Form 10-Q for Period Ended 06/30/2003

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10-Q 1 d10q.htm FORM 10-Q FOR PERIOD ENDED 06/30/2003 Form 10-Q for Period Ended 06/30/2003

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-Q

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

For the quarterly period ended June 30, 2003

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 þ No ¨

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act) Yes ¨ No þ

The number of shares outstanding of Registrant’s common stock, par value $0.001, as of August 11, 2003, was 24,500,356.

ATP OIL & GAS CORPORATION

TABLE OF CONTENTS

		Page
PART I.	FINANCIAL INFORMATION

ITEM 1.	FINANCIAL STATEMENTS
	Consolidated Balance Sheets:
	June 30, 2003 (unaudited) and December 31, 2002	3
	Consolidated Statements of Operations:
	For the three and six months ended June 30, 2003 and 2002 (unaudited)	4
	Consolidated Statements of Cash Flows:
	For the three and six months ended June 30, 2003 and 2002 (unaudited)	5
	Consolidated Statements of Comprehensive Income (Loss):
	For the three and six months ended June 30, 2003 and 2002 (unaudited)	6
	Notes to Consolidated Financial Statements (unaudited)	7

ITEM 2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	17

ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	24

ITEM 4.	CONTROLS AND PROCEDURES	25

PART II.	OTHER INFORMATION	26

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(In Thousands, Except Share Amounts)

	June 30, 2003			December 31, 2002
	(unaudited)
Assets
Current assets
Cash and cash equivalents	$	5,536		$	6,944
Restricted cash		—			414
Accounts receivable (net of allowance of $1,266)		27,043			24,998
Deferred tax asset		1,556			1,628
Other current assets		3,388			3,245

Total current assets		37,523			37,229

Oil and gas properties (using the successful efforts method of accounting)		412,313			355,088
Less: Accumulated depletion, impairment and amortization		(240,955	)		(236,052	)

Oil and gas properties, net		171,358			119,036

Furniture and fixtures (net of accumulated depreciation)		770			810
Deferred tax asset		20,057			21,580
Other assets, net		2,296			3,400

Total assets	$	232,004		$	182,055

Liabilities and Shareholders’ Equity
Current liabilities
Accounts payable and accruals	$	47,842		$	35,336
Current maturities of long-term debt		—			6,000
Asset retirement obligation		5,659			—
Derivative liability		6,442			9,592

Total current liabilities		59,943			50,928
Long-term debt		80,537			80,387
Asset retirement obligation		16,495			—
Deferred revenue		1,019			1,111
Other long-term liabilities and deferred obligations		20,603			11,082

Total liabilities		178,597			143,508

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; 24,571,196 issued and 24,495,356 outstanding at June, 2003; 20,398,007 issued and 20,322,167 outstanding at December 31, 2002		25			20
Additional paid in capital		92,214			81,087
Accumulated deficit		(36,485	)		(39,314	)
Accumulated other comprehensive loss		(1,436	)		(2,335	)
Treasury stock		(911	)		(911	)

Total shareholders’ equity		53,407			38,547

Total liabilities and shareholders’ equity	$	232,004		$	182,055

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 June 30,						Six Months Ended June 30,
	2003			2002			2003			2002
Oil and gas revenues	$	18,627		$	27,742		$	39,107		$	46,352

Total revenues
Costs and operating expenses:
Lease operating expenses		3,702			3,542			7,329			7,357
Geological and geophysical expenses		146			54			300			11
General and administrative expenses		3,351			2,556			6,563			5,034
Non-cash compensation expense (general and administrative)		—			244			(39	)		487
Depreciation, depletion and amortization		6,095			13,030			13,857			24,890
Accretion expense		718			—			1,447			—
Loss on abandonment		2,655			—			2,655			—

Total costs and operating expenses		16,667			19,426			32,112			37,779

Income from operations		1,960			8,316			6,995			8,573

Other income (expense):
Interest income		22			10			34			26
Interest expense		(2,316	)		(2,614	)		(4,653	)		(5,280	)
Other		1,119			45			1,150			89
Loss on derivative instruments		(122	)		(879	)		(192	)		(8,319	)

Total other income (expense)		(1,297	)		(3,438	)		(3,661	)		(13,484	)

Income (loss) before income taxes and cumulative effect of change in accounting principle		663			4,878			3,334			(4,911	)
Income tax benefit (expense)		(232	)		(1,707	)		(1,167	)		1,719

Income (loss) before cumulative effect of change in accounting principle		431			3,171			2,167			(3,192	)
Cumulative effect of change in accounting principle, net of tax		—			—			662			—

Net income (loss)	$	431		$	3,171		$	2,829		$	(3,192	)

Basic and diluted income (loss) per common share:
Income (loss) before cumulative effect of change in accounting principle	$	0.02		$	0.16		$	0.10		$	(0.16	)
Cumulative effect of change in accounting principle, net of tax		—			—			0.03			—

Net income (loss) per common share	$	0.02		$	0.16		$	0.13		$	(0.16	)

Weighted average number of common shares:
Basic		22,481			20,314			21,413			20,314

Diluted		22,584			20,456			21,558			20,314

See accompanying notes to consolidated financial statements.

