Atp Oil & Gas 10Q 2003 Q3 Quarterly report

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, 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 November 13, 2003, was 24,505,356.

ATP OIL & GAS CORPORATION

TABLE OF CONTENTS

		Page

PART I.	FINANCIAL INFORMATION

ITEM 1.	FINANCIAL STATEMENTS

	Consolidated Balance Sheets: September 30, 2003 (unaudited) and December 31, 2002	3

	Consolidated Statements of Operations: For the three and nine months ended September 30, 2003 and 2002 (unaudited)	4

	Consolidated Statements of Cash Flows: For the nine months ended September 30, 2003 and 2002 (unaudited)	5

	Consolidated Statements of Comprehensive Income (Loss): For the three and nine months ended September 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)

	September 30, 2003			December 31, 2002
	(unaudited)
Assets
Current assets
Cash and cash equivalents	$	3,905		$	6,944
Restricted cash		—			414
Accounts receivable (net of allowance of $1,266)		29,328			24,998
Deferred tax asset		207			1,628
Other current assets		4,657			3,245

Total current assets		38,097			37,229

Oil and gas properties (using the successful efforts method of accounting)		425,726			355,088
Less: Accumulated depletion, impairment and amortization		(252,670	)		(236,052	)

Oil and gas properties, net		173,056			119,036

Furniture and fixtures (net of accumulated depreciation)		656			810
Deferred tax asset (net of allowance of $5,248 at September 30, 2003)		20,057			21,580
Other assets, net		3,961			3,400

Total assets	$	235,827		$	182,055

Liabilities and Shareholders’ Equity
Current liabilities
Accounts payable and accruals	$	54,564		$	35,336
Current maturities of long-term debt		—			6,000
Asset retirement obligation		5,706			—
Derivative liability		1,115			9,592

Total current liabilities		61,385			50,928
Long-term debt		99,894			80,387
Asset retirement obligation		17,892			—
Deferred revenue		973			1,111
Other long-term liabilities and deferred obligations		14,289			11,082

Total liabilities		194,433			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; 24,581,196 issued and 24,505,356 outstanding at September 30, 2003; 20,398,007 issued and 20,322,167 outstanding at December 31, 2002		25			20
Additional paid in capital		92,223			81,087
Accumulated deficit		(51,479	)		(39,314	)
Accumulated other comprehensive income (loss)		1,536			(2,335	)
Treasury stock		(911	)		(911	)

Total shareholders’ equity		41,394			38,547

Total liabilities and shareholders’ equity	$	235,827		$	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 September 30,						Nine Months Ended September 30,
	2003			2002			2003			2002
Oil and gas revenues	$	17,179		$	23,207		$	56,160		$	61,329

Costs and operating expenses:
Lease operating expenses		5,390			4,908			12,719			12,265
Geological and geophysical expenses		161			141			461			152
General and administrative expenses		2,810			2,614			9,373			7,648
Non-cash compensation expense (general and administrative)		—			(34	)		(39	)		453
Depreciation, depletion and amortization		6,377			10,356			20,234			35,246
Impairment of oil and gas properties		10,645			—			10,645			—
Accretion expense		638			—			2,085			—
Loss on abandonment		1,754			—			4,409			—

Total costs and operating expenses		27,775			17,985			59,887			55,764

Income (loss) from operations		(10,596	)		5,222			(3,727	)		5,565

Other income (expense):
Interest income		12			12			46			38
Interest expense		(2,219	)		(2,673	)		(6,872	)		(7,953	)
Loss on extinguishment of debt		(3,352	)		—			(3,352	)		—
Other		1,161			—			2,245			—

Total other income (expense)		(4,398	)		(2,661	)		(7,933	)		(7,915	)

Income (loss) before income taxes and cumulative effect of change in accounting principle		(14,994	)		2,561			(11,660	)		(2,350	)
Income tax benefit (expense)		—			(896	)		(1,167	)		823

Income (loss) before cumulative effect of change in accounting principle		(14,994	)		1,665			(12,827	)		(1,527	)
Cumulative effect of change in accounting principle, net of tax		—			—			662			—

Net income (loss)	$	(14,994	)	$	1,665		$	(12,165	)	$	(1,527	)

Basic and diluted income (loss) per common share:
Income (loss) before cumulative effect of change in accounting principle	$	(0.61	)	$	0.08		$	(0.57	)	$	(0.08	)
Cumulative effect of change in accounting principle, net of tax		—			—			0.03			—

