UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-Q

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

For the quarterly period ended September 30, 2008

OR

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

Commission file number: 000-32261

ATP OIL & GAS CORPORATION

(Exact name of registrant as specified in its charter)

Texas	76-0362774
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

4600 Post Oak Place, Suite 200

Houston, Texas 77027

(Address of principal executive offices)

(Zip Code)

(713) 622-3311

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes  x    No  ¨

Indicate by check mark whether the Registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer	x	Accelerated filer	¨
Non-accelerated filer	¨	Smaller reporting company	¨

Indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes  ¨    No  x

The number of shares outstanding of the issuer’s common stock, par value $0.001, as of November 3, 2008, was 35,897,830.

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

TABLE OF CONTENTS

	Page
PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS (Unaudited)
Consolidated Balance Sheets: September 30, 2008 and December 31, 2007	3
Consolidated Statements of Operations: For the three and nine months ended September 30, 2008 and 2007	4
Consolidated Statements of Cash Flows: For the nine months ended September 30, 2008 and 2007	5
Consolidated Statements of Comprehensive Income: For the three and nine months ended September 30, 2008 and 2007	6
Notes to Consolidated Financial Statements	7
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	18
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS	28
ITEM 4. CONTROLS AND PROCEDURES	30
PART II. OTHER INFORMATION	31

2

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(In Thousands, Except Share and Per Share Amounts)

(Unaudited)

	September 30,			December 31,
	2008			2007
Assets
Current assets:
Cash and cash equivalents	$	178,358		$	199,449
Restricted cash		—			13,981
Accounts receivable (net of allowance of $358 and $382, respectively)		44,460			127,891
Deferred tax asset		45,049			84,110
Derivative asset		1,409			1,286
Other current assets		12,582			15,934
Total current assets		281,858			442,651
Oil and gas properties (using the successful efforts method of accounting):
Proved properties		3,026,918			2,468,523
Unproved properties		141,001			88,415
		3,167,919			2,556,938
Less accumulated depletion, impairment and amortization		(931,092	)		(726,358	)
Oil and gas properties, net		2,236,827			1,830,580
Furniture and fixtures (net of accumulated depreciation)		589			860
Derivative asset		431			673
Deferred tax asset		19,841			—
Deferred financing costs, net		14,504			19,873
Other assets		17,741			12,496
Total assets	$	2,571,791		$	2,307,133
Liabilities and Shareholders’ Equity
Current liabilities:
Accounts payable and accruals	$	220,317		$	270,557
Current maturities of long-term debt		10,500			12,165
Asset retirement obligation		19,075			28,194
Derivative liability		32,659			11,335
Other current liabilities		14,164			23,512
Total current liabilities		296,715			345,763
Long-term debt		1,598,392			1,391,846
Asset retirement obligation		167,778			158,577
Deferred tax liability		83,814			85,256
Derivative liability		12,185			13,242
Deferred revenue		62,549			—
Other liabilities		2,582			2,583
Total liabilities		2,224,015			1,997,267
Commitments and contingencies (Note 10)
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; 35,973,670 issued and 35,897,830 outstanding at September 30, 2008; 35,808,188 issued and 35,732,348 outstanding at December 31, 2007		36			36
Additional paid-in capital		397,354			388,250
Accumulated deficit		(20,513	)		(92,061	)
Accumulated other comprehensive income (loss)		(28,190	)		14,552
Treasury stock		(911	)		(911	)
Total shareholders’ equity		347,776			309,866
Total liabilities and shareholders’ equity	$	2,571,791		$	2,307,133

See accompanying notes to consolidated financial statements.

3

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,
	2008			2007			2008			2007
Revenues:
Oil and gas production	$	118,347		$	116,738		$	536,193		$	393,640
Other revenues		—			—			897			1,598
		118,347			116,738			537,090			395,238
Costs, operating expenses and other:
Lease operating		24,723			21,152			73,111			62,326
Exploration		48			1,799			48			13,135
General and administrative		9,212			7,610			27,279			22,950
Depreciation, depletion and amortization		52,825			53,617			222,097			159,629
Impairment of oil and gas properties		—			4,028			—			9,798
Accretion of asset retirement obligation		4,211			3,039			12,792			9,019
Loss on abandonment		896			300			2,309			379
Other, net		(149	)		(1,785	)		(259	)		(1,785	)
		91,766			89,760			337,377			275,451
Income from operations		26,581			26,978			199,713			119,787
Other income (expense):
Interest income		1,079			1,329			2,951			5,947
Interest expense, net		(26,606	)		(29,717	)		(78,969	)		(87,541	)
Derivatives income (expense)		40,963			284			(9,187	)		284
Loss on debt extinguishment		—			—			(24,220	)		—
		15,436			(28,104	)		(109,425	)		(81,310	)
Income (loss) before income taxes		42,017			(1,126	)		90,288			38,477
Income tax (expense) benefit:
Current		6,710			1,566			(3,648	)		1,532
Deferred		(12,244	)		1,881			(15,092	)		(4,129	)
		(5,534	)		3,447			(18,740	)		(2,597	)
Net income	$	36,483		$	2,321		$	71,548		$	35,880
Net income per share:
Basic	$	1.03		$	0.08		$	2.02		$	1.19
Diluted	$	1.02		$	0.08		$	1.99		$	1.17
Weighted average shares outstanding:
Basic		35,452			30,118			35,441			30,060
Diluted		35,815			30,771			35,871			30,669

See accompanying notes to consolidated financial statements.

4

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In Thousands)

(Unaudited)

	Nine Months Ended September 30,
	2008			2007
Cash flows from operating activities
Net income	$	71,548		$	35,880
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		222,097			159,629
Impairment of oil and gas properties		—			9,798
Gain on disposition of assets		(160	)		—
Accretion of asset retirement obligation		12,792			9,019
Deferred income taxes		15,092			4,129
Dry hole costs		—			10,251
Stock-based compensation		9,071			5,095
Amortization of deferred revenue		(19,451	)		—
Derivatives expense		23,435			—
Loss on extinguishment of debt		15,370			—
Noncash interest expense		12,751			5,212
Other noncash items, net		1,855			1,668
Changes in assets and liabilities:
Accounts receivable and other current assets		85,947			31,339
Accounts payable and accruals		(196,999	)		(31,879	)
Other assets		—			(2,390	)
Net cash provided by operating activities		253,348			237,751
Cash flows from investing activities
Additions to oil and gas properties		(544,176	)		(636,597	)
Decrease in restricted cash		13,864			14,096
Proceeds from disposition of oil and gas properties		82,644			—
Additions to furniture and fixtures		(129	)		(296	)
Net cash used in investing activities		(447,797	)		(622,797	)
Cash flows from financing activities
Proceeds from long-term debt		1,608,750			574,500
Payments of long-term debt		(1,404,278	)		(184,552	)
Deferred financing costs		(15,523	)		(13,449	)
Payments of capital lease		—			(23,950	)
Net profits interest payments		(13,602	)		—
Exercise of stock options		33			2,004
Net cash provided by financing activities		175,380			354,553
Effect of exchange rate changes on cash and cash equivalents		(2,022	)		882
Decrease in cash and cash equivalents		(21,091	)		(29,611	)
Cash and cash equivalents, beginning of period		199,449			182,592
Cash and cash equivalents, end of period	$	178,358		$	152,981
Noncash investing and financing activities:
Change in accrued property additions		136,176			(12,419	)
Asset retirement costs capitalized under SFAS No. 143		4,313			19,659
Property acquired in exchange for a net profits interest		—			22,468

See accompanying notes to consolidated financial statements.

5

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(In Thousands)

(Unaudited)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2008			2007			2008			2007
Net income	$	36,483		$	2,321		$	71,548		$	35,880
Other comprehensive income (loss):
Reclassification adjustment for settled hedge contracts (net of taxes of $(82), $59, $(4,987) and $59, respectively)		151			75			6,002			1,712
Changes in fair value of outstanding hedge positions (net of taxes of $(8,446), $3,177, $22,711 and $3,177, respectively)		9,855			(6,727	)		(23,139	)		(8,878	)
Reclassification adjustment for de-designated hedge contracts (net of taxes of $0, $0, $(19,288) and $0, respectively)		—			—			21,258			—
Foreign currency translation adjustment		(47,227	)		8,350			(46,863	)		17,893
Other comprehensive income (loss)		(37,221	)		1,698			(42,742	)		10,727
Comprehensive income (loss)	$	(738	)	$	4,019		$	28,806		$	46,607

See accompanying notes to consolidated financial statements.