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In Thousands)

(Unaudited)

	Six Months Ended June 30,
	2003			2002
Cash flows from operating activities
Net income (loss)	$	2,829		$	(3,192	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities—
Depreciation, depletion and amortization		13,857			24,890
Accretion of discount in asset retirement obligation		1,447			—
Amortization of deferred financing costs		640			768
Other comprehensive income		135			—
Deferred tax asset		1,167			(1,719	)
Non-cash compensation expense		(39	)		487
Other non-cash items		914			154
Cumulative effect of change in accounting principle		(662	)		—
Changes in assets and liabilities—
Accounts receivable and other		(2,188	)		(3,988	)
Restricted cash		414			—
Net (assets) liabilities from risk management activities		(3,078	)		8,166
Accounts payable and accruals		9,116			(6,363	)
Other long-term assets		464			(388	)
Other long-term liabilities and deferred credits		9,429			3,538

Net cash provided by operating activities		34,445			22,353


Cash flows from investing activities
Additions and acquisitions of oil and gas properties		(40,911	)		(11,693	)
Additions to furniture and fixtures		(113	)		(95	)

Net cash used in investing activities		(41,024	)		(11,788	)


Cash flows from financing activities
Proceeds from issuance of common stock, net		10,884			—
Payments of long-term debt		(6,000	)		(10,000	)
Deferred financing costs		—			(158	)
Other		287			2

Net cash provided by (used in) financing activities		5,171			(10,156	)

Increase (decrease) in cash and cash equivalents		(1,408	)		409
Cash and cash equivalents, beginning of period		6,944			5,294

Cash and cash equivalents, end of period	$	5,536		$	5,703

Supplemental disclosures of cash flow information:
Cash paid during the period for interest	$	2,975		$	3,343

Cash paid during the period for taxes	$	—		$	—

See accompanying notes to consolidated financial statements.

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(In Thousands)

(Unaudited)

	Three Months Ended June 30,						Six Months Ended June 30,
	2003			2002			2003			2002
Net income (loss)	$	431		$	3,171		$	2,829		$	(3,192	)

Other comprehensive income (loss):
Reclassification adjustment for settled contracts, net of tax		(21	)		—			(174	)		—
Change in fair value of outstanding hedge positions, net of tax		991			—			309			—
Foreign currency translation adjustment		1,091			(19	)		764			(25	)

Other comprehensive income (loss)		2,061			(19	)		899			(25	)

Comprehensive income (loss)	$	2,492		$	3,152		$	3,728		$	(3,217	)

See accompanying notes to consolidated financial statements.

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Note 1—Organization

The accompanying consolidated financial statements have been prepared in accordance with generally accepted accounting principles for interim information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by generally accepted accounting principles for complete financial statements. In the opinion of management, all material adjustments (consisting of normal recurring adjustments) considered necessary for a fair presentation have been included. 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 six months ended June 30, 2003 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 2002 Annual Report on Form 10-K.

Note 2—Accounting Pronouncements

SFAS No. 141, “Business Combinations” (“SFAS 141”) and SFAS No. 142, “Goodwill and Intangible Assets,” (“SFAS 142”) became effective on July 1, 2001 and January 1, 2002, respectively. We understand that the Financial Accounting Standards Board (“FASB”) and the staff of the Securities Exchange Commission (“SEC”) are evaluating whether SFAS 141 and SFAS 142 require the cash costs of oil and gas leasehold interests or other contractual arrangements to be classified as intangible assets. If such costs were deemed to be intangible assets, the costs for both undeveloped and developed leaseholds would be classified separate from oil and gas properties as intangible assets on our consolidated balance sheets. Historically we, and to our knowledge, almost all other oil and gas companies have included these oil and gas leasehold costs as part of oil and gas properties after SFAS 141 and SFAS 142 became effective.

We will continue to classify our oil and gas leasehold costs as tangible oil and gas properties until further guidance is provided. We anticipate there will be no effect on our results of operations or cash flows.

In April 2002, the FASB issued SFAS No. 145, “Rescission of FASB Statements No. 4, No. 44, and No. 64, Amendment of FASB Statement No. 13, and Technical Corrections” (“SFAS 145”). Among other things, SFAS 145 requires gains and losses from early extinguishment of debt to be included in income from continuing operations instead of being classified as extraordinary items as previously required by generally accepted accounting principles. SFAS 145 is effective for fiscal years beginning after May 15, 2002 and we adopted the statement on January 1, 2003. Gains or losses on early extinguishment of debt that were classified as an extraordinary item in periods prior to adoption must be reclassified into income from continuing operations. The adoption of SFAS 145 required the $0.6 million (net of tax) of extraordinary loss for the year ended December 31, 2001 to be reclassified to interest expense and income tax benefit.