Net income (loss) per common share	$	(0.61	)	$	0.08		$	(0.54	)	$	(0.08	)

Weighted average number of common shares:
Basic		24,503			20,316			22,454			20,315

Diluted		24,503			20,432			22,454			20,315

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,
	2003			2002
Cash flows from operating activities
Net loss	$	(12,165	)	$	(1,527	)
Adjustments to reconcile net loss to net cash provided by operating activities –
Depreciation, depletion and amortization		20,234			35,246
Impairment of oil and gas properties		10,645			—
Accretion of discount in asset retirement obligation		2,085			—
Amortization of deferred financing costs		917			1,110
Loss on extinguishment of debt		883			—
Other comprehensive income (loss)		2,639			(1,845	)
Deferred income taxes		1,167			(861	)
Non-cash compensation expense		(39	)		453
Cumulative effect of change in accounting principle		(662	)		—
Other non-cash items		2,404			454
Changes in assets and liabilities –
Accounts receivable and other		(5,742	)		(16,403	)
Restricted cash		414			(1,609	)
Net (assets) liabilities from derivatives		(7,056	)		8,861
Accounts payable and accruals		15,784			(921	)
Other long-term assets		738			(2,570	)
Other long-term liabilities and deferred credits		3,069			10,293

Net cash provided by operating activities		35,315			30,681

Cash flows from investing activities
Additions to oil and gas properties		(58,671	)		(17,744	)
Additions to furniture and fixtures		(149	)		(250	)

Net cash used in investing activities		(58,820	)		(17,994	)

Cash flows from financing activities
Proceeds from issuance of common stock, net		10,879			—
Proceeds from long-term debt		98,918			1,000
Payments of long-term debt		(86,580	)		(13,000	)
Deferred financing costs		(3,052	)		(492	)
Other		301			5

Net cash provided by (used in) financing activities		20,466			(12,487	)

Increase (decrease) in cash and cash equivalents		(3,039	)		200
Cash and cash equivalents, beginning of period		6,944			5,294

Cash and cash equivalents, end of period	$	3,905		$	5,494

Supplemental disclosures of cash flow information:
Cash paid during the period for interest	$	3,187		$	5,666

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 September 30,						Nine Months Ended September 30,
	2003			2002			2003			2002
Net income (loss)	$	(14,994	)	$	1,665		$	(12,165	)	$	(1,527	)

Other comprehensive income (loss):
Reclassification adjustment for settled contracts, net of tax		7			—			181			—
Change in fair value of outstanding hedge positions, net of tax		2,498			(1,845	)		2,458			(1,845	)
Foreign currency translation adjustment		467			476			1,232			451

Other comprehensive income (loss)		2,972			(1,369	)		3,871			(1,394	)

Comprehensive income (loss)	$	(12,022	)	$	296		$	(8,294	)	$	(2,921	)

See accompanying notes to consolidated financial statements.

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Note 1 — Organization

ATP Oil & Gas Corporation (“ATP”), a Texas corporation, was formed on August 8, 1991 and is engaged in the acquisition, development and production of 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.

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 nine months ended September 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 — Liquidity

At September 30, 2003, we had a working capital deficit of approximately $23.3 million. In compliance with the definition of working capital in our credit facility, we had a working capital deficit of approximately $6.6 million at September 30, 2003 resulting in non-compliance with the current ratio covenant. This definition excludes current maturities of long-term debt, the current portion of assets and liabilities from derivatives and the current portion of asset retirement obligations and includes availability under the borrowing base. Effective November 17, 2003, we obtained a waiver for the non-compliance with the current ratio requirement at September 30, 2003 and entered into an amendment to the credit facility with our lenders which modified our future current ratio requirement.

In January 2003, we tested our Helvellyn well in the North Sea at flow rates in excess of 60 Mmcf per day. We had expected first production from the Helvellyn well in the second quarter of this year, but became aware that certain of the modifications at the host platform were not yet completed by the operator of the platform. During the second half of 2003, the necessary modifications on the platform were substantially completed, but we encountered further delays in our efforts to commence production. We performed an intervention in the well that found the reservoir intact, but discovered mechanical problems that prevented the well from flowing. The test performed in January 2003 did not indicate the existence of this problem. We, along with our 50% partner, decided that a sidetrack of the well, which is currently underway, would be preferable to reworking the existing well. In addition to Helvellyn, we are presently incurring significant capital expenditures on our ongoing Garden Banks 142 and Ship Shoal 358 developments in the Gulf of Mexico. Upon completion of these developments, we expect significant production increases which are currently estimated to begin in December 2003. The remaining costs to be expended through March 2004 for these three major developments are projected to be approximately $24.9 million.