6

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 1 — Organization

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

The accompanying unaudited consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”) for interim financial information and reflect all adjustments (consisting of normal recurring adjustments) which are, in the opinion of management, necessary for a fair statement of the results of operations for the interim periods. All intercompany transactions are eliminated upon consolidation. The interim financial information and notes hereto should be read in conjunction with our 2007 Annual Report on Form 10-K. The results of operations for the quarter and nine months ended September 30, 2008 are not necessarily indicative of results to be expected for the entire year. We have reclassified certain amounts applicable to prior periods to conform to the current classifications. Such reclassifications do not affect earnings.

Note 2 — Recent Accounting Pronouncements

During the first quarter of 2008, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards (“SFAS”) No. 161, “Disclosures about Derivative Instruments and Hedging Activities – an amendment of FASB Statement No. 133.” This statement requires enhanced disclosures about an entity’s derivative and hedging activities and is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008. We expect to adopt this standard in the first quarter of 2009 and do not anticipate that it will have a material effect on our financial statements.

During the second quarter of 2008, the FASB issued SFAS No. 162, “The Hierarchy of Generally Accepted Accounting Principles.” This statement identifies a consistent framework, or hierarchy, for selecting accounting principles to be used in preparing financial statements that are presented in conformity with U.S. generally accepted accounting principles and is expected to be effective later in 2008. We do not anticipate that it will have a material effect on our financial statements.

Note 3 — Income Taxes

Income tax expense during interim periods is based on the estimated annual effective income tax rate plus any significant unusual or infrequently occurring items which are recorded in the period the specific item occurs. Our year-to-date interim effective tax rate is derived from our expectations of net income for the year, taking into consideration permanent differences. We compute income taxes using an asset and liability approach which results in the recognition of deferred tax liabilities and assets for the expected future tax consequences of temporary differences between the financial basis and the tax basis of those assets and liabilities. We recognized income tax expense of $18.7 million and $2.6 million for the nine months ended September 30, 2008 and 2007, respectively. For the three months ended September 30, 2008 and 2007 we recognized income tax expense of $5.5 million and benefit of $3.4 million, respectively. The worldwide effective tax rates for the first nine months of 2008 and 2007 were 20.8% and 6.8%, respectively. In 2007 the provision was partially offset by the release of valuation allowance on the books related to our deferred tax assets in the United States jurisdiction.

7

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 4 — Oil and Gas Properties

Acquisitions

During the first nine months of 2008, we acquired in the Gulf of Mexico a 100% working interest in Mississippi Canyon (“MC”) Block 304 and a 55% working interest in Green Canyon Blocks 299 and 300 (collectively, “Clipper”). Also during this period, we were awarded leases for 100% of the working interests in Viosca Knoll Block 863, De Soto Canyon Block 355 and Atwater Valley Blocks 19 and 62 by the U.S. Department of Interior Minerals Management Service. The total paid for these acquisitions was $1.8 million.

During the first nine months of 2007, we completed the acquisition of a 100% working interest in the northwest quarter of MC Block 755, a 25% working interest in MC Block 754, and a 10% working interest in MC Block 800. A portion of the acquisition price of MC Block 755 was financed by the seller. The financing was full recourse and initially due on December 31, 2009. However, the amount due was converted to a net profits interest at the time of initial production. As of September 30, 2008, the amount outstanding under the net profits interest was $11.2 million and was included in current liabilities on the consolidated balance sheet.

Dispositions

During the second quarter of 2008, we completed the sale of 5.76 Bcfe of proved reserves in the form of a 15% limited-term overriding royalty interest for $82.0 million. The interest is carved out of our net revenue interests in production from MC Blocks 711, 754, 755 and 800. In accordance with SFAS No. 19, “Financial Accounting and Reporting by Oil & Gas Producing Companies,” the sale is accounted for as a volumetric production payment. The net proceeds received were recorded as deferred revenue to be recognized in earnings as the production is delivered and is presented on the consolidated statements of cash flows as proceeds from disposition of oil and gas properties. The reserves associated with the interest have been removed from our proved oil and natural gas reserves.

See also Note 13-Subsequent Events.

Note 5 — Asset Retirement Obligation

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

	Nine Months Ended September 30,
	2008			2007
Asset retirement obligation at beginning of year	$	186,771		$	108,389
Liabilities incurred		2,848			21,639
Liabilities settled		(14,785	)		(9,393	)
Property dispositions		(1,104	)		—
Changes in estimates		331			—
Accretion		12,792			9,019
Total		186,853			129,654
Less current portion		19,075			15,832
Total long-term asset retirement obligation at end of period	$	167,778		$	113,822

Note 6 — Long-Term Debt

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

	September 30, 2008		December 31, 2007
Term Loans (includes unamortized discount of $38,483 as of September 30, 2008)	$	1,608,892	$	1,202,154
Subordinated Notes		—		201,857
Total		1,608,892		1,404,011
Less current maturities		10,500		12,165
Total long-term debt	$	1,598,392	$	1,391,846

8

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

We entered into new senior secured term loan facilities, effective June 27, 2008 (collectively, the “Term Loans”). Key components of the Term Loans included a tranche of $1.05 billion, maturing July 2014, and a tranche of $600.0 million (the “Asset Sale Facility”), maturing January 2011. The Term Loans were issued with an original issue discount of 2.5% and bear interest at LIBOR plus 5.25% (with a LIBOR floor of 3.25%). The $1.05 billion tranche requires a $2.63 million principal repayment per calendar quarter until September 2013, and four quarterly repayments of $249.4 million thereafter. The Asset Sale Facility is due in full at maturity and allows for prepayment at any time at par. The Term Loans are secured by substantially all of our oil and gas assets in the Gulf of Mexico and a pledge of 65% of the common stock of our wholly owned subsidiaries, ATP Oil & Gas (UK) Limited and ATP Oil and Gas (Netherlands) B.V.

We also have a $50.0 million revolving credit facility which has the same interest obligations as the Term Loans and has a final maturity of January 2014. Available borrowing capacity is reduced by outstanding letters of credit issued against the facility.

The Term Loans carry the following restrictions and covenants, among others:

• Minimum Current Ratio of 1.0 to 1.0;

• Ratio of Total Net Debt to Consolidated EBITDAX of not greater than 3.0 to 1.0 at the end of each quarter;

• Ratio of Consolidated EBITDAX to Consolidated Interest Expense of not less than 2.5 to 1.0 for any four consecutive fiscal quarters;

• Ratio of pre-tax PV-10 of our total Proved Developed Producing oil and gas reserves adjusted for current oil and gas price estimates, to Net Debt of at least 0.5 to 1.0 at June 30 and December 31 of any fiscal year;

• Ratio of pre-tax PV-10 of our Total Proved oil and gas reserves plus 50% of our pre-tax probable oil and gas reserves, both adjusted for current oil and gas price estimates, to Net Debt of at least 2.5 to 1.0 at June 30 or December 31 of any fiscal year;

• Commodity Hedging Agreements, based on forecasted production attributable to our proved producing reserves of (i) 60% of the projected PDP production from the Oil and Gas Properties of the Borrower and the Subsidiaries for the succeeding twelve calendar months on a rolling twelve calendar month basis and (ii) 40% of such projected PDP production on a rolling basis for the twelve calendar month period subsequent to the twelve calendar month period ;

• Permitted Business Investments during any fiscal year of no more than $150.0 million or 7.5% of PV-10 value of our total proved reserves;

• Requirement that at least 75% of net proceeds from all Asset Sales be applied to the Asset Sale Facility as long as any balance is outstanding on the Asset Sale Facility.

Capitalized terms in the foregoing restrictions and covenants have the meaning set forth in our credit agreement dated June 27, 2008. The combined effective interest rate under the Term Loans at September 30, 2008 was approximately 9.34% per annum.