We apply Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees” (“APB 25”) and related interpretations in accounting for stock options. Under APB 25, no compensation expense is recognized when the exercise price of options equals the fair value (market price) of the underlying stock on the date of grant. The following table illustrates the effect on net income and earnings per share if we had applied the fair value recognition provisions of 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”), to stock based compensation:

	Three Months Ended June 30,						Six Months Ended June 30,
	2003			2002			2003			2002
Net income (loss) as reported	$	431		$	3,171		$	2,829		$	(3,192	)
Add: Stock based compensation expense included in reported net income (loss), determined under APB 25, net of related tax effects		—			158			(26	)		316
Deduct: Total stock based compensation expense determined under fair value of all awards, net of related tax effects		(271	)		(668	)		(543	)		(1,337	)

Pro forma net income (loss)	$	160		$	2,661		$	2,260		$	(4,213	)

Earnings per share:
Basic and diluted—as reported	$	0.02		$	0.16		$	0.13		$	(0.16	)
Basic and diluted—pro forma	$	0.01		$	0.13		$	0.11		$	(0.21	)

In April 2003, the FASB issued SFAS No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities” (“SFAS 149”). SFAS 149 amends and clarifies accounting for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities under SFAS 133. SFAS 149 clarifies under what circumstances a contract with an initial net investment meets the characteristic of a derivative and when a derivative contains a financing component that warrants special reporting in the statement of cash flows. This statement is generally effective for contracts entered into or modified after June 30, 2003 and is not expected to have a material impact on our financial statements.

In May 2003, the FASB issued SFAS No. 150, “Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity” (“SFAS 150”). This statement establishes standards for how an issuer classifies and measures in its statement of financial position certain financial instruments with characteristics of both liabilities and equity. In accordance with the standard, financial instruments that embody obligations for the issuer are required to be classified as liabilities. This statement shall be effective for financial instruments entered into or modified after May 31, 2003, and otherwise shall be effective at the beginning of the first interim period beginning after June 15, 2003. We do not expect the provision of this statement to have a significant impact on the statement of financial position.

In January 2003, the FASB issued FASB Interpretation No. 46, “Consolidation of Variable Interest Entities” (“FIN 46”). FIN 46 requires a company to consolidate a variable interest entity if it is designated as the primary beneficiary of that entity even if the company does not have a majority of voting interest. A variable interest entity is generally defined as an entity where its equity is unable to finance its activities or where the owners of the entity lack the risk and rewards of ownership. The provisions of FIN 46 apply immediately to variable interest entities created after January 31, 2003 and to variable interest entities in which an enterprise obtains an interest after that date. The adoption of FIN 46 did not have an effect on our financial position or results of operations.

Emerging Issues Task Force (“EITF”) Issue No. 02-03, “Recognition and Reporting of Gains and Losses on Energy Trading Contracts” under EITF Issues No. 98-10, “Accounting for Contracts Involved in Energy Trading and Risk Management Activities” was issued in June 2002. EITF Issue No. 02-03 addresses certain issues related to energy trading activities, including (a) gross versus net presentation in the income statement, (b) whether the initial fair value of an energy trading contract can be other than the price at which it was exchanged, and (c) accounting for inventory utilized in energy trading activities. As of January 1, 2003, we have presented our gas sold and purchased activities in the statement of operations for all periods on a net rather than a gross basis under other income (expense). The remaining provisions effective January 1, 2003 had no impact on our financial position or results of operations.

Note 3—Acquisitions

In April 2003, we received $8.1 million from a working interest participant related to development costs on one of our properties. We agreed to develop the property within 60 months from receipt of the funds or return the funds with interest if development had not been completed at the expiration of such time. At June 30, 2003, this transaction is reflected as a long-term liability in the financial statements.

Note 4—Asset Retirement Obligations

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. We adopted SFAS 143 on January 1, 2003 and recorded a liability for asset retirement obligations of $23.1 million and a net of tax cumulative effect of change in accounting principle of $0.7 million.

The reconciliation of the beginning and ending asset retirement obligation for the periods ending June 30, 2003 is as follows (in thousands):

	Period Ending June 30, 2003
	Three Months			Six Months
Asset retirement obligation, beginning of period	$	22,822		$	—
Liabilities upon adoption of SFAS 143 on January 1, 2003		—			23,135
Liabilities incurred		531			531
Liabilities settled		(4,572	)		(5,614	)
Accretion expense		718			1,447
Loss on abandonment		2,655			2,655

Asset retirement obligation, as of June 30, 2003	$	22,154		$	22,154

During the second quarter of 2003, we recognized a loss on abandonment of $2.7 million due to actual costs exceeding the original estimates on two properties. These unforeseen overruns were due to difficulties in abandoning one of our properties due to the condition of the wells received from the original owner and the collapse of a platform crane. In addition, we incurred standby time as a result of Hurricane Claudette.