In order to alleviate a projected liquidity shortfall resulting from production delays and our current development plan and to improve our financial situation, we are aggressively pursuing additional capital. On November 17, 2003 we executed an amendment to our credit facility which contains terms that will increase the borrowing base by up to $15.0 million, subject to terms mutually acceptable to both parties. Other alternatives that we are either considering or negotiating with third parties include a production payment on certain of our properties, the sale of certain interests in our properties and additional financing for the Helvellyn property in the North Sea. In the event that we are unable to obtain additional capital from one or more of these sources, we are prepared to take further necessary actions to improve our liquidity position. Those actions would include the suspension or deferral of a significant portion of our current development program.

Although there can be no assurance we will be successful in closing these transactions, we believe these transactions, combined with our current credit facility and cash flows from operating activities will enable us to meet our future obligations and to comply with debt covenant requirements of our credit agreement, as amended. However, sustained positive liquidity can only be achieved if we are able to successfully realize a significant increase in production from the ongoing developments discussed above and we successfully execute a transaction with a third party or our current lenders to provide additional capital. Our inability to execute the above and to maintain compliance with our debt covenants could materially and adversely affect our financial position, results of operations and cash flows.

Note 3 — Income Taxes

During the third quarter of 2003, we provided a valuation allowance of $5.2 million related to the deferred tax asset arising from the losses in the quarter. Such allowance was recorded as we currently do not believe it is more likely than not that the asset will be realized. We continue to believe it is more likely than not that the remaining net deferred tax asset will be realized. The results of the matters discussed in Note 2 related to efforts to improve our liquidity may have a significant impact on our ability to realize the deferred tax asset. Depending on the outcome of our efforts, we may increase or decrease the deferred tax asset valuation allowance in the fourth quarter of 2003.

Note 4 — Accounting Pronouncements

In June 2001, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 141, “Business Combinations(“SFAS 141”) which requires the use of the purchase method of accounting for business combinations initiated after June 30, 2001 and eliminates the pooling-of-interests method. In July 2001, the FASB also issued SFAS No. 142, “Goodwill and Other Intangible Assets” (“SFAS 142”) which discontinues the practice of amortizing goodwill and indefinite lived intangible assets and initiates an annual review of impairment. The new standard also requires that, at a minimum, all intangible assets be aggregated and presented as a separate line item in the balance sheet. The adoption of SFAS 141 and 142 had no impact on our financial position or results of operations. A reporting issue has arisen regarding the application of certain provisions of SFAS 141 and SFAS 142 to companies in the extractive industries, including oil and gas companies. The issue is whether SFAS 141 requires registrants to classify the costs of mineral rights associated with extracting oil and gas as intangible assets in the balance sheet, apart from other capitalized oil and gas property costs, and provide specific footnote disclosures. Historically, we have included the costs of mineral rights associated with extracting oil and gas as a component of oil and gas properties. If it is ultimately determined that SFAS 141 requires oil and gas companies to classify costs of mineral rights associated with extracting oil and gas as a separate intangible assets line item on the balance sheet, we would be required to reclassify approximately $3.0 million and $2.5 million at September 30, 2003 and December 31, 2002, respectively, out of oil and gas properties and into a separate intangible assets line item. These costs include those incurred to acquire contract based drilling and mineral use rights such as delay rentals, lease bonuses, commissions and brokerage fees, and other leasehold costs. Our cash flows and results of operations would not be affected since such intangible assets would continue to be depleted and assessed for impairment in accordance with successful efforts accounting rules, as allowed by SFAS 142. Further, we do not believe the classification of the costs of mineral rights associated with extracting oil and gas as intangible assets would have any impact on our compliance with covenants under our debt agreements.

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 $3.4 million loss from the extinguishment of debt for the nine months ended September 30, 2003 to be recorded as a component of income from continuing operations.