Note 7 — Stock–Based Compensation

We recognized stock option compensation expense of approximately $0.9 million and $0.4 million for the three months ended September 30, 2008 and 2007, respectively. We recognized stock option compensation expense of approximately $2.2 million and $1.0 million for the nine months ended September 30, 2008 and 2007, respectively. The weighted average grant-date fair value of options granted during the nine months ended September 30, 2008 and 2007 was $9.96

9

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

and $14.82, respectively. The fair values of options granted during the nine months ended September 30, 2008 and 2007 were estimated at the date of grant using a Black-Scholes option-pricing model assuming no dividends and with the following weighted average assumptions for grants during the following periods:

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2008		2007		2008		2007
Weighted average volatility	41	%	36	%	41	%	36	%
Expected term (in years)	3.8		3.8		3.8		3.8
Risk-free rate	3.2	%	4.0	%	3.1	%	4.0	%

The following table sets forth a summary of option transactions for the nine month period ended September 30, 2008:

	Number of Options		Weighted Average Grant Price		Aggregate Intrinsic Value ($000) (1)		Weighted Average Remaining Contractual Life
							(in years)
Outstanding at beginning of year	800,069		$	33.83
Granted	323,600			28.56
Exercised	(2,250	)		14.05
Forfeited	(22,439	)		43.16
Outstanding at end of period	1,098,980			32.12	$	269	3.3
Vested and expected to vest	1,001,158			24.76		252	3.2
Options exercisable at end of period	296,350			24.79		186	1.8

(1) Based upon the difference between the market price of the common stock on the last trading date of the period and the option exercise price of in-the-money options.

At September 30, 2008, unrecognized compensation expense related to nonvested stock option grants totaled $4.9 million. Such unrecognized expense will be recognized as vesting occurs over the weighted average remaining vesting period of 2.8 years.

At September 30, 2008, unrecognized compensation expense related to restricted stock totaled $8.9 million. Such unrecognized expense will be recognized as vesting occurs over a weighted average period of 1.9 years. The following table sets forth the restricted stock transactions for the nine-month period ended September 30, 2008 during which we recognized $6.8 million of compensation expense:

	Number of Shares		Weighted Average Grant Date Fair Value		Aggregate Intrinsic Value ($000) (1)
Nonvested at beginning of year	305,789		$	43.79
Granted	163,232			39.87
Vested	(24,171	)		40.24
Nonvested at end of period	444,850			42.54	$	7,923

(1) Based upon the market price of the common stock on the last trading date of the period.

10

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 8 — Earnings Per Share

Basic earnings per share (“EPS”) is computed by dividing net income or loss available to common shareholders by the weighted average number of shares of common stock (other than nonvested restricted stock) outstanding during the period. Weighted average shares outstanding for diluted EPS also includes a hypothetical number of shares assuming all in-the-money options and warrants would have been exercised and vesting of restricted stock. Potential common shares are excluded from the computation of weighted average common shares outstanding when their effect is antidilutive. For the three months ended September 30, 2008 and 2007, respectively, stock-based awards for 699,000 and 25,500 average shares of common stock, were excluded from the diluted EPS calculation because their inclusion would have been antidilutive. For the nine months ended September 30, 2008 and 2007, respectively, stock-based awards for 488,000 and 294,000 average shares of common stock were excluded from the diluted EPS calculation because their inclusion would have been antidilutive.

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

	Three Months Ended September 30,				Nine months Ended September 30,
	2008		2007		2008		2007
Net income	$	36,483	$	2,321	$	71,548	$	35,880
Shares outstanding:
Weighted average shares outstanding - basic		35,452		30,118		35,441		30,060
Effect of potentially dilutive securities - stock options and warrants		251		507		289		471
Nonvested restricted stock		112		146		141		138
Weighted average shares outstanding - diluted		35,815		30,771		35,871		30,669
Net income per share:
Basic	$	1.03	$	0.08	$	2.02	$	1.19
Diluted	$	1.02	$	0.08	$	1.99	$	1.17

Note 9 — Derivative Instruments and Risk Management Activities

At September 30, 2008 and December 31, 2007, accumulated other comprehensive income included $13.2 million and $17.3 million of unrealized after-tax losses, respectively, on our cash flow hedges. In the period the forecasted hedged transactions occur, gains and losses are reclassified from accumulated other comprehensive income to the consolidated statement of operations as components of the revenue or expense items to which they relate. Hedge ineffectiveness is recorded directly to the consolidated statement of operations.

11

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

At September 30, 2008, we had financial derivative contracts in place for the following natural gas and oil volumes:

					Net Fair Value Asset (Liability)
Description	Type	Volumes	Price
			$/Unit		($000)
Oil (Bbl) – Gulf of Mexico
Remainder of 2008	Puts	625,600	$	54.67	$	12
2009	Puts	1,496,500		54.00		1,093
Remainder of 2008	Swaps	92,000		100.11		(660	)
2009	Swaps	90,000		100.11		(60	)
Natural Gas (MMBtu)
North Sea
Remainder of 2008	Swaps	690,000	$	8.47	$	(4,357	)
2009	Swaps	5,892,250		7.92		(36,365	)
2010	Swaps	450,000		8.45		(3,403	)
Gulf of Mexico
Remainder of 2008	Swaps	310,000		9.86		736

As a result of the sale of the limited-term overriding royalty interest and changes in forecasts of production, during the second quarter 2008 we determined that it was no longer probable that forecasted production would be sufficient to satisfy amounts designated under certain of our cash flow commodity-price hedges. Consequently, we have de-designated some of these instruments as hedges, which resulted in reclassification of $40.5 million of net unrealized losses ($21.2 million after tax) from accumulated other comprehensive income to derivatives expense in the consolidated statement of operations. Subsequent changes to the fair value of these instruments will be reflected as derivatives income (expense) in the consolidated statement of operations. For the quarter and nine months ended September 30, 2008, we recognized income of $41.0 million and a loss of $9.2 million, respectively in derivatives income (expense) for changes in fair value of derivatives, that are not designated as cash flow hedges. At the beginning of the third quarter, we entered into oil collar derivatives as price hedges of future-year production. However, at the end of the quarter, we elected to terminate these instruments and realized a gain of $20.0 million in derivatives income.

Settlements on all of our commodity derivative instruments are included in cash flows from operating activities in our consolidated statement of cash flows.

We also manage our exposure to oil and natural gas price risks by periodically entering into fixed-price physical forward sale contracts. These physical contracts qualified and have been designated for the normal purchase and sale exemption under SFAS No. 133, as amended, and therefore are not recorded.

12

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

At September 30, 2008, we had fixed-price physical contracts in place for the following natural gas and oil volumes:

Period	Volumes	Average Fixed Price (1)
		$/Unit
Natural gas (MMBtu)
Gulf of Mexico:
Remainder of 2008	2,745,000	$	8.48
2009	8,175,000		8.04
North Sea:
Remainder of 2008	3,680,000	$	7.64
2009	2,700,000		7.39
Oil (Bbl) – Gulf of Mexico:
Remainder of 2008	890,000	$	77.37
2009	2,736,750		76.01
2010	365,000		68.20
2011	273,000		68.20

(1) Includes the effect of basis differentials.

In January 2008, we entered into a cash flow hedge using an interest rate swap on, initially, $500.0 million of principal which locked the LIBOR portion of the interest rate on our then-outstanding first lien borrowings at 3.1% until February 15, 2010. As mentioned above, in the second quarter 2008, we refinanced the first lien borrowings and assumed different interest obligations. Accordingly, we have de-designated as a hedge the interest rate swap because we no longer expect it to be highly effective at offsetting the variability in the interest payments required under the new Term Loans. This resulted in reclassification of $49,000 of net unrealized losses ($32,000 after tax) from accumulated other comprehensive income to derivatives expense in the consolidated statement of earnings. During July 2008, we terminated the interest rate swap and received $50,000 cash consideration.

Note 10 — Commitments and Contingencies

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

In the normal course of business we occasionally purchase oil and gas properties for little or no up-front costs and instead commit to pay consideration contingent upon the successful development and operation of the properties. The contingent consideration generally includes amounts to be paid upon achieving specified operational milestones, such as first commercial production and again upon achieving designated cumulative sales volumes. At September 30, 2008 the aggregate amount of such contingent commitments was $12.0 million.