The following table summarizes the pro forma net income (loss) and earnings per share for the three and six months ended June 30, 2002 as if SFAS 143 had been adopted on January 1, 2002 (in thousands, except per share amounts):

	Period Ending June 30, 2002
	Three Months		Six Months
Net income (loss)	$	3,092	$	(3,304	)

Net income (loss) per share – basic and diluted	$	0.15	$	(0.16	)

The pro-forma asset retirement obligation, if the adoption of this statement had occurred on January 1, 2002, would have been $17.5 million at January 1, 2002 and $20.1 million at December 31, 2002.

Note 5—Long-Term Debt

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

	June 30, 2003		December 31, 2002
Credit facility	$	50,000	$	56,000
Note payable, net of unamortized discount of $713 and $863, respectively		30,537		30,387

Total debt		80,537		86,387
Less current maturities		—		(6,000	)

Total long-term debt	$	80,537	$	80,387

At June 30, 2003, 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 credit facility is limited to the loan value, as determined by the bank, of oil and gas properties pledged under the facility. 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%. The amount available for borrowings under the $100.0 million credit facility was $50.0 million, all of which was outstanding.

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 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, (3) maintaining certain financial ratios and (4) limitations on advances to our foreign subsidiaries. The debt has been classified in accordance with the terms of the amendment described below.

On August 13, 2003, we entered into a material modification of the current credit facility in the form of an amendment, whereby the current lenders were replaced and the terms were modified. Under the amended agreement, the borrowing base was redetermined and was established at $110.0 million. The borrowing base reduction amount was re-established at zero until the next redetermination in October 2003. The material modification to the credit facility also increased the term of the facility which now matures in August 2007. If our outstanding balance exceeds our borrowing base at any time, we are required to repay such excess immediately.

Advances under the amended credit facility bear interest at the base rate plus a margin of 1.0% to 8.0%, depending on the amount outstanding. The amended 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 properties, (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) a limitation of $7.5 million on future advances to our foreign subsidiaries.

In addition, the terms of the amended agreement require us to maintain certain covenants including:

•

a current ratio of 1.0 to 1.0, as defined in the agreement;

•

a consolidated and domestic debt coverage ratio which is not greater than 2.5 to 1.0 beginning September 30, 2003 through December 31, 2003 and 2.0 to 1.0 thereafter;

•

a consolidated and domestic interest coverage ratio which is not less than 3.0 to 1.0; and

•

the requirement to maintain hedges on no less than 40% and no more than 80% of the next twelve months of forecasted production attributable to our proved producing reserves.

In June 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 2003. On August 12, 2003, we entered into an amendment with the purchaser to remove the requirement of a positive working capital position at June 30, 2003. 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. As of June 30, 2003, all of our borrowing base under the agreement was outstanding. On August 14, 2003 and in connection with the execution of our amended credit agreement, we paid $36.1 million to the holder of the note payable to settle all outstanding obligations under the note agreement. Those obligations included principal, accrued interest and early repayment premiums. This payment was funded from proceeds of the amended credit agreement and will result in a loss on early extinguishment of debt of approximately $2.7 million, which will be recorded in the third quarter of 2003.

As of June 30, 2003, we had a negative working capital under both our credit agreement and note payable agreement, as such term is defined in such agreements. The material modification to our credit facility executed on August 13, 2003 waived any then-existing events of default, increased our borrowing base from $50.0 million to $110.0 million and has allowed us to re-finance the $50.0 million obligation that was outstanding on the credit facility at June 30, 2003. The amendment to the note payable executed on August 12, 2003, which removed the requirement for a specific minimum working capital as of June 30, 2003, eliminated the non-compliance with the working capital covenant under the note payable agreement that existed as of such date. We expect that we will be in compliance with the financial covenants under our amended credit facility for the next twelve months.

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 loss per share is computed based on the following information (in thousands, except per share amounts):

	Three Months Ended June 30,				Six Months Ended June 30,
	2003		2002		2003		2002
Net income (loss)	$	431	$	3,171	$	2,829	$	(3,192	)

Weighted average shares outstanding—basic		22,481		20,314		21,413		20,314
Effect of dilutive securities—stock options		103		142		145		—

Weighted average shares outstanding—diluted		22,584		20,456		21,558		20,314

Net income (loss) per share—basic and diluted	$	0.02	$	0.16	$	0.13	$	(0.16	)

Note 7—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. 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 occasionally use derivative instruments with respect to a portion of our oil and gas production to manage our exposure to price volatility. These instruments may take the form of futures contracts, swaps or options.