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 September 30,						Nine Months Ended September 30,
	2003			2002			2003			2002
Net income (loss) as reported	$	(14,994	)	$	1,665		$	(12,165	)	$	(1,527	)
Add: Stock based compensation expense included in reported net income (loss), determined under APB 25, net of related tax effects		—			(22	)		(26	)		294
Deduct: Total stock based compensation expense determined under fair value of all awards, net of related tax effects		(253	)		(650	)		(760	)		(1,950	)

Pro forma net income (loss)	$	(15,247	)	$	993		$	(12,951	)	$	(3,183	)

Earnings per share:
Basic and diluted – as reported	$	(0.61	)	$	0.08		$	(0.54	)	$	(0.08	)
Basic and diluted – pro forma	$	(0.62	)	$	0.05		$	(0.58	)	$	(0.16	)

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 upon adoption, did not have an impact on our financial position or results of operations.

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 was effective for financial instruments entered into or modified after May 31, 2003, and was adopted on July 1, 2003. As we have no such instruments, the adoption of this statement did not have an impact on our statement of financial position or results of operations.

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.

Note 5 — Acquisition

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 commercial production is not achieved at the expiration of such time. At September 30, 2003, this obligation is reflected as a long-term liability in the financial statements.

Note 6 — 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 (using a 12.5% discount rate) 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 September 30, 2003 is as follows (in thousands):

	Period Ending September 30, 2003
	Three Months			Nine Months
Asset retirement obligation, beginning of period	$	22,154		$	—
Liabilities upon adoption of SFAS 143 on January 1, 2003		—			23,135
Liabilities incurred		861			1,392
Liabilities settled		(1,809	)		(7,423	)
Accretion expense		638			2,085
Loss on abandonment		1,754			4,409

Asset retirement obligation, as of September 30, 2003	$	23,598		$	23,598

During the nine months ending September 30, 2003, we recognized a loss on abandonment of $4.4 million due to actual costs exceeding the original estimates on two properties. These unforeseen overruns were a result of 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 nine months ended September 30, 2002 as if SFAS 143 had been adopted on January 1, 2002 (in thousands, except per share amounts):

	Period Ending September 30, 2002
	Three Months		Nine Months
Net income (loss)	$	1,488	$	(1,816	)
Net income (loss) per share – basic and diluted	$	0.07	$	(0.09	)

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 7 — Long-Term Debt

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

	September 30, 2003		December 31, 2002
Credit facility	$	99,894	$	56,000
Note payable, net of unamortized discount of $863		—		30,387

Total debt		99,894		86,387
Less current maturities		—		(6,000	)

Total long-term debt	$	99,894	$	80,387

On August 13, 2003, we entered into a material modification of the prior credit facility in the form of an amendment, whereby the prior 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 material modification to the credit facility also increased the term of the facility, which now matures in August 2007. On November 17, 2003 the credit facility was amended to modify certain debt covenants and will expand the borrowing base by up to $15.0 million, subject to terms mutually acceptable to both parties, by pledging the oil and gas properties in the UK sector of the North Sea. The amended facility is now secured by all of our U.S. assets in addition to approximately two-thirds of the capital stock of our foreign subsidiaries and is still guaranteed by our wholly owned subsidiary, ATP Energy. The borrowing base is reviewed monthly and 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 $17.5 million on future advances to our foreign subsidiaries. In addition, in order to decrease borrowings outstanding at any time and reduce interest costs, we agreed to maintain a separate account whereby all domestic collections will be deposited. The daily available balance from that account will automatically be transferred to the lender to be applied against the then principal balance of the credit facility; however, this application will not result in a reduction in the borrowing base or amounts available for borrowing. Amounts required to fund our immediate working capital needs can be drawn from borrowing availability under the credit facility.

The terms of the agreement, including the amendment dated November 17, 2003, require us to maintain certain covenants including:

•

a current ratio, as defined in the agreement, of 0.35 to 1.0 through December 31, 2004 and 1.0 to 1.0 monthly thereafter;

•

a consolidated debt coverage ratio which is not greater than 2.5 to 1.0 beginning October 31, 2003 with ranges from 1.6 to 1.0 to 3.0 to 1.0 monthly through August 31, 2004 and 1.6 to 1.0 monthly thereafter;

•

a domestic debt coverage ratio which is not greater than 2.5 to 1.0 beginning October 31, 2003 with ranges from 1.9 to 1.0 to 3.0 to 1.0 monthly through January 31, 2005 and 1.9 to 1.0 monthly 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.

The amendment to our credit facility, executed on November 17, 2003, waived the September 30, 2003 non-compliance with the current ratio requirement (as defined in the agreement), minimum consolidated EBITDA requirement (as defined in the agreement) and the requirement to perfect the pledge of 65% of the stock of each foreign subsidiary by August 21, 2003. We expect that we will be in compliance with the financial covenants under our amended credit facility for the next twelve months. Costs of $1.6 million were incurred to execute the amendment in the fourth quarter of 2003.

