 million related to certain options granted prior to September 1999 and exercised in the first nine months of 2001. The additional $0.5 million expense was recorded as a result of the manner in which those shares were exercised.

Depreciation, Depletion and Amortization Expense. Depreciation, depletion and amortization expense decreased from the first nine months 2001 amount of $38.5 million to the first nine months 2002 amount of $35.2 million. The average DD&A rate was $1.64 per Mcfe in the first nine months of 2002 compared to $2.08 per Mcfe in the same nine months of 2001. This decrease in the rate for the nine months was attributable to (1) impairments taken in the prior year, (2) higher than expected costs of a an abandonment completed in 2001 and (3) a new property brought on line in 2002 with a lower average rate than those properties producing in 2001.

Impairment Expense. We recorded no impairments in the first nine months of 2002. During the nine months ended September 30, 2001, we recorded impairments of $17.8 million on six of our depletable units. These impairments were primarily the result of drilling a non-commercial development well and a reduction in expected future cash flows on the other properties due to lower expectations of future natural gas prices at September 30, 2001.

Other Income (Expense). Effective July 1, 2002, we qualified for hedge accounting treatment under the provisions of SFAS 133 and began recording any gains or losses on settled derivative instruments as a component of oil and gas revenue. The effective portion of any changes in the fair market value of open positions at the end of the period is recorded in other comprehensive income. The loss on derivative instruments of $8.3 million in the first nine months of 2002 represents amounts recorded prior to July 1, 2002. The net loss in 2002 is comprised of a realized loss of $0.1 million for derivative contracts settled in the first half of 2002 and an unrealized loss of $8.2 million representing the change in fair market value of the open derivative positions at June 30, 2002. In the first nine months of 2001, we recorded a loss on derivative instruments of $17.5 million. The net loss in 2001 was comprised of a realized loss of $22.7 million for derivative contracts settled in the period and an unrealized gain of $5.2 million representing the change in fair market value of the open derivative positions at September 30, 2001.

Interest expense increased to $8.0 million in the first nine months of 2002 from $7.1 million in the comparable nine months of 2001 primarily due to higher borrowing levels.

Liquidity and Capital Resources

We have financed our acquisition and development activities through a combination of project-based development arrangements, bank borrowings and proceeds from our February 2001 IPO, 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 U.K. through available cash flows and the potential sell down of 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.

However, future cash flows are subject to a number of variables including changes in the borrowing base, the level of production from our properties, oil and natural gas prices and the impact, if any, of commitments and contingencies. Future borrowings under credit facilities are subject to variables including the lenders’ practices and policies, changes in the prices of oil and natural gas and changes in our oil and gas reserves. A material reduction in the borrowing base or an increase in the monthly reduction amount by our lenders would have a material negative impact on our cash flows and our ability to fund future obligations. No assurance can be given that operations and other capital resources will provide cash in sufficient amounts to maintain planned levels of operations and capital expenditures. Historically, in periods of reduced availability of funds from either cash flows or credit sources we have delayed planned capital expenditures and will continue do to so when necessary. While the delay decreases the amount of capital expenditures in the current period, it could negatively impact our future revenues and cash flows.

Cash Flows

	Nine Months Ended, September 30,
	2002			2001
	(in thousands)
Cash provided by (used in)
Operating activities	$	30,681		$	62,085
Investing activities		(17,994	)		(108,858	)
Financing activities		(12,487	)		38,148

Cash provided by operating activities in the first nine months of 2002 and 2001 was $30.7 million and $62.1 million, respectively. Cash flow from operations decreased primarily due to the decline in oil and gas prices from the first nine months of 2001, somewhat offset by the 16% increase in production. In addition, our significant decrease in development activity during the first nine months of 2002 allowed us to use available cash to reduce amounts owed to third parties. Restricted cash of $1.6 million represents funds set aside to satisfy payment conditions in our drilling contract for development in the U.K.

Cash used in investing activities in the first nine months of 2002 and 2001 was $18.0 million and $108.9 million, respectively. We incurred no costs for two acquisitions made in the first nine months of 2002 and incurred $17.7 million for developmental capital expenditures, of which $12.7 million was incurred for activity in the Gulf of Mexico and $5.0 million was incurred for projects in the U.K. In the first nine months of 2001, capital expenditures for acquisition and development activities were $30.8 million and $77.6 million, respectively.

Cash used in financing activities in the first nine months of 2002 represents net principal payments on our credit facility. Cash provided from financing activities in the first nine months of 2001 included the proceeds from our initial public offering in February 2001 of $78.3 million, repayment of prior credit facilities of $119.9 million and proceeds of $95.0 million from our credit facility and promissory note.

Credit Facilities

Note Payable

As of September 30, 2002, we were in compliance with all of the financial covenants of our credit facility and note payable agreements. We anticipate that we will be in compliance with all financial covenants for both agreements for the remainder of the year.

Working Capital

At September 30, 2002, we had working capital of approximately $0.5 million, an improvement over our working capital deficit of $29.1 million at December 31, 2001. In compliance with the definition of working capital in our credit facilities, which excludes current maturities of long-term debt and the current portion of assets and liabilities from derivatives, we had working capital of approximately $11.6 million at September 30, 2002 as compared to a deficit of approximately $9.0 million at December 31, 2001. The significant improvement in our working capital is primarily the result of the reclassification of current maturities of debt to long-term and the increase in accounts receivable from our participant in the Helvellyn Field project. 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.