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.

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 sheet. Changes in fair value, to the extent the hedge is effective, are recognized in other comprehensive income (loss) 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. 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 other income (expense) in the current period.

At June 30, 2003, $0.2 million (approximately $0.1 million after tax) was recorded to accumulated other comprehensive loss for the effective portion of the change in fair market during the first half of 2003. All of this deferred loss will be reversed during the next six months as the forecasted transactions actually occur; therefore, all forecasted transactions currently being hedged are expected to occur by December 2003. As of June 30, 2003, the fair value of the outstanding derivative instruments was a current liability of $6.4 million. This amount represents the difference between contract prices and projected future market prices on contracted volumes of the commodities as of June 30, 2003.

As of June 30, 2003, we had derivative contracts (swaps) in place for the following natural gas and oil volumes:

Period	Volumes	Average Price
Natural gas (MMBtu):
2003	2,460,000	$	3.02
Oil (Bbl):
2003	92,000		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. As of June 30, 2003, we had fixed-price contracts in place for the following natural gas and oil volumes:

Period	Volumes	Average Fixed Price (1)
Natural gas (MMBtu):
2003	3,001,000	$	3.86
2004	5,060,000		4.52
Oil (Bbl):
2003	92,000		24.90

The following table summarizes all derivative instruments and fixed-price contracts as of June 30, 2003:

Period	Volumes	Average Price (1)
Natural gas (MMBtu):
2003	5,461,000	$	3.48
2004	5,060,000		4.52
Oil (Bbl):
2003	184,000		24.50

(1)

Includes the effect of basis differentials.

Additionally, in the first quarter of 2003, we entered into a costless collar arrangement for 300,000 MMBtu of our natural gas production for the months of January through March 2004 with a floor of $4.40 per MMBtu and a ceiling of $5.80 MMBtu. Collar arrangements are put and call options used to establish floor and ceiling commodity prices for a fixed volume of production during a certain time period. They provide for payments to counterparties if the index price exceeds the ceiling and payments from the counterparties if the index price is below the floor.

Note 8—Issuance of Common Stock

On May 14, 2003, we completed a private placement of four million shares of common stock to accredited investors for a total consideration of $11.8 million. We paid a fee of 6.0% of the gross proceeds from the sale of the stock to our placement agent and incurred other expenses of approximately $0.2 million in the transaction, resulting in net proceeds of approximately $10.9 million. On June 11, 2003, our registration statement on Form S-3 relating to the resale of these shares became effective.

Note 9—Stock Options

In the first half 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 (“IPO”) on February 5, 2001 (the “measurement date”). The total expected expense as of the measurement date was recognized in the periods in which the option vested. Each option was 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.

Note 10—Commitments and Contingencies

Contingencies

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. We had expected first production in the second quarter of this year; however, we became aware that certain of the modifications at the host platform were not completed and we encountered further delays in our efforts to commence production. During the second half of 2003, we will begin a required intervention on the well and the operator of the host platform is expected to complete the necessary modifications on the platform. First commercial production from the Helvellyn property is expected to occur during the second half of 2003 and accordingly, contingent consideration has been accrued for payment and capitalized as acquisition costs. Future development is planned on the other two properties.

Litigation

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 judge has abated the litigation, until arbitration pursuant to the underlying agreements between the sellers and ATP is completed. The arbitration was held from May 19 through May 23, 2003. Final briefs from both parties are to be filed during the third quarter of 2003 and a written decision from the arbitration panel is expected in the fourth quarter of 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 all 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. A trial is currently scheduled to take place during the two week period of November 10, 2003 through November 21, 2003. We intend to defend against these claims vigorously. It is not possible to predict with certainty whether we will incur any liability or to estimate the possible range of loss, if any, that we might incur in connection with this lawsuit.

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.

Note 11—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. Following is certain financial information regarding our segments for the three and six months ended June 30, 2003 and 2002 (in thousands):

	Three Months Ended June 30, 2003
	Gulf of Mexico		North Sea			Total
Revenues	$	18,627	$	—		$	18,627
Depreciation, depletion and amortization		6,070		25			6,095
Operating income (loss)		2,704		(744	)		1,960
Additions to oil and gas properties		13,385		5,205			18,590

	Three Months Ended June 30, 2002
	Gulf of Mexico		North Sea			Total
Revenues	$	27,742	$	—		$	27,742
Depreciation, depletion and amortization		13,005		25			13,030
Operating income (loss)		9,146		(830	)		8,316
Additions to oil and gas properties		5,726		264			5,990

Table continued on following page

	Six Months Ended June 30, 2003
	Gulf of Mexico		North Sea			Total
Revenues	$	39,107	$	—		$	39,107
Depreciation, depletion and amortization		13,805		52			13,857
Operating income (loss)		8,347		(1,352	)		6,995
Additions to oil and gas properties		31,425		9,486			40,911