At December 31, 2002, we had a $100.0 million senior-secured revolving credit facility which was 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 was guaranteed by our wholly owned subsidiary, ATP Energy, Inc. The amount available for borrowing under the credit facility was limited to the loan value, as determined by the bank, of oil and gas properties pledged under the facility. If our outstanding balance exceeded our borrowing base at any time, we were required to repay such excess within 30 days and our interest rate during the time an excess exists is increased by 2.00%. On August 13, 2003, this credit facility was amended to replace the lenders and the outstanding balance was repaid.

In June 2001, we issued a note payable to a purchaser for a face principal amount of $31.3 million which was to mature in June 2005 and bore interest at a fixed rate of 11.5% per annum. The note was secured by second priority liens on substantially all of our U.S. oil and gas properties and was 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. The expected repayment premium was amortized to interest expense straight-line, over the term of the note which approximated the effective interest method. The discount of $1.3 million was amortized to interest expense using the effective interest method. The resulting liability was included in other long-term liabilities on the consolidated balance sheet at December 31, 2002. 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. Upon repayment of the note payable and replacement of the prior lenders of the credit facility, we recorded a $3.4 million total loss on the extinguishment of debt for the three months ending September 30, 2003, $0.9 million of which was related to non-cash deferred financing costs.

Note 8 — 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,
	2003			2002		2003			2002
Net income (loss)	$	(14,994	)	$	1,665	$	(12,165	)	$	(1,527	)

Weighted average shares outstanding - basic		24,503			20,316		22,454			20,315
Effect of dilutive securities – stock options		—			116		—			—

Weighted average shares outstanding - diluted		24,503			20,432		22,454			20,315

Net income (loss) per share – basic and diluted	$	(0.61	)	$	0.08	$	(0.54	)	$	(0.08	)

Note 9 — 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.

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 a component of revenues in the current period. This presentation is a reclassification of prior period disclosures that segregated the mark-to-market value changes on instruments that did not qualify for hedge accounting treatment as income (loss) on derivative instruments on the statement of operations.

For the nine months ended September 30, 2003, a $4.1 million loss ($2.6 million after tax) was realized and transferred out of accumulated other comprehensive income (loss) into earnings. The fair value of the outstanding derivative instruments was a current liability of $1.1 million at September 30, 2003. This amount represents the difference between contract prices and future market prices on contracted volumes of the commodities as of September 30, 2003. All forecasted transactions currently being hedged are expected to occur by December 2003; therefore, all of the deferred loss will be reversed during the next three months as the forecasted transactions actually occur.

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

Period	Volumes	Average Price
Natural gas (MMBtu):
2003	620,000	$	3.02
Oil (Bbl):
2003	46,000		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, which we have designated as normal sales pursuant to SFAS 133, as amended. As of September 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	1,897,000	$	3.87
2004	5,060,000		4.52
Oil (Bbl):
2003	46,000		24.90

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

Period	Volumes	Average Price ⁽¹⁾
Natural gas (MMBtu):
2003	2,517,000	$	3.66
2004	5,060,000		4.52
Oil (Bbl):
2003	92,000		24.50

⁽¹⁾

Includes the effect of basis differentials.

In the fourth quarter of 2003, we entered into a fixed price delivery contract with a third party to sell 500 barrels of oil per day at $30.00 per barrel for January through May 2004. 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 10 — 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 11 — Stock Options

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 (“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 12 — 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. First commercial production from the Helvellyn property is expected to occur during the first quarter of 2004 contingent upon the successful execution of our development plan and related funding requirements. 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 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, attorneys fees and expenses. ATP continues to vigorously defend against these claims. The judge 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 were 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 week of December 8, 2003. We will continue 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 13 — 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 months and nine months ended September 30, 2003 and 2002 (in thousands):

	Three Months Ended September 30, 2003
	Gulf of Mexico			North Sea			Total
Revenues	$	17,179		$	—		$	17,179
Depreciation, depletion and amortization		6,272			105			6,377
Impairment on oil and gas properties		10,645			—			10,645
Operating loss		(9,730	)		(866	)		(10,596	)
Additions to oil and gas properties		13,740			4,020			17,760