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

13

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 11 — Segment Information

The Company’s operations are focused in the Gulf of Mexico and in the North Sea. Management reviews and evaluates separately the operations of its Gulf of Mexico segment and its North Sea segment. The operations of our segments include natural gas and liquid hydrocarbon production and sales. Segment activity for the three months and nine months ended September 30, 2008 and 2007 is as follows (in thousands):

For the Three Months Ended –	Gulf of Mexico			North Sea			Total
September 30, 2008:
Revenues	$	99,996		$	18,351		$	118,347
Depreciation, depletion and amortization		30,518			22,307			52,825
Income (loss) from operations		38,072			(11,491	)		26,581
Interest income		578			501			1,079
Interest expense, net		26,606			—			26,606
Income tax (expense) benefit		(16,729	)		11,195			(5,534	)
Additions to oil and gas properties		221,809			(25,512	)		196,297
September 30, 2007:
Revenues	$	99,212		$	17,526		$	116,738
Depreciation, depletion and amortization		39,531			14,086			53,617
Impairment of oil and gas properties		4,028			—			4,028
Income (loss) from operations		28,526			(1,548	)		26,978
Interest income		723			606			1,329
Interest expense, net		29,717			—			29,717
Income tax benefit		—			3,447			3,447
Additions to oil and gas properties		144,928			65,634			210,562
For the Nine months Ended –	Gulf of Mexico			North Sea			Total
September 30, 2008:
Revenues	$	445,924		$	91,166		$	537,090
Depreciation, depletion and amortization		136,567			85,530			222,097
Income (loss) from operations		217,805			(18,092	)		199,713
Interest income		1,337			1,614			2,951
Interest expense, net		78,904			65			78,969
Income tax (expense) benefit		(50,298	)		31,558			(18,740	)
Additions to oil and gas properties		594,071			17,795			611,866
Total assets		1,963,935			607,856			2,571,791

14

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

September 30, 2007:
Revenues	$	328,596	$	66,642	$	395,238
Depreciation, depletion and amortization		123,446		36,183		159,629
Impairment of oil and gas properties		9,798		—		9,798
Income from operations		106,784		13,003		119,787
Interest income		4,240		1,707		5,947
Interest expense, net		87,541		—		87,541
Income tax expense		—		2,597		2,597
Additions to oil and gas properties		504,302		188,097		692,399
Total assets		1,303,961		585,731		1,889,692

Note 12 — Fair Value Measurements

We adopted SFAS No. 157, “Fair Value Measurements,” effective January 1, 2008 for financial assets and liabilities measured on a recurring basis. SFAS No. 157 applies to all financial assets and financial liabilities that are being measured and reported on a fair value basis. In February 2008, the FASB issued FSP No. 157-2, which delayed the effective date of SFAS No. 157 by one year for nonfinancial assets and liabilities, except those measured on a recurring basis. We will adopt SFAS No. 157 with respect to asset retirement obligations and non-recurring impairments of oil and gas properties in the first quarter of 2009. Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). SFAS No. 157 establishes a framework for measuring fair value and expands disclosure about fair value measurements. The statement requires fair value measurements be classified and disclosed in one of the following categories:

Level 1:	Measured based on unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities.
Level 2:	Measured based on quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability. This category includes those derivative instruments that we value using observable market data. Substantially all of these inputs are observable in the marketplace throughout the full term of the derivative instrument, can be derived from observable data, or supported by observable levels at which transactions are executed in the marketplace.
Level 3:	Measured based on prices or valuation models that require inputs that are both significant to the fair value measurement and less observable from objective sources (i.e., supported by little or no market activity). Our option pricing models are industry-standard and consider various inputs including forward commodity price estimates, volatility and time value of money.

Financial assets and liabilities are classified based on the lowest level input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and determines the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels. The following table summarizes, according to their inputs, financial assets and liabilities that are being measured on a fair value basis at September 30, 2008 (in thousands):

15

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Description	Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Assets (liabilities) – net:
Gas swap contracts – U.K.	$	—	$	(44,125	)
Oil and gas swap contracts – U.S.		16		—
Oil put contracts		—		1,105
Total	$	16	$	(43,020	)

The following table sets forth a reconciliation of changes in the fair value of financial assets (liabilities) valued using inputs classified as Level 3 at September 30, 2008 (in thousands):

	Gas Swap Contracts – U.K.			Oil Put Contracts		Total
Balance at beginning of year	$	(24,577	)	$	747	$	(23,830	)
Total loss included in other comprehensive income		(21,724	)		—		(21,724	)
Derivatives expense		(9,034	)		358		(8,676	)
Settlements		11,210			—		11,210
Balance at end of period	$	(44,125	)	$	1,105	$	(43,020	)
Changes in unrealized income (loss) included in earnings relating to derivatives still held at September 30, 2008	$	(7,159	)	$	372	$	(6,787	)

Note 13 — Subsequent Events

Sale of Interests in U.K. Properties

On October 23, 2008, we finalized a Sale and Purchase Agreement (the “S&P Agreement”) with EDF Production UK Limited (“EDF”) relating to the sale of 80% of our working interests in certain producing oil and gas properties, leasehold acreage and gathering infrastructures, all located in the U.K. sector of the North Sea at the Tors and Wenlock fields. The agreement provides for the acquisition to be effective as of July 1, 2008. The closing of the transaction is expected to occur by December 31, 2008, subject to customary closing conditions, including without limitation approval of the transaction by the U.K. Department of Energy and Climate Change. We currently own a 100% working interest in the Wenlock field and an 85% working interest in the Tors field.

The purchase price for these assets of £265.0 million (approximately $435.1 million as of October 23, 2008) was determined in arm’s-length negotiations and is subject to adjustment

16

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

based on each party’s share of production proceeds received and expenses paid for periods before and after July 1, 2008 and other factors. The S&P Agreement contains customary representations and warranties. Either party may terminate the agreement if the closing has not occurred by December 31, 2008.

The parties also entered into a Call Option Agreement dated October 23, 2008 pursuant to which we granted to EDF the option to acquire the remaining 20% of our working interests in the Wenlock and Tors fields. The option may be exercised at any time after the later of December 1, 2008 or the closing date of the transaction contemplated by the S&P Agreement (“the Initial Exercise Date”) and the 60th day following the Initial Exercise Date. The minimum purchase price payable by EDF to us under the Call Option Agreement is £72.4 million (approximately $118.9 million as of October 23, 2008), subject to being increased based on natural gas prices on the day before the option is exercised.

Share Repurchase Program

In October 2008, we announced a share repurchase program for up to 3,500,000 shares of common stock at any time through the end of 2011.

17

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

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

Executive Overview

General

ATP Oil & Gas Corporation is engaged in the acquisition, development and production of oil and natural gas properties in the Gulf of Mexico and the North Sea. We seek to acquire and develop properties with proved undeveloped reserves that are economically attractive to us but are not strategic to major or large exploration-oriented independent oil and gas companies. Occasionally we will acquire properties that are already producing or where previous drilling has encountered reservoirs that appear to contain commercially productive quantities of oil and gas even though the reservoirs do not meet the SEC definition of proved reserves. We may also acquire offshore lease blocks that surround our existing developments in order to expand our acreage position in the development. This expansion may add drilling opportunities, new reserves or production. We believe that our strategy of focusing on development with an occasional exposure to exploration opportunities near our existing developments provides assets for us without the risk, cost or time of traditional exploration.

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

• significant undeveloped reserves and reservoirs;

• close proximity to developed markets for oil and natural gas;

• existing infrastructure of common carrier oil and natural gas pipelines; and

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

Our focus is on acquiring properties that are noncore or nonstrategic to their original owners for a variety of reasons. For example, larger oil companies from time to time adjust their capital spending or shift their focus to exploration prospects which they believe may offer greater reserve potential. Some projects may provide lower economic returns to a company due to changes in its cost structure or other constraints within that company. Also, timing, budget constraints or changes in a company’s ownership or management structure, may render a company unwilling or unable to develop a property before the expiration of the lease. Because of our cost structure, expertise in our areas of focus and ability to develop projects, the properties may be more financially attractive to us than the seller.

We focus on developing projects in the shortest time possible between initial major investment and first revenue generated in order to maximize our rate of return. Since we operate most of the properties in which we acquire a working interest, we are able to significantly influence the development concept and timing of a project’s development. We may initiate new development projects by simultaneously obtaining the various required components such as the pipeline and the production platform or subsea well completion equipment. We believe this strategy, combined with our strong technical abilities to evaluate and implement a project’s requirements, allows us to efficiently complete the development project and commence production. To enhance the economics of a project, we sometimes develop the project to a value creation point and either sell an interest or bring in partners on a promoted basis.

18

Third Quarter 2008 Highlights

Our financial and operating performance for the third quarter of 2008 included the following highlights:

• Net income of $36.5 million or $1.03 per share;

• Record nine-month production and revenues despite the impact of hurricanes Gustav and Ike;

• Executed an agreement to sell 80% of certain assets in the U.K. North Sea for approximately $430 million, which represents significant progress toward our previously announced monetization program;

• Continued progress on our 2008 development program.