	Six Months Ended June 30, 2002
	Gulf of Mexico		North Sea			Total
Revenues	$	46,352	$	—		$	46,352
Depreciation, depletion and amortization		24,840		50			24,890
Operating income (loss)		9,904		(1,331	)		8,573
Additions to oil and gas properties		11,325		368			11,693

	At June 30, 2003
	Gulf of Mexico		North Sea			Total
Identifiable assets	$	185,640	$	46,364		$	232,004

	At December 31, 2002
	Gulf of Mexico		North Sea			Total
Identifiable assets	$	144,069	$	37,986		$	182,055

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 the U.K. and Dutch Sectors of the North Sea (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 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 2002 Annual Report on Form 10-K includes a 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 June 30,						Six Months Ended June 30,
	2003			2002			2003			2002
Production:
Natural gas (MMcf)		2,632			5,552			5,566			10,028
Oil and condensate (MBbls)		322			385			665			812

Total (Mmcfe)		4,564			7,864			9,559			14,899
Revenues (in thousands):
Natural gas	$	13,113		$	18,561		$	28,429		$	29,262
Effects of risk management activities		(4,339	)		(1,305	)		(10,832	)		(28	)

Total	$	8,774		$	17,256		$	17,597		$	29,234

Table continued on following page

	Three Months Ended June 30,						Six Months Ended June 30,
	2003			2002			2003			2002
Oil and condensate	$	8,651		$	9,181		$	19,030		$	17,090
Effects of risk management activities		(218	)		(125	)		(655	)		(125	)

Total	$	8,443		$	9,056		$	18,375		$	16,965

Natural gas, oil and condensate	$	21,764		$	27,742		$	47,459		$	46,352
Effects of risk management activities		(4,557	)		(1,430	)		(11,487	)		(153	)

Total	$	17,207		$	26,312		$	35,972		$	46,199


Average sales price per unit:
Natural gas (per Mcf)	$	4.98		$	3.34		$	5.11		$	2.92
Effects of risk management activities (per Mcf)		(1.65	)		(0.24	)		(1.95	)		—

Total	$	3.33		$	3.10		$	3.16		$	2.92

Oil and condensate (per Bbl)	$	26.87		$	23.83		$	28.60		$	21.05
Effects of risk management activities (per Bbl)		(0.68	)		(0.32	)		(0.98	)		(0.15	)

Total	$	26.19		$	23.51		$	27.62		$	20.90

Natural gas, oil and condensate (per Mcfe)	$	4.77		$	3.53		$	4.97		$	3.11
Effects of risk management activities (per Mcfe)		(1.00	)		(0.18	)		(1.20	)		(0.01	)

Total	$	3.77		$	3.35		$	3.77		$	3.10

Expenses (per Mcfe):
Lease operating expense	$	0.81		$	0.45		$	0.77		$	0.49
General and administrative		0.73			0.33			0.69			0.34
Depreciation, depletion and amortization		1.34			1.66			1.45			1.67

Three Months Ended June 30, 2003 Compared with Three Months Ended June 30, 2002

For the three months ended June 30, 2003, we reported net income of $0.4 million, or $0.02 per share on total revenue of $18.6 million, as compared with net income of $3.2 million, or $0.16 per share on total revenue of $27.7 million in the second quarter of 2002.

Oil and Gas Revenue. Excluding the effects of settled derivatives, revenue from natural gas and oil production for the second quarter of 2003 decreased approximately 22% from the same period in 2002 from $27.7 million to $21.8 million. The decrease was primarily due to an approximate 42% decrease in production volumes from 7.9 Bcfe to 4.6 Bcfe as a result of adverse weather conditions and repairs on pipelines and host platform facilities. The decrease was partially offset by an increase in our sales price per Mcfe from $3.53 in 2002 to $4.77 in 2003.

Lease Operating Expense. Lease operating expenses for the second quarter of 2003 increased to $3.7 million ($0.81 per Mcfe) from $3.5 million ($0.45 per Mcfe) in the second quarter of 2002. The increase per Mcfe was attributable to the effect of fixed costs on those properties with lower production rates in the second quarter of 2003 than the second quarter of 2002.

General and Administrative Expense. General and administrative expense increased to $3.4 million for the second quarter of 2003 compared to $2.6 million for the same period in 2002. The primary reason for the increase was the result of higher compensation related costs and professional fees and bank charges connected with financing arrangements.

Non-Cash Compensation Expense. In the second quarter of 2002, we recorded a non-cash charge to compensation expense of approximately $0.2 million for options granted since September 1999 through the date of our initial public offering (“IPO”) on February 5, 2001 (the “measurement date”). The total expected expense as of the measurement date was recognized in the periods in which the option vested. Each option was 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. There was no corresponding expense in the second quarter of 2003.