	Three Months Ended September 30, 2002
	Gulf of Mexico		North Sea			Total
Revenues	$	23,207	$	—		$	23,207
Depreciation, depletion and amortization		10,331		25			10,356
Operating income (loss)		6,242		(1,020	)		5,222
Additions to oil and gas properties		1,324		4,727			6,051

Table continued on following page

	Nine Months Ended September 30, 2003
	Gulf of Mexico			North Sea			Total
Revenues	$	56,160		$	—		$	56,160
Depreciation, depletion and amortization		20,077			157			20,234
Impairment on oil and gas properties		10,645			—			10,645
Operating income (loss)		(1,509	)		(2,218	)		(3,727	)
Additions to oil and gas properties		45,165			13,506			58,671

	Nine Months Ended September 30, 2002
	Gulf of Mexico		North Sea			Total
Revenues	$	61,329	$	—		$	61,329
Depreciation, depletion and amortization		35,171		75			35,246
Operating income (loss)		7,772		(2,157	)		5,615
Additions to oil and gas properties		12,649		5,095			17,744

	At September 30, 2003
	Gulf of Mexico		North Sea		Total
Identifiable assets	$	189,894	$	45,993	$	235,827

	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

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.

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.

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,
	2003			2002			2003			2002
Production:
Natural gas (MMcf)		2,693			4,421			8,259			14,449
Oil and condensate (MBbls)		265			353			931			1,164

Total (Mmcfe)		4,284			6,536			13,843			21,435
Revenues (in thousands):
Natural gas	$	12,444		$	14,354		$	40,873		$	43,616
Effects of risk management activities		(3,594	)		(723	)		(14,426	)		(751	)

Total	$	8,850		$	13,631		$	26,447		$	42,865

Oil and condensate	$	7,109		$	8,654		$	26,139		$	25,744
Effects of risk management activities		(282	)		(275	)		(937	)		(400	)

Total	$	6,827		$	8,379		$	25,202		$	25,344

Natural gas, oil and condensate	$	19,553		$	23,008		$	67,012		$	69,360
Effects of risk management activities		(3,876	)		(998	)		(15,363	)		(1,151	)

Total	$	15,677		$	22,010		$	51,649		$	68,209

	Three Months Ended September 30,						Nine Months Ended September 30,
	2003			2002			2003			2002
Average sales price per unit:
Natural gas (per Mcf)	$	4.62		$	3.25		$	4.95		$	3.02
Effects of risk management activities (per Mcf)		(1.34	)		(0.16	)		(1.75	)		(0.05	)

Total	$	3.28		$	3.09		$	3.20		$	2.97

Oil and condensate (per Bbl)	$	26.80		$	24.55		$	28.09		$	22.11
Effects of risk management activities (per Bbl)		(1.06	)		(0.78	)		(1.01	)		(0.34	)

Total	$	25.74		$	23.77		$	27.08		$	21.77

Natural gas, oil and condensate (per Mcfe)	$	4.56		$	3.52		$	4.84		$	3.24
Effects of risk management activities (per Mcfe)		(0.90	)		(0.15	)		(1.11	)		(0.05	)

Total	$	3.66		$	3.37		$	3.73		$	3.19

Expenses (per Mcfe):
Lease operating expense	$	1.26		$	0.75		$	0.92		$	0.57
General and administrative		0.66			0.40			0.68			0.36
Depreciation, depletion and amortization		1.49			1.58			1.46			1.64

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

For the three months ended September 30, 2003, we reported a net loss of $15.0 million, or $0.61 per share on total revenue of $17.2 million, as compared with net income of $1.7 million, or $0.08 per share on total revenue of $23.2 million in the third quarter of 2002.

Oil and Gas Revenue. Excluding the effects of derivatives, revenue from natural gas and oil production for the third quarter of 2003 decreased approximately 15% from the same period in 2002 from $23.0 million to $19.6 million. The decrease was primarily due to an approximate 34% decrease in production volumes from 6.5 Bcfe to 4.3 Bcfe as a result of natural decline, 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 $3.52 in 2002 to $4.56 in 2003.

Lease Operating Expense. Lease operating expenses for the third quarter of 2003 increased to $5.4 million ($1.26 per Mcfe) from $4.9 million ($0.75 per Mcfe) in the third quarter of 2002. This increase per Mcfe was attributable to the aforementioned decrease in production, unscheduled workover activities on three properties and the effect of higher fixed costs on those properties with lower production rates in the third quarter of 2003 than the third quarter of 2002.

General and Administrative Expense. General and administrative expense increased to $2.8 million for the third 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 professional fees.