Additional discussion of our expectations for 2008 can be found in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our 2007 Annual Report on Form 10-K.

Results of Operations

Three Months Ended September 30, 2008 Compared to Three Months Ended September 30, 2007

For the three months ended September 30, 2008 and 2007 we reported net income of $36.5 million and $2.3 million, or net income of $1.02 and $0.08 per diluted share, respectively.

Oil and Gas Production Revenues

Revenues presented in the table and the discussion below represent revenues from sales of oil and natural gas production volumes. Production sold under fixed-price delivery contracts which have been designated for the normal purchase and sale exemption under Statement of Financial Accounting Standards (“SFAS”) No. 133 are also included in these amounts as well as the effects of financial cash flow price hedges. Deliveries under the fixed-price contracts are approximately 100% and 45% of our oil production for the three months ended September 30, 2008 and 2007, respectively. Approximately 92% and 46% of our natural gas production was sold under these fixed-price delivery contracts for the comparable periods. The proportion of production sold under fixed-price delivery contracts in the current quarter is so great due to the temporary impacts of hurricanes Gustav and Ike. The realized prices below may differ from the market prices in effect during the periods depending on when the fixed-price delivery contract was executed. The table also reflects oil and gas production revenues from amortization of deferred revenue related to the second quarter 2008 sale of the limited-term overriding royalty interest. We do not reflect any production associated with those revenues.

	Three Months Ended September 30,				% Change in 2008 from
	2008		2007		2007
Production:
Natural gas (MMcf)		7,267		8,021	(9	)%
Oil and condensate (MBbl)		821		887	(7	)%
Total (MMcfe)		12,190		13,343	(9	)%
Revenues from production (in thousands):
Natural gas	$	53,429	$	58,276	(8	)%

19

Effects of cash flow hedges		(230	)		(118	)
Amortization of deferred revenue		2,434			—		—
Total	$	55,633		$	58,158		(4	)%
Oil and condensate	$	53,510		$	59,046		(9	)%
Effects of cash flow hedges		(957	)		(230	)
Amortization of deferred revenue		10,161			—		—
Total	$	62,714		$	58,816		7	%
Natural gas, oil and condensate	$	106,939		$	117,322		(9	)%
Effects of cash flow hedges		(1,187	)		(348	)
Amortization of deferred revenue		12,595			—		—
Total	$	118,347		$	116,974		1	%
Average realized sales price:
Natural gas (per Mcf)	$	7.35		$	7.27		1	%
Effects of cash flow hedges (per Mcf)		(0.03	)		(0.02	)
Average realized price (per Mcf)	$	7.32		$	7.25		1	%
Oil and condensate (per Bbl)	$	65.18		$	66.56		(2	)%
Effects of cash flow hedges (per Bbl)		(1.17	)		(0.26	)
Average realized price (per Bbl)	$	64.01		$	66.30		(3	)%
Natural gas, oil and condensate (per Mcfe)	$	8.77		$	8.79		—
Effects of cash flow hedges (per Mcfe)		(0.10	)		(0.02	)
Average realized price (per Mcfe)	$	8.67		$	8.77		(1	)%

Revenues from production increased 1% in the third quarter of 2008 compared to the third quarter of 2007. During the period production decreased 9% compared to the third quarter of 2007 primarily due to the Gulf of Mexico hurricanes Gustav and Ike, partially offset by increased production from the Wenlock property in the U.K., which was brought online in the fourth quarter of 2007. Also during the period, average sales prices decreased 1% primarily due to $8.9 million paid to purchasers related to shortfalls of deliveries under fixed-price forward contracts. These decreases were virtually offset by deferred revenue recognized.

Lease Operating

Lease operating expense for the third quarter of 2008 increased to $24.7 million ($2.03 per Mcfe) from $21.2 million ($1.59 per Mcfe) in the third quarter of 2007. The increase was primarily attributable to the increased cost of chemicals and fuel. The per unit cost increased primarily due to the effect on fixed costs of the storm-related decrease in production. In third quarter 2008, lease operating expense per Mcfe in the Gulf of Mexico and the North Sea was $2.20 and $1.61, respectively. In the third quarter 2007, lease operating expense per Mcfe in the Gulf of Mexico and North Sea was $1.69 and $1.17, respectively.

20

General and Administrative

General and administrative expense for the third quarter of 2008 increased to $9.2 million from $7.6 million in the third quarter of 2007. The increase is primarily attributable to higher stock-based compensation costs and legal fees.

Depreciation, Depletion and Amortization

Depreciation, Depletion and Amortization (“DD&A”) expense decreased during the third quarter of 2008 to $52.8 million from $53.6 million for the third quarter of 2007. The decrease was due to the decreased production caused by Gulf of Mexico hurricanes Gustav and Ike noted above partially offset by an increased depletion rate. The average depletion rate increased 8% to $4.33 per Mcfe in the third quarter of 2008 compared to $4.02 per Mcfe in the third quarter of 2007. This per unit increase is primarily a result of higher costs incurred on our new developments relative to some of our older properties. The third quarter of 2008 DD&A rates for the Gulf of Mexico and North Sea were $3.51 per Mcfe and $6.38 per Mcfe, respectively. The third quarter of 2007 DD&A rates for the Gulf of Mexico and North Sea were $3.71 per Mcfe and $5.25 per Mcfe, respectively.

Impairment of Oil and Gas Properties

There have been no impairments during the third quarter of 2008. In the third quarter of 2007, we recorded an impairment of oil and gas properties totaling $4.0 million due to unfavorable operating performance on one property in the Gulf of Mexico.

Accretion of Asset Retirement Obligation

Accretion expense increased to $4.2 million in the third quarter of 2008 compared to 3.0 million in third quarter 2007 primarily due to increased asset retirement obligations associated with increased oil and gas property development and overall vendor price increases.

Loss on Abandonment

During the third quarter of 2008, we recognized an aggregate loss on abandonment of $0.9 million compared to $0.3 million in the third quarter of 2007.

Interest Expense

Interest expense decreased to $26.6 million for the third quarter of 2008 compared to $29.7 million for the third quarter of 2007 primarily due to the effect of lower interest rates on our floating-rate borrowings and $12.5 million of capitalized 2008 interest related to the construction of a floating production system at the Telemark Hub.

Derivatives Income (Expense)

Derivatives income in the third quarter of 2008 was $41.0 million (Gulf of Mexico, $27.3 million and North Sea, $13.7 million). At the beginning of the third quarter, we entered into oil collar derivatives as price hedges of future-year production. However, at the end of the quarter, we elected to terminate these instruments and realized a gain of $20.0 million in derivatives income. The balance of the derivatives income is related primarily to changes in fair value of derivatives not designated as cash flow hedges.

Income Taxes

We recorded income tax expense of $5.5 million and income tax benefit of $3.4 million during the quarter ended September 30, 2008 and 2007, respectively. The provision for each quarter results from the application of the expected annual tax rate in each jurisdiction applied to the year-to-date pre-tax income by

21

jurisdiction, and takes into account permanent differences. Our estimated year-to-date effective tax rate for 2008 is 20.8% and for 2007 is 6.8%. In 2007 the provision was partially offset by the release of valuation allowance on the books related to our deferred tax assets in the United States jurisdiction.

Nine months Ended September 30, 2008 Compared to Nine months Ended September 30, 2007

For the nine months ended September 30, 2008 and 2007 we reported net income of $71.5 million and $35.9 million, or $1.99 and $1.17 per diluted share, respectively.

Oil and Gas Production Revenues

Revenues presented in the table and the discussion below represent revenues from sales of oil and natural gas production volumes. Production sold under fixed-price delivery contracts which have been designated for the normal purchase and sale exemption under SFAS No. 133 are also included in these amounts as well as the effects of financial cash flow price hedges. Deliveries under the fixed-price contracts are approximately 91% and 35% of our oil production for the nine months ended September 30, 2008 and 2007, respectively. Approximately 85%, and 48% of our natural gas production was sold under these fixed-price delivery contracts for the comparable periods. The proportion of production sold under fixed-price delivery contracts in the current year-to-date period is so great due to the temporary impacts of hurricanes Gustav and Ike. The realized prices below may differ from the market prices in effect during the periods depending on when the fixed-price delivery contract was executed. The table also reflects oil and gas production revenues from amortization of deferred revenue related to the second quarter 2008 sale of the limited-term overriding royalty interest. We do not reflect any production associated with those revenues.

	Nine months Ended September 30,						% Change in 2008 From
	2008			2007			2007
Production:
Natural gas (MMcf)		29,080			26,271		11	%
Oil and condensate (MBbl)		3,857			2,926		32	%
Total (MMcfe)		52,219			43,830		19	%
Revenues from production (in thousands):
Natural gas	$	247,050		$	216,628		14	%
Effects of cash flow hedges		(8,689	)		917
Amortization of deferred revenue		3,843			—		—
Total	$	242,204		$	217,545		11	%
Oil and condensate	$	280,775		$	177,341		58	%
Effects of cash flow hedges		(2,394	)		(1,320	)
Amortization of deferred revenue		15,608			—		—
Total	$	293,989		$	176,021		67	%
Natural gas, oil and condensate	$	527,825		$	393,969		34	%
Effects of cash flow hedges		(11,083	)		(403	)
Amortization of deferred revenue		19,451			—		—
Total	$	536,193		$	393,566		36	%

22

Average realized sales price:
Natural gas (per Mcf)	$	8.50		$	8.25		3	%
Effects of cash flow hedges (per Mcf)		(0.30	)		0.03
Average realized price (per Mcf)	$	8.20		$	8.28		(1	)%
Oil and condensate (per Bbl)	$	72.80		$	60.60		20	%
Effects of cash flow hedges (per Bbl)		(0.62	)		(0.45	)
Average realized price (per Bbl)	$	72.18		$	60.15		20	%
Natural gas, oil and condensate (per Mcfe)	$	10.11		$	8.99		12	%
Effects of cash flow hedges (per Mcfe)		(0.21	)		(0.01	)
Average realized price (per Mcfe)	$	9.90		$	8.98		10	%

Revenues from production increased 36% in the first nine months of 2008 compared to the first nine months of 2007. During the first nine months of 2008, our production increased 19% compared to the first nine months of 2007 primarily due to greater production in the Gulf of Mexico from the Gomez Hub and due to production from the Wenlock property in the U.K., which was brought online in the fourth quarter of 2007. The increased revenues were also attributable to a 10% increase in average realized sales price.

Lease Operating

Lease operating expense for the first nine months of 2008 increased to $73.1 million ($1.40 per Mcfe) from $62.3 million ($1.42 per Mcfe) in the first nine months of 2007. The increase was primarily attributable to the production increases noted above. The per unit cost has decreased primarily due to the effect of fixed costs. In the first nine months of 2008, lease operating expense per Mcfe in the Gulf of Mexico and the North Sea was $1.41 and $1.36, respectively. In the first nine months of 2007, lease operating expense per Mcfe in the Gulf of Mexico and North Sea was $1.39 and $1.57, respectively.

General and Administrative

General and administrative expense for the first nine months of 2008 increased to $27.3 million from $23.0 million in the first nine months of 2007. The increase is primarily attributable to higher stock-based compensation costs.

Depreciation, Depletion and Amortization

DD&A expense increased during the first nine months of 2008 to $222.1 million from $159.6 million for the first nine months of 2007. The increase was due to the increased production noted above and to an increased depletion rate. The average depletion rate increased 16% to $4.25 per Mcfe in the first nine months of 2008 compared to $3.64 per Mcfe in the first nine months of 2007. This per unit increase is primarily a result of higher costs incurred on our new developments relative to some of our older properties. During the first nine months of 2008, DD&A rates for the Gulf of Mexico and North Sea were $3.53 per Mcfe and $6.33 per Mcfe, respectively. The first nine months of 2007 DD&A rates for the Gulf of Mexico and North Sea were $3.44 per Mcfe and $4.57 per Mcfe, respectively.

23

Impairment of Oil and Gas Properties

There have been no impairments during the first nine months of 2008. In the first nine months of 2007, we recorded an impairment of oil and gas properties totaling $9.8 million due to unfavorable operating performance on one property in the Gulf of Mexico.

Accretion of Asset Retirement Obligation

Accretion expense increased to $12.8 million in the first nine months of 2008 compared to 9.0 million in the first nine months of 2007 primarily due to increased asset retirement obligations associated with increased oil and gas property development and overall vendor price increases.

Loss on Abandonment

During the first nine months of 2008, we recognized an aggregate loss on abandonment of $2.3 million compared to $0.4 million in 2007 due to unanticipated vendor price increases in the Gulf of Mexico.

Interest Expense

Interest expense decreased to $79.0 million for the first nine months of 2008 compared to $87.5 million for the first nine months of 2007 primarily due to $25.5 million of capitalized 2008 interest related to the construction of a floating production system at the Telemark Hub and lower overall interest rates and their effect on our floating-rate borrowings. This decrease was partially offset by interest related to the net $200.0 million increase in outstanding borrowings under our Term Loans beginning in the second quarter of 2007.

Derivatives Income (Expense)

Derivatives expense in the first nine months of 2008 was $9.2 million (Gulf of Mexico, $11.1 million gain and North Sea, $20.3 million loss). As a result of the limited-term overriding royalty interest and changes in forecasts of production, during the second quarter 2008 we determined that it was no longer probable that forecasted production would be sufficient to satisfy amounts designated under certain of our cash flow commodity-price hedges. Consequently, we have de-designated some of these instruments as hedges. Also, we have de-designated as a hedge the interest rate swap because we no longer expect it to be highly effective at offsetting the variability in the interest payments for the new Term Loans. The total expense related to de-designation of these cash flow hedges is $40.5 million. At the beginning of the third quarter, we entered into oil collar derivatives as price hedges of future-year production. However, at the end of the quarter, we elected to terminate these instruments and realized a gain of $20.0 million in derivatives income. The balance of the derivatives expense is related primarily to changes in fair value of derivatives no longer designated as cash flow hedges.

Loss on Debt Extinguishment

Loss on debt extinguishment in the first nine months of 2008 is $24.2 million. As discussed below, during the second quarter of 2008, we refinanced the Term Loans and Subordinated Notes and recorded losses for the remaining unamortized deferred financing costs, debt discount related to the retired debt and for repayment premiums associated with the Subordinated Notes.

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Income Taxes

We recorded income tax expense of $18.7 million and $2.6 million during the nine months ended September 30, 2008 and 2007, respectively. The provision for each period results from the application of the expected annual tax rate in each jurisdiction applied to the year-to-date pre-tax income by jurisdiction, and takes into account permanent differences. Our estimated year-to-date effective tax rate for 2008 is 20.8% and for 2007 is 6.8%. In 2007 the provision was partially offset by the release of valuation allowance on the books related to our deferred tax assets in the United States jurisdiction.

Liquidity and Capital Resources

Under the Term Loans (as defined below), we have a $50.0 million revolving credit facility (“Revolver”), of which $31.0 was available as of September 30, 2008. At that date, we had a working capital deficit of approximately $14.9 million, a decrease of approximately $111.8 million from December 31, 2007. Working capital was negatively impacted by hurricanes Gustav and Ike, which has caused the deferral of production during the third quarter of 2008. Our credit agreement covenants specify a minimum liquidity ratio under which we include the availability under the Revolver, and exclude current maturities of long-term debt, the current portion of assets and liabilities from derivatives and the current portion of asset retirement obligations. We were in compliance with all of our credit agreement covenants at September 30, 2008.

Historically, we have financed our acquisition and development activities through a combination of bank borrowings, proceeds from equity offerings, cash from operations and the sale of interests in selected properties. In the second quarter of 2008, we announced plans to offer for sale partial working interests in a number of our properties, both producing and under development. In October 2008, we announced the agreement to sell 80% of our working interests in two of our U.K. fields for £265.0 million (approximately $435.1 million as of October 23, 2008, the date of the Sale and Purchase Agreement). In addition, we granted the purchaser an option to purchase our remaining interests in these fields (see Note 13-Subsequent Events). We expect the sale to close by December 31, 2008. We intend to reduce our debt by up to $600.0 million with the expected proceeds from this and other such sales. We may also use discretionary cash flow to repurchase shares of common stock in accordance with our recently announced program.

We intend to continue to finance our near-term development projects utilizing cash on hand, asset sale proceeds net of debt repayments and the other potential sources of capital mentioned above. As operator of most of our projects under development, we have the ability to significantly control the timing of most of our capital expenditures. Coupled with that control, we believe our cash flows from operating activities and capital from other sources as noted above will enable us to meet our future capital requirements.

Cash Flows

	Nine months Ended
	September 30,
	2008			2007
Cash provided by (used in) (in thousands):
Operating activities	$	253,348		$	237,751
Investing activities		(447,797	)		(622,797	)
Financing activities		175,380			354,553

Cash provided by operating activities during the first nine months of 2008 and 2007 was $253.3 million and $237.8 million, respectively. Cash flow from operations increased primarily

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due to higher oil and gas production revenues during 2008 compared to 2007. The increase in sales revenue was attributable to higher oil and gas production and higher oil and gas prices during 2008.

Cash used in investing activities was $447.8 million and $622.8 million during the first nine months of 2008 and 2007, respectively. Cash expended in the Gulf of Mexico and North Sea for additions to oil and gas properties was approximately $406.1 million and $138.1 million, respectively, in the first nine months of 2008. Cash expended in the Gulf of Mexico and North Sea for additions to oil and gas properties was approximately $166.2 million and $470.4 million, respectively, in the first nine months of 2007. During the second quarter of 2008, we completed the sale of 5.76 Bcfe of proved reserves in the form of a 15% limited-term overriding royalty interest for $82.0 million.

Cash provided by financing activities was $175.4 million and $354.6 million during first the nine months of 2008 and 2007, respectively. Payments of long-term debt for the first nine months of 2008 are primarily comprised of $1,202.2 million of repayment of borrowings under our former credit agreement and of $199.5 million related to our former subordinated notes. Proceeds from long-term debt are comprised of $1,593.4 million (net of issuance costs) of proceeds from the Term Loans. During the first nine months of 2007, financing cash flows were primarily due to the increase in our former term loans and former subordinated notes of $561.1 million (net of issuance costs), partially offset by the aggregate $208.5 million repayments of our former second lien term loans and other debt payments.

Long-term Debt

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

	September 30,		December 31,
	2008		2007
Term Loans (includes unamortized discount of $38,483 as of September 30, 2008)	$	1,608,892	$	1,202,154
Subordinated Notes		—		201,857
Total		1,608,892		1,404,011
Less current maturities		10,500		12,165
Total long-term debt	$	1,598,392	$	1,391,846

We entered into a new senior secured term loan facility, effective June 27, 2008 (collectively, the “Term Loans”). Proceeds of the Term Loans were used to refinance the $1.2 billion senior secured term loan scheduled to mature in April 2010 and $210.0 million of unsecured subordinated notes scheduled to mature in September 2011, and for general corporate purposes. Key components of the Term Loans included a tranche of $1.05 billion, maturing July 2014, and a tranche of $600.0 million (the “Asset Sale Facility”), maturing January 2011. The Term Loans were issued with an original issue discount of 2.5% and bear interest at LIBOR plus 5.25% (with a LIBOR floor of 3.25%). The $1.05 billion tranche requires a $2.63 million principal repayment per calendar quarter until September 2013, and four quarterly repayments of $249.4 million thereafter. The Asset Sale Facility is due in full at maturity and allows for prepayment at any time at par. The Term Loans are secured by substantially all of our oil and gas assets in the Gulf of Mexico and a pledge of 65% of the common stock of our wholly owned subsidiaries, ATP Oil & Gas (UK) Limited and ATP Oil and Gas (Netherlands) B.V. We have a $50.0 million revolving credit facility (of which $31.0 million was available as of September 30, 2008).

The Term Loans carry the following restrictions and covenants, among others:

• Minimum Current Ratio of 1.0 to 1.0;

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• Ratio of Total Net Debt to Consolidated EBITDAX of not greater than 3.0 to 1.0 at the end of each quarter;

• Ratio of Consolidated EBITDAX to Consolidated Interest Expense of not less than 2.5 to 1.0 for any four consecutive fiscal quarters;

• Ratio of pre-tax PV-10 of our total Proved Developed Producing oil and gas reserves adjusted for current oil and gas price estimates, to Net Debt of at least 0.5 to 1.0 at June 30 and December 31 of any fiscal year;

• Ratio of pre-tax PV-10 of our Total Proved oil and gas reserves plus 50% of our pre-tax probable oil and gas reserves, both adjusted for current oil and gas price estimates, to Net Debt of at least 2.5 to 1.0 at June 30 or December 31 of any fiscal year;

• Commodity Hedging Agreements, based on forecasted production attributable to our proved producing reserves of (i) 60% of the projected PDP production from the Oil and Gas Properties of the Borrower and the Subsidiaries for the succeeding twelve calendar months on a rolling twelve calendar month basis and (ii) 40% of such projected PDP production on a rolling basis for the twelve calendar month period subsequent to the twelve calendar month period ;

• Permitted Business Investments during any fiscal year of no more than $150.0 million or 7.5% of PV-10 value of our total proved reserves;

• Requirement that at least 75% of net proceeds from all Asset Sales be applied to the Asset Sale Facility as long as any balance is outstanding on the Asset Sale Facility.

Capitalized terms in the foregoing restrictions and covenants have the meaning set forth in the credit agreement dated June 27, 2008, which is Exhibit 10.2 to this document. We were in compliance with our credit agreement covenants at September 30, 2008.

Contractual Obligations

The following table summarizes certain contractual obligations at September 30, 2008 (in thousands):

Contractual Obligations	Total		Less than 1 year		1-3 years		3-5 years		More than 5 years
Long-term debt (1)	$	1,647,375	$	10,500	$	621,000	$	267,750	$	748,125
Interest on long-term debt (2)		586,215		139,692		242,707		171,137		32,679
Other trade commitments		280,370		121,620		158,750		—		—
Noncancelable operating leases		4,530		1,204		1,815		1,116		395
Total contractual obligations	$	2,518,490	$	273,016	$	1,024,272	$	440,003	$	781,199

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(1) Long-term debt in future periods includes amortization of discount.

(2) Interest is based on rates and principal repayments in effect at September 30, 2008.

Our liabilities also include asset retirement obligations (“ARO”) ($19.1 million current and $167.8 million long-term) that represent the amount at September 30, 2008 of our obligations with respect to the retirement/plugging and abandonment of our oil and gas properties. The ultimate settlement amounts and the timing of the settlements of such obligations are unknown because they are subject to, among other things, federal, state and local regulation, economic and operational factors. Consequently, ARO is not reflected in the table above.

Commitments and Contingencies

Management is periodically faced with uncertainties, the outcomes of which are not within its control and will not be known for a long time. We are involved in actions from time to time, which if determined adversely, could have a material negative impact on our financial position, results of operations and cash flows. Management, with the assistance of counsel makes estimates, if determinable, of ATP’s probable liabilities and records such amounts in the consolidated financial statements. Such estimates may be the minimum amount of a range of probable loss when no single best estimate is determinable. Disclosure is made, when determinable, of any additional possible amount of loss on these claims, or if such estimate cannot be made, that fact is disclosed. Along with our counsel, we monitor developments related to these legal matters and, when appropriate, we make adjustments to recorded liabilities to reflect current facts and circumstances. Although it is difficult to predict the ultimate outcome of these matters, management is not aware of any amounts that need to be recorded and believes that the recorded amounts, if any, are reasonable. See Note 10 to the consolidated financial statements for additional discussion of commitments and contingencies.

Accounting Pronouncements

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

Critical Accounting Policies

Our discussion and analysis of our financial condition and results of operations are based on consolidated financial statements which have been prepared in accordance with generally accepted accounting principles in the United States. The preparation of these financial statements requires us to make estimates and judgments that affect the reported amounts or assets, liabilities, revenues and expenses. We believe that certain accounting policies affect our more significant judgments and estimates used in the preparation of our consolidated financial statements. Our 2007 Annual Report on Form 10-K includes a discussion of our critical accounting policies.

Item 3. Quantitative and Qualitative Disclosures about Market Risks

Interest Rate Risk

We are exposed to changes in interest rates on our Term Loans in Management’s Discussion and Analysis of Financial Condition and Results of Operations: Liquidity and Capital Resources, and on the earnings from cash and cash equivalents. See the discussion of our Term Loans in Note 6 to the consolidated financial statements.

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Foreign Currency Risk

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

Commodity Price Risk

Our revenues, profitability and future growth depend substantially on prevailing prices for oil and natural gas. Prices also affect the amount of cash flow available for capital expenditures and our ability to borrow and raise additional capital. Lower prices may also reduce the amount of oil and natural gas that we can economically produce. We currently sell a portion of our oil and natural gas production under market price contracts. We periodically use derivative instruments to hedge our commodity price risk. We hedge a portion of our projected oil and natural gas production through a variety of financial and physical arrangements intended to support oil and natural gas prices at targeted levels and to manage our exposure to price fluctuations. We may use futures contracts, swaps, put options and fixed-price physical contracts to hedge our commodity prices. See Derivative Instruments and Risk Management Activities in Note 9 to the consolidated financial statements.

We may enter into short-term hedging arrangements if (1) we are able to obtain commodity contracts at prices sufficient to secure an acceptable internal rate of return on a particular property or on a group of properties or (2) if deemed necessary by the terms of our existing credit agreements. We do not initially hold or issue derivative instruments for speculative purposes.

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Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

Our principal executive officer and principal financial officer have reviewed and evaluated the effectiveness of our disclosure controls and procedures, as defined in Exchange Act Rules 13a-15(e) and 15d-15(e), as of September 30, 2008 (the “Evaluation Date”). Based on this evaluation, the principal executive officer and principal financial officer have concluded that ATP’s disclosure controls and procedures were effective as of the Evaluation Date to ensure that information that is required to be disclosed by ATP in the reports it files or submits under the Exchange Act is (i) recorded, processed, summarized and reported, within the time periods specified in the Securities and Exchange Commission’s rules and forms and (ii) accumulated and communicated to ATP’s management, including our principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding required disclosure.

Changes in Internal Control Over Financial Reporting

During the three months ended September 30, 2008, we have made no change to our internal controls over financial reporting that has materially affected, or is reasonably likely to materially affect, our internal controls over financial reporting.

Forward-Looking Statements and Associated Risks

This Quarterly Report contains projections and other forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934. These projections and statements reflect the Company’s current views with respect to future events and financial performance. No assurances can be given, however, that these events will occur or that these projections will be achieved and actual results could differ materially from those projected as a result of certain factors. A discussion of these factors is included in the Company’s 2007 Annual Report on Form 10-K.

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PART II. OTHER INFORMATION

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

Item 1A.    Risk Factors

For additional information about the risk factors facing the Company, see Item 1A of Part I of the Company’s Annual Report on Form 10-K for the year ended December 31, 2007.

The global financial crisis may materially and adversely impact our financial condition and results of operations in amounts and ways that we currently cannot predict.

The continued credit crisis and related turmoil in the global financial system may have an impact on our industry, our business and our financial condition. This stress in the markets may cause us to face greater challenges if conditions in the financial markets do not improve. Our ability to access the capital markets or to consummate planned asset sales may be restricted at a time when we would like or need to raise financing, impairing our ability to react to changing economic and business conditions, or modifying or interrupting our business plans. The current economic situation could lead to reduced demand for oil and natural gas, or lower prices for oil and natural gas, or both, which could have a negative impact on our revenues, the value of our assets and our ability to meet our obligations. Further, the economic situation could also impact our lenders, customers and hedging counterparties and may cause them to fail to meet their obligations to us with little or no warning.

Item 6. Exhibits

Exhibits
3.1	Amended and Restated Articles of Incorporation, incorporated by reference to Exhibit 3.1 of Registration Statement No. 333-46034 on Form S-1 of ATP Oil & Gas Corporation (“ATP”).
3.2	Amended and Restated Bylaws of ATP, incorporated by reference to Exhibit 3.1 of ATP’s Report on Form 10-Q for the quarter ended September 30, 2006.
4.1	Warrant Shares Registration Rights Agreement dated as of March 29, 2004 between ATP and each of the Holders set forth on the execution pages thereof, incorporated by reference to Exhibit 4.5 of ATP’s Form 10-K for the year ended December 31, 2003.
4.2	Warrant Agreement dated as of March 29, 2004 by and among ATP and the Holders from time to time of the warrants issued hereunder, incorporated by reference to Exhibit 4.6 of ATP’s Form 10-K for the year ended December 31, 2003.
4.3	Rights Agreement dated October 11, 2005 between ATP and American Stock Transfer & Trust Company, as Rights Agent, specifying the terms of the Rights, which includes the form of Statement of Designations of Junior Participating Preferred Stock as Exhibit A, the form of Right Certificate as Exhibit B and the form of the Summary of Rights to Purchase Preferred Shares as Exhibit C, incorporated by reference to Exhibit 1 to the Company’s Registration Statement on Form 8-A filed with the Securities and Exchange Commission on October 14, 2005.
*10.1	Sale and Purchase Agreement between ATP Oil & Gas (UK) Limited and EDF Production UK Ltd, as amended and restated on October 23, 2008.
*10.2	Call Option Agreement between EDF Production UK Ltd and ATP Oil & Gas (UK) Limited, as amended and restated on October 23, 2008.
†10.3	ATP Oil & Gas Corporation 2000 Stock Plan, incorporated by reference to Exhibit 10.11 of ATP’s Form 10-K for the year ended December 31, 2000.
10.4	Credit Agreement, dated as of June 27, 2008, among ATP, the lenders named therein, and Credit Cuisse, as Administrative Agent and Collateral Agent, incorporated by reference to Exhibit 99.1 to ATP’s Form 8-K dated June 27, 2008.
†10.5	Employment Agreement between ATP and Pauline H. van der Sman-Archer, dated December 29, 2005, incorporated by reference to Exhibit 10.1 to ATP’s Form 8-K dated December 30, 2005.
†10.6	Employment Agreement between ATP and John E. Tschirhart, dated December 29, 2005, incorporated by reference to Exhibit 10.2 to ATP’s Form 8-K dated December 30, 2005.
†10.7	Employment Agreement between ATP and Leland E. Tate, dated December 29, 2005, incorporated by reference to Exhibit 10.3 to ATP’s Form 8-K dated December 30, 2005.
†10.8	Employment Agreement between ATP and Robert M. Shivers, III, dated December 29, 2005, incorporated by reference to Exhibit 10.4 to ATP’s Form 8-K dated December 30, 2005.
†10.9	Employment Agreement between ATP and Mickey W. Shaw, dated December 29, 2005, incorporated by reference to Exhibit 10.5 to ATP’s Form 8-K dated December 30, 2005.
†10.10	Employment Agreement between ATP and Albert L. Reese, Jr., dated December 29, 2005, incorporated by reference to Exhibit 10.7 to ATP’s Form 8-K dated December 30, 2005.

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†10.11	Employment Agreement between ATP and Isabel M. Plume, dated December 29, 2005, incorporated by reference to Exhibit 10.8 to ATP’s Form 8-K dated December 30, 2005.
†10.12	Employment Agreement between ATP and Scott D. Heflin, dated December 29, 2005, incorporated by reference to Exhibit 10.9 to ATP’s Form 8-K dated December 30, 2005.
†10.13	Employment Agreement between ATP and Keith R. Godwin, dated December 29, 2005, incorporated by reference to Exhibit 10.10 to ATP’s Form 8-K dated December 30, 2005.
†10.14	Employment Agreement between ATP and George Ross Frazer, dated December 29, 2005, incorporated by reference to Exhibit 10.11 to ATP’s Form 8-K dated December 30, 2005.
†10.15	Employment Agreement between ATP and T. Paul Bulmahn, dated December 29, 2005, incorporated by reference to Exhibit 10.12 to ATP’s Form 8-K dated December 30, 2005.
†10.16	Employment Agreement between ATP and George R. Morris, dated May 27, 2008, incorporated by reference to Exhibit 99.1 to ATP’s Form 8-K dated May 21, 2008.
21.1	Subsidiaries of ATP, incorporated by reference to Exhibit 21.1 of ATP’s Annual Report on Form 10-K for the year ended December 31, 2002.
*31.1	Certification of Principal Executive Officer pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934, the “Act.”
*31.2	Certification of Principal Financial Officer pursuant to Rule 13a-14(a) of the Act
*32.1	Certification of Principal Executive Officer pursuant to 18 U.S.C. Section 1350
*32.2	Certification of Principal Financial Officer pursuant to 18 U.S.C. Section 1350

† Management contract or compensatory plan or arrangement

* Filed herewith

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SIGNATURES

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

		ATP Oil & Gas Corporation
Date: November 7, 2008	By:	/s/ Albert L. Reese Jr.
		Albert L. Reese Jr.
		Chief Financial Officer

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