Depreciation, Depletion and Amortization Expense. Depreciation, depletion and amortization expense decreased from the second quarter 2002 amount of $13.0 million to the second quarter 2003 amount of $6.1 million. The average DD&A rate was $1.34 per Mcfe in the second quarter of 2003 compared to $1.66 per Mcfe in the same quarter of 2002. This decrease was due primarily to upward reserve revisions on several of our significant properties.

Other Income (Expense). In the second quarter of 2003, we recorded an unrealized loss of $0.1 million on a costless collar which does not qualify for hedge accounting treatment. In the second quarter of 2002, we recorded a net loss on derivative instruments of $0.9 million. The net loss in 2002 is comprised of a realized gain of $1.4 million for derivative contracts settled in the quarter and an unrealized gain of $0.5 million representing the change in fair market value of the open derivative positions at June 30, 2002.

In the fourth quarter of 2002, we filed an insurance claim covering the estimated damages and lost production from the Gulf of Mexico region resulting from the effects of Hurricane Lili in October 2002. At December 31, 2002, we recorded amounts recoverable, net of deductibles, of approximately $1.5 million for damages to ten properties and lost production on four properties through December 31, 2002. In the second quarter of 2003, we recorded $1.0 million related to losses incurred. As of August 13, 2003 we had received two proofs of claim from the insurance underwriters totaling $3.3 million, of which $1.1 million has been received. Of the $3.3 million claim, $1.5 million was recognized during the fourth quarter of 2002 and $1.0 million was recognized during the second quarter of 2003. We will record the balance, which represents proceeds in excess of costs incurred, in the third quarter of 2003.

Interest expense decreased to $2.3 million in the second quarter of 2003 from $2.6 million in the comparable quarter of 2002 primarily due to lower borrowing levels and lower interest rates.

Six Months Ended June 30, 2003 Compared with Six Months Ended June 30, 2002

For the six months ended June 30, 2003, we reported a net income of $2.8 million, or $0.13 per share, on total revenue of $39.1 million, as compared with a net loss of $3.2 million, or $0.16 per share, on total revenue of $46.4 million in the first half of 2002.

Oil and Gas Revenue. Excluding the effects of settled derivatives, revenue from natural gas and oil production for the first half of 2003 was $47.5 million as compared to $46.4 million for the same period in 2002. The increase was due to an increase in our sales price per Mcfe from $3.10 in 2002 to $4.97 in 2003. This increase was substantially offset by an approximate 36% decrease in production volumes from 14.9 Bcfe to 9.6 Bcfe as a result of adverse weather conditions and repairs on pipelines and host platform facilities.

Lease Operating Expense. Lease operating expenses for the first half of 2003 increased on a per Mcfe basis from $0.49 per Mcfe in the first half of 2002 to $0.77 per Mcfe in the first half of 2003. The increase per Mcfe was attributable to the effect of fixed costs on those properties which produced less in the first half of 2003 than the first half of 2002.

General and Administrative Expense. General and administrative expense increased to $6.6 million for the first half of 2003 compared to $5.0 million for the same period in 2002. The increase was primarily due to higher compensation related costs and professional fees.

Non-Cash Compensation Expense. In the first half 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 (“IPO”) on February 5, 2001 (the “measurement date”). The total expected expense as of the measurement date was recognized in the periods in which the option vested. Each option was 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 from the first half 2002 amount of $24.9 million to the first half 2003 amount of $13.9 million. The average DD&A rate was $1.45 per Mcfe in the first half of 2003 compared to $1.67 per Mcfe in the same half of 2002. This decrease was due primarily to upward reserve revisions on several of our significant properties.

Other Income (Expense). In the first half of 2003, we recorded an unrealized loss of $0.2 million on a costless collar which does not qualify for hedge accounting treatment. In the first half of 2002, we recorded a loss on derivative instruments of $8.3 million. The net loss in 2002 is comprised of a realized loss of $0.1 million for derivative contracts settled in the period 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 fourth quarter of 2002, we filed an insurance claim covering the estimated damages and lost production from the Gulf of Mexico region resulting from the effects of Hurricane Lili in October 2002. At December 31, 2002, we recorded amounts recoverable, net of deductibles, of approximately $1.5 million for damages to ten properties and lost production on four properties through December 31, 2002. In the second quarter of 2003, we recorded $1.0 million related to losses incurred. As of August 13, 2003 we had received two proofs of claim from the insurance underwriters totaling $3.3 million, of which $1.1 million has been received. Of the $3.3 million claim, $1.5 million was recognized during the fourth quarter of 2002 and $1.0 million was recognized during the first half of 2003. We will record the balance, which represents proceeds in excess of costs incurred, in the second half of 2003.

Interest expense decreased to $4.7 million in the first half of 2003 from $5.3 million in the comparable half of 2002 primarily due to lower borrowing levels and lower interest rates.