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. This adjustment related to 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 third quarter of 2003.

Depreciation, Depletion and Amortization Expense. Depreciation, depletion and amortization expense decreased from the third quarter 2002 amount of $10.4 million to the third quarter 2003 amount of $6.4 million as a result of lower production and a reduced DD&A rate. The average DD&A rate was $1.49 per Mcfe in the third quarter of 2003 compared to $1.58 per Mcfe in the same quarter of 2002. This decrease was due primarily to upward reserve revisions on several of our significant properties.

Impairment Expense. As of September 30, 2003, the future undiscounted cash flows were less than their individual net book value on two of our properties. As a result, we recorded impairments of $10.6 million in the third quarter of 2003. These impairments were the result of reductions in estimates of recoverable reserves. There were no impairments in the third quarter of 2002.

Other Income (Expense).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 third quarter of 2003, we recorded additional amounts receivable of $1.2 million in damages based upon the final agreed upon claim with the underwriters.

In the third quarter of 2003, we recognized a $3.4 million loss on the extinguishment of debt related to the material modification of our prior credit agreement and the repayment of our note payable. The portion of the loss attributable to the prior credit facility ($0.9 million) was related to non-cash deferred financing costs.

Interest expense decreased to $2.2 million in the third quarter of 2003 from $2.7 million in the comparable quarter of 2002 primarily due to lower borrowing levels and lower interest rates.

Income Tax Benefit (Expense). During the third quarter of 2003, we recorded an income tax benefit of $5.2 million related to our net loss (before tax) of $15.0 million. Due to the liquidity issues discussed in Note 2 to our Consolidated Financial Statements, we have provided for a valuation allowance of $5.2 million that offset the recorded income tax benefit and corresponding deferred tax asset. During the third quarter of 2002, we recorded income tax expense of $0.9 million related to our net income (before tax) of $2.6 million.

Nine Months Ended September 30, 2003 Compared with Nine Months Ended September 30, 2002

For the nine months ended September 30, 2003, we reported a net loss of $12.2 million, or $0.54 per share, on total revenue of $56.2 million, as compared with a net loss of $1.5 million, or $0.08 per share, on total revenue of $61.3 million in the first nine months of 2002.

Oil and Gas Revenue. Excluding the effects of derivatives, revenue from natural gas and oil production for the first nine months of 2003 decreased approximately 3% from the same period in 2002, from $69.4 million to $67.0 million. The decrease was primarily due to an approximate 35% decrease in production volumes from 21.4 Bcfe to 13.8 Bcfe as a result of natural decline, 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 $3.24 in 2002 to $4.84 in 2003.

Lease Operating Expense. Lease operating expenses for the first nine months of 2003 increased on a per Mcfe basis from $0.57 per Mcfe in the first nine months of 2002 to $0.92 per Mcfe in the first nine months of 2003. The increase per Mcfe was attributable to the aforementioned decrease in production, workover activities on six properties and the effect of higher fixed costs on those properties with lower production rates in the first nine months of 2003 than the first nine months of 2002.

General and Administrative Expense. General and administrative expense increased to $9.4 million for the first nine months of 2003 compared to $7.6 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 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 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 nine months 2002 amount of $35.2 million to the first nine months 2003 amount of $20.2 million as a result of lower production and a reduced DD&A rate. The average DD&A rate was $1.46 per Mcfe in the first nine months of 2003 compared to $1.64 per Mcfe in the same nine months of 2002. This decrease was due primarily to upward reserve revisions on several of our significant properties.

Impairment Expense. As of September 30, 2003, the future undiscounted cash flows were less than their individual net book value on two of our properties. As a result, we recorded impairments of $10.6 million in the first nine months of 2003. These impairments were the result of reductions in estimates of recoverable reserves. We had no impairments in the first nine months of 2002.

Other Income (Expense).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 first nine months of 2003, we recorded additional amounts receivable of $2.2 million in damages based upon the final agreed upon claim with the underwriters.

In the first nine months of 2003, we recognized a $3.4 million loss on the extinguishment of debt related to the material modification of our prior credit agreement and the repayment of our note payable. The portion of the loss attributable to the prior credit facility ($0.9 million) was related to non-cash deferred financing costs.

Interest expense decreased to $6.9 million in the first nine months of 2002 from $8.0 million in the comparable nine months of 2002 primarily due to lower borrowing levels and lower interest rates.