Our current year planned development, acquisition and debt reduction programs are projected to be funded by available cash flow from our 2002 operations. 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 capital requirements. In addition to these measures, we are currently in discussions with potential investors to provide additional capital. These discussions involve increases to our current credit facilities, new credit facilities and the sale of interests in selected properties. We have also explored the possibility of the issuance of new debt or equity. Completion of any of these potential financings will expand our capabilities to further reduce our outstanding indebtedness, increase our working capital and expand or accelerate our 2002 and future development and acquisition programs. There can be no assurance however, that we will be successful in negotiating any of these transactions or that the form of the transaction will be acceptable to both the potential investor and our management or our board of directors.

Commitments and Contingencies

Accounting Pronouncements

See Note 1 to our Consolidated Financial Statements for a discussion of recently issued accounting pronouncements.

Item 3. Quantitative and Qualitative Disclosures about Market Risks

We are exposed to various market risks, including volatility in natural gas and oil commodity prices and interest rates. To manage such exposure, we monitor our expectations of future commodity prices and interest rates when making decisions with respect to risk management. Substantially all of our derivative contracts are entered into with counter parties which we believe to be of high credit quality and the risk of credit loss is considered insignificant. We have never experienced a loss on a derivative contract due to the inability of the counter party to fulfill their portion of the contract.

Commodity Price Risk. Our revenues, profitability and future growth depend substantially on prevailing prices for natural gas and oil. Prices also affect the amount of cash flow available for capital expenditures and our ability to borrow and raise additional capital. The amount we can borrow under our bank credit facility is subject to periodic re-determination based in part on changing expectations of future prices. Lower prices may also reduce the amount of natural gas and oil that we can economically produce. We currently sell a portion of our natural gas and oil production under price sensitive or market price contracts. To reduce exposure to fluctuations in natural gas and oil prices and to achieve more predictable cash flows, we periodically enter into arrangements that usually consist of swaps or price collars that are settled in cash. However, these contracts also limit the benefits we would realize if commodity prices increase. In addition to these arrangements, we also manage our exposure to oil and gas price risks by periodically entering into fixed-price delivery contracts. (See Note 7 to our Consolidated Financial Statements for a discussion of activities involving derivative financial instruments during 2002.) 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 natural gas and oil prices. We will 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.

To calculate the potential effect of the derivative and fixed-price contracts on future income (loss) before taxes, we applied the NYMEX oil and gas strip prices as of September 30, 2002 to the quantity of our oil and gas production covered by those contracts as of that date. The following table shows the estimated potential effects of the derivative and fixed-price contracts on future income (loss) before taxes (in thousands):

	Estimated Increase (Decrease) In Income (Loss) Before Taxes Due to
Instrument	10% Decrease in Prices		10% Increase in Prices
Natural gas swaps	$	3,266	$	(3,266	)
Oil swaps		622		(622	)
Natural gas fixed price contracts		2,099		(2,099	)
Oil fixed price contracts		663		(663	)

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 agreements. 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 subsidiary in the U.K. 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.

Item 4. Controls and Procedures

a. Based on their evaluation of the Company’s disclosure controls and procedures as of a date within 90 days of the filing date of this Quarterly Report on Form 10-Q, the Company’s chief executive officer and chief financial officer have concluded that Company’s disclosure controls and procedures were adequate and designed to ensure that material information relating to the Company and the Company’s consolidated subsidiaries would be made known to them by others within those entities.

b. There were no significant changes in the Company’s internal controls or in other factors that could significantly affect these controls subsequent to the date of their evaluation.

Forward-Looking Statements and Associated Risks

Some of the information included in this quarterly report includes assumptions, expectations, projections, intentions or beliefs about future events. These statements are intended as “forward-looking statements” under the Private Securities Litigation Reform Act of 1995. We caution that assumptions, expectations, projections, intentions and beliefs about future events may and often do vary from actual results and the differences can be material.

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

•

projected operating or financial results;

•

budgeted or projected capital expenditures;

•

statements about pending or recent acquisitions, including the anticipated closing dates;

•

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

•

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

•

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

•

timing and amount of future production of natural gas and oil.

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

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

•

the timing and extent of changes in natural gas and oil prices;

•

the timing of planned capital expenditures and availability of acquisitions;

•

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

•

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

•

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

•

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

•

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

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 – None

99.1 Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

B. Reports on Form 8-K – None.

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: November 13, 2002	By:	/s/ Albert L. Reese, Jr.
		Albert L. Reese, Jr. Senior Vice President and Chief Financial Officer

CERTIFICATIONS

I, T. Paul Bulmahn, certify that:

1. I have reviewed this quarterly report on Form 10-Q of ATP Oil & Gas Corporation;

2. Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report;

3. Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this quarterly report;

4. The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:

a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared;

b) evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the “Evaluation Date”); and

c) presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

5. The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent function):

a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant’s auditors any material weaknesses in internal controls; and

b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and

6. The registrant’s other certifying officers and I have indicated in this quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.


Date: November 13, 2002	By:	/s/ T. Paul Bulmahn
		T. Paul Bulmahn President and Chief Executive Officer

I, Albert L. Reese, Jr., certify that:

1. I have reviewed this quarterly report on Form 10-Q of ATP Oil & Gas Corporation;

b) evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the “Evaluation Date”); and

c) presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and


Date: November 13, 2002	By:	/s/ Albert L. Reese, Jr.
		Albert L. Reese, Jr. Senior Vice President and Chief Financial Officer

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