Liquidity and Capital Resources

We have financed our acquisition and development activities through a combination of project-based development arrangements, bank borrowings, proceeds from our equity offerings, 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, proceeds from our recent equity offering, borrowings under our amended credit facility 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, our recent equity offering and an increased borrowing base 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.

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 the institution of a 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 to do 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

	Six Months Ended, June 30,
	2003			2002
	(in thousands)
Cash provided by (used in)
Operating activities	$	34,445		$	22,353
Investing activities		(41,024	)		(11,788	)
Financing activities		5,171			(10,156	)

Cash provided by operating activities in the first half of 2003 and 2002 was $34.4 million and $22.4 million, respectively. Cash flow from operations increased primarily due to the increase in oil and gas prices from the first half of 2002, somewhat offset by the 36% decrease in production.

Cash used in investing activities in the first half of 2003 and 2002 was $41.0 million and $11.8 million, respectively. We incurred no costs during the first half of 2003 for the Dutch Sector – North Sea acquisition. Developmental capital expenditures in the Gulf of Mexico and North Sea were approximately $31.4 million and $9.5 million, respectively, during the first half of 2003. In the first half of 2002, total developmental expenditures of $11.7 million related to the Gulf of Mexico.

Cash provided by financing activities was the result of a private placement of four million shares of common stock to accredited investors for a total consideration of $11.8 million ($10.9 million net of placement fees and other expenses). We also made principal payments of $6.0 million and $10.0 million on our credit facility during the first half of 2003 and 2002, respectively.

Credit Facilities

(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, (3) maintaining certain financial ratios and (4) limitations on advances to our foreign subsidiaries. The debt has been classified in accordance with the terms of the amendment described below.

In addition, the terms of the amended agreement require us to maintain certain covenants including:

•

a current ratio of 1.0 to 1.0, as defined in the agreement;

•

a consolidated and domestic debt coverage ratio which is not greater than 2.5 to 1.0 beginning September 30, 2003 through December 31, 2003 and 2.0 to 1.0 thereafter;

•

a consolidated and domestic interest coverage ratio which is not less than 3.0 to 1.0; and

•

the requirement to maintain hedges on no less than 40% and no more than 80% of the next twelve months of forecasted production attributable to our proved producing reserves.

Note Payable

Working Capital

At June 30, 2003, we had a working capital deficit of approximately $22.4 million. In compliance with the definition of working capital in our credit facility, which excludes current maturities of long-term debt, the current portion of assets and liabilities from derivatives and the current portion of asset retirement obligations, we had a working capital deficit of approximately $11.9 million at June 30, 2003. In accordance with the definition of working capital under our note payable agreement, we had a working capital deficit of $17.5 million. This calculation excludes current maturities of long-term debt and the current portion of assets and liabilities from derivatives. We believe the cash flows from operating activities, our recent equity offering and our amended $110.0 million senior secured credit facility 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 and comply with our debt covenant requirements in future periods.

Our 2003 planned development and acquisition programs are projected to be substantially funded by available cash flow from our 2003 operations and our amended credit facility. In addition to these measures, we are continually in discussions with other potential investors to provide additional capital. These discussions will generally involve the sale of interests in selected properties. Completion of these potential transactions would expand our capabilities to further reduce our outstanding indebtedness, improve our working capital position and may allow us to expand or accelerate our 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 2 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 2003.) 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 June 30, 2003 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	$	1,331	$	(1,331	)
Oil swaps		272		(272	)
Natural gas fixed price contracts		4,306		(4,306	)
Oil fixed price contracts		272		(272	)

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. 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.

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

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 2002 Form 10-K.

PART II. OTHER INFORMATION

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

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

The following items were presented for approval to stockholders of record on April 11, 2003 at the Company’s annual meeting of stockholders which was held on May 28, 2003 in Houston, Texas:

(i)	Election of Directors:

		For	Against	Abstained or Withheld
	Arthur H. Dilly	17,690,870	—	138,500
	Robert C. Thomas	17,690,870	—	138,500

(ii)	Ratification of KPMG LLP, independent certified public accountants, as auditors of the Company’s financial statements for 2003.	17,820,120	5,950	3,300

Of the 24,350,753 shares of common stock outstanding on May 28, 2003, 17,829,378 were voted.

All matters received the required number of votes for approval.

Item 6—Exhibits and Reports on Form 8-K

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.

Reports on Form 8-K

On May 15, 2003, the Company furnished Form 8-K, pursuant to Item 12, Results of Operations, under Item 9, Regulation FD Disclosure (in accordance with the interim filing guidance for these items), a press release announcing its earnings results for the first quarter of fiscal year 2003.

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: August 14, 2003

/s/ Albert L. Reese, Jr.

Albert L. Reese, Jr.

Senior Vice President and Chief

Financial Officer