Income Tax Benefit (Expense). During the nine months ended September 30, 2003, we recorded income tax expense of $1.2 million. This nine months income tax expense consisted of an income tax benefit of $4.0 million related to our net loss (before tax) of $11.7 million for the period, partially offset by a valuation allowance of $5.2 million provided for during the period due to the liquidity issues discussed in Note 2 to our Consolidated Financial Statements. During the nine months ended September 30, 2002, we recorded an income tax benefit of $0.8 million related to our net loss (before tax) for the period of $2.4 million.

Liquidity and Capital Resources

General

During the third quarter of 2003, we provided a valuation allowance of $5.2 million related to the deferred tax asset arising from the losses in the quarter. Such allowance was recorded as we currently do not believe it is more likely than not that the asset will be realized. We continue to believe it is more likely than not that the remaining net deferred tax asset will be realized. The results of the matters discussed in Note 2 to our Consolidated Financial Statements related to efforts to improve our liquidity may have a significant impact on our ability to realize the deferred tax asset. Depending on the outcome of our efforts, we may increase or decrease the deferred tax asset valuation allowance in the fourth quarter of 2003.

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 as described above will provide cash in sufficient amounts to maintain planned levels of operations and capital expenditures.

Working Capital

At September 30, 2003, we had a working capital deficit of approximately $23.3 million. In compliance with the definition of working capital in our credit facility, we had a working capital deficit of approximately $6.6 million at September 30, 2003. This definition excludes current maturities of long-term debt, the current portion of assets and liabilities from derivatives and the current portion of asset retirement obligations as well as including availability under the borrowing base. In the past, we have reported deficits in working capital at the end of a period. Such working capital deficits have principally been the result of accounts payable related to ongoing development activities. Settlement of these payables is primarily funded by cash flow from operations or, if necessary, by availability on our credit facility.

Cash Flows

	Nine Months Ended, September 30,
	2003			2002
	(in thousands)
Cash provided by (used in)
Operating activities	$	35,315		$	30,681
Investing activities		(58,820	)		(17,994	)
Financing activities		20,466			(12,487	)

Cash provided by operating activities in the first nine months of 2003 and 2002 was $35.3 million and $30.7 million, respectively. Cash flow from operations increased primarily due to the change in amounts owed to third parties as a result of increased development activity in 2003 as compared to 2002.

Cash used in investing activities in the first nine months of 2003 and 2002 was $58.8 million and $18.0 million, respectively. In the first nine months of 2003, we incurred $0.5 million for two acquisitions in the Gulf of Mexico and no costs for one acquisition in the Dutch Sector of the North Sea. Developmental capital

expenditures in the Gulf of Mexico and North Sea were approximately $44.7 million and $13.5 million, respectively. In the first nine months of 2002, we incurred no costs for two acquisitions 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.

Cash provided by financing activities in 2003 included the private placement sale 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). In addition, we received net cash proceeds of $4.2 million from our prior and current credit facility. In the first nine months of 2002, we made net principal payments of $12.0 million on our prior credit facility.

Credit Facilities

The terms of the agreement, including the amendment dated November 17, 2003, require us to maintain certain covenants including:

•

a current ratio, as defined in the agreement, of 0.35 to 1.0 through December 31, 2004 and 1.0 to 1.0 monthly 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

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 9 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 September 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	$	275	$	(275	)
Oil swaps		130		(130	)
Natural gas fixed price contracts		3,392		(3,392	)
Oil fixed price contracts		130		(130	)

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

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, 4 & 5 are not applicable and have been omitted.

Item 6 – Exhibits and Reports on Form 8-K

Exhibits


10.1		Second Amended and Restated Financing Agreement dated August 13, 2003, among ATP Oil & Gas Corporation, Ableco Finance LLC, as agent, and Wells Fargo Foothill, Inc., as funding agent.

10.2		First Amendment to the Second Amended and Restated Financing Agreement dated November 17, 2003, among ATP Oil & Gas Corporation, Ableco Finance LLC, as agent, and Wells Fargo Foothill, Inc., as funding agent.

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 August 18, 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 second 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: November 19, 2003	By:	/s/ ALBERT L. REESE, JR.

		Albert L. Reese, Jr. Senior Vice President and Chief Financial Officer

Positive
Negative
Uncertain
Constraining
Legalese
Litigous
Readability	H.S. freshman Good

Atp Oil & Gas (ATPGQ) Inactive 10-Q2003 Q3 Quarterly report

Content analysis

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents