10-Q

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, 2007

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 ¨

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 5, 2007, was 30,632,351.

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

TABLE OF CONTENTS

	Page
PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS (Unaudited)
Consolidated Balance Sheets: September 30, 2007 and December 31, 2006	3
Consolidated Statements of Operations: For the three and nine months ended September 30, 2007 and 2006	4
Consolidated Statements of Cash Flows: For the nine months ended September 30, 2007 and 2006	5
Consolidated Statements of Comprehensive Income: For the three and nine months ended September 30, 2007 and 2006	6
Notes to Consolidated Financial Statements	7
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	16
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS	24
ITEM 4. CONTROLS AND PROCEDURES	25
PART II. OTHER INFORMATION	25

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,
	2007			2006
Assets
Current assets:
Cash and cash equivalents	$	152,981		$	182,592
Restricted cash		14,413			27,497
Accounts receivable (net of allowance of $382 and $409, respectively)		66,438			105,030
Deferred tax asset		1,418			1,113
Derivative asset		1,044			1,170
Other current assets		16,213			9,931
Total current assets		252,507			327,333
Oil and gas properties (using the successful efforts method of accounting)
Proved properties		2,109,119			1,483,163
Unproved properties		112,381			56,189
		2,221,500			1,539,352
Less: Accumulated depletion, impairment and amortization		(617,420	)		(443,707	)
Oil and gas properties, net		1,604,080			1,095,645
Furniture and fixtures (net of accumulated depreciation)		969			1,079
Deferred tax asset		591			—
Derivative asset		3,019			—
Deferred financing costs, net		22,064			13,272
Other assets, net		6,462			9,729
Total assets	$	1,889,692		$	1,447,058
Liabilities and Shareholders’ Equity
Current liabilities:
Accounts payable and accruals	$	163,460		$	195,846
Current maturities of long-term debt		12,737			8,987
Current maturities of long-term capital lease		—			23,699
Asset retirement obligation		15,832			21,297
Derivative liability		168			—
Other current liabilities		24,265			—
Total current liabilities		216,462			249,829
Long-term debt		1,449,207			1,062,454
Asset retirement obligation		113,822			87,092
Deferred tax liability		14,391			11,765
Derivative liability		6,185			—
Total liabilities		1,800,067			1,411,140
Commitments and contingencies (Note 11)		—			—
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; 30,525,473 issued and 30,449,633 outstanding at September 30, 2007; 30,272,210 issued and 30,196,370 outstanding at December 31, 2006		30			30
Additional paid-in capital		158,567			151,467
Accumulated deficit		(104,801	)		(140,681	)
Accumulated other comprehensive income		36,740			26,013
Treasury stock		(911	)		(911	)
Total shareholders’ equity		89,625			35,918
Total liabilities and shareholders’ equity	$	1,889,692		$	1,447,058

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						Nine Months Ended
	September 30,			September 30,			September 30,			September 30,
	2007			2006			2007			2006
Revenues:
Oil and gas production	$	116,738		$	132,822		$	393,640		$	286,952
Other revenues		—			—			1,598			—
		116,738			132,822			395,238			286,952
Costs, operating expenses and other:
Lease operating		21,152			22,848			62,326			54,800
Exploration		1,799			1,660			13,135			2,168
General and administrative		7,610			7,803			22,950			23,163
Depreciation, depletion and amortization		53,617			55,026			159,629			115,545
Impairment of oil and gas properties		4,028			11,760			9,798			11,760
Accretion of asset retirement obligation		3,039			2,255			9,019			5,473
Loss on abandonment		300			349			379			3,855
Other, net		(2,069	)		—			(2,069	)		—
		89,476			101,701			275,167			216,764
Income from operations		27,262			31,121			120,071			70,188
Other income (expense):
Interest income		1,329			1,377			5,947			3,157
Interest expense		(29,717	)		(14,780	)		(87,541	)		(38,049	)
		(28,388	)		(13,403	)		(81,594	)		(34,892	)
Income (loss) before income taxes		(1,126	)		17,718			38,477			35,296
Income tax (expense) benefit:
Current		1,566			(2,195	)		1,532			(4,036	)
Deferred		1,881			(2,814	)		(4,129	)		(4,236	)
		3,447			(5,009	)		(2,597	)		(8,272	)
Net income		2,321			12,709			35,880			27,024
Preferred stock dividends		—			(11,536	)		—			(29,340	)
Net income (loss) available to common shareholders	$	2,321		$	1,173		$	35,880		$	(2,316	)
Net income (loss) per common share:
Basic	$	0.08		$	0.04		$	1.19		$	(0.08	)
Diluted		0.08			0.04			1.17			(0.08	)
Weighted average number of common shares:
Basic		30,118			29,776			30,060			29,643
Diluted		30,771			30,406			30,669			29,643

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,			September 30,
	2007			2006
Cash flows from operating activities
Net income	$	35,880		$	27,024
Adjustments to reconcile net income to net cash provided by operating activities—
Depreciation, depletion and amortization		159,629			115,545
Impairment of oil and gas properties		9,798			11,760
Accretion of asset retirement obligation		9,019			5,473
Deferred income taxes		4,129			4,236
Dry hole costs		10,251			—
Amortization of deferred financing costs		5,212			4,387
Stock-based compensation		5,095			8,686
Ineffectiveness of cash flow hedges		(74	)		45
Other noncash items		1,742			4,424
Changes in assets and liabilities—
Accounts receivable and other current assets		31,339			(81,935	)
Accounts payable and accruals		(31,879	)		6,847
Other assets		(2,390	)		(1,146	)
Net cash provided by operating activities		237,751			105,346
Cash flows from investing activities
Additions and acquisitions of oil and gas properties		(636,597	)		(390,916	)
Additions to furniture and fixtures		(296	)		(331	)
(Increase) decrease in restricted cash		14,096			(13,296	)
Net cash used in investing activities		(622,797	)		(404,543	)
Cash flows from financing activities
Proceeds from long-term debt		574,500			178,500
Payments of long-term debt		(184,552	)		(2,188	)
Deferred financing costs		(13,449	)		(11,116	)
Issuance of preferred stock, net of issuance costs		—			145,463
Payments of capital lease		(23,950	)		(20,869	)
Exercise of stock options		2,004			4,416
Net cash provided by financing activities		354,553			294,206
Effect of exchange rate changes on cash and cash equivalents		882			688
Decrease in cash and cash equivalents		(29,611	)		(4,303	)
Cash and cash equivalents, beginning of period		182,592			65,566
Cash and cash equivalents, end of period	$	152,981		$	61,263

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					Nine Months Ended
	September 30,			September 30,		September 30,			September 30,
	2007			2006		2007			2006
Net income (loss)	$	2,321		$	1,173	$	35,880		$	(2,316	)
Other comprehensive income, net of tax:
Reclassification adjustment for settled hedge contracts (net of income tax of $59, $0, $59 and $0, respectively)		75			1,429		1,712			3,439
Change in fair value of outstanding hedge positions (net of tax benefit of $3,177, $0, $3,177 and $0, respectively)		(6,727	)		514		(8,878	)		(3,832	)
Foreign currency translation adjustment		8,350			4,327		17,893			15,108
Other comprehensive income		1,698			6,270		10,727			14,715
Comprehensive income	$	4,019		$	7,443	$	46,607		$	12,399

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 (“ATP”) 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 with proved undeveloped reserves that are economically attractive to us but are not strategic to major or exploration-oriented independent oil and gas companies.

The accompanying unaudited consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”) for interim financial information and reflect all adjustments (consisting of normal recurring adjustments) which are, in the opinion of management, necessary for a fair presentation of the results of operations for the interim periods. All intercompany transactions are eliminated upon consolidation. The interim financial information and notes hereto should be read in conjunction with our 2006 Annual Report on Form 10-K. The results of operations for the nine months ended September 30, 2007 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 classifications currently followed. Such reclassifications do not affect earnings.

Note 2—Recent Accounting Pronouncements

During September 2006, the Financial Accounting Standards Board (“FASB”) issued Interpretation No. 48, “Accounting for Uncertainty in Income Taxes-an Interpretation of FASB Statement No. 109,” (“FIN No. 48”) which provides guidance for the recognition and measurement of a tax position taken or expected to be taken in a tax return. We adopted FIN No. 48, effective January 1, 2007. Under FIN No. 48, we are required to determine whether it is more likely than not that a tax position will be sustained upon examination, including resolution of any related appeals or litigation processes, based on the technical merits of the position. If the tax position meets the “more likely than not” recognition threshold, it is then measured and recorded at the largest amount of benefit that is greater than 50 percent likely of being realized upon ultimate settlement. This is discussed in detail in Note 3.

During September 2006, the FASB issued Statement of Financial Accounting Standards (“SFAS”) No. 157, “Fair Value Measurements”. This Statement defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles, and expands disclosures about fair value measurements. This Statement applies under other accounting pronouncements that require or permit fair value measurements, where fair value has been determined to be the relevant measurement attribute. This statement is effective for financial statements of fiscal years beginning after November 15, 2007. We are evaluating the impact that this guidance may have on our financial statements.

During February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities including an amendment of FASB Statement No. 115.” The new standard permits an entity to make an irrevocable election to measure most financial assets and financial liabilities at fair value. The fair value option may be elected on an instrument-by-instrument basis, with a few exceptions, as long as it is applied to the instrument in its entirety. Changes in fair value would be recorded in income. SFAS No. 159 establishes presentation and disclosure requirements intended to help financial statement users understand the effect of the entity’s election on earnings. SFAS No. 159 is effective as of the beginning of the first fiscal year beginning after November 15, 2007. Early adoption is permitted. We are evaluating the impact that this guidance may have on our financial statements.

Note 3—Income Taxes

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 carrying amounts and the tax basis of those assets and liabilities. We have recorded and continue to carry a valuation allowance to give effect to our judgment that it is more likely than not that some portion or all of our net U.S. deferred tax assets will not be realized at some point in the future. Relevant accounting guidance suggests that cumulative losses in recent years constitute significant negative evidence that such deferred tax assets are not

7

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

recoverable, and that future expectations about income are overshadowed by such history of losses. As of September 30, 2007, we have a valuation allowance equal to the entire balance of our net U.S. deferred tax asset, and we have no valuation allowance recorded related to our foreign operations as a result of the taxable income generated by those entities. Our year-to-date 2007 effective tax rate in the foreign jurisdictions is derived from our expectations of net income for the year, taking into consideration permanent differences primarily related to foreign exchange gains and losses, certain nondeductible interest expense and property basis differences. Year to date, we recorded income taxes of $2.6 million resulting in a worldwide effective tax rate of 6.8%.

The adoption of FIN No. 48 discussed in Note 2 above had no material effect on our consolidated financial position or results of operations. The Company and its subsidiaries file income tax returns in the United States federal jurisdiction, two states, the United Kingdom and the Netherlands. Our open tax years in our major jurisdictions are from 2001 to current. We will record to the income tax provision any interest and penalties related to unrecognized tax positions.

We have provided for an uncertainty that relates to a disagreement with the Dutch taxing authority in regard to the timing of the recognition of taxable income on certain cash receipts in 2002. As of September 30, 2007, the amount of the uncertain tax position is $2.2 million, which is the difference between the tax filing position and the amounts provided for in current liabilities in the accompanying financial statements. If the tax filing position is sustained, there would be no expected significant impact to the effective tax rate. We expect this uncertainty to be resolved in the next twelve months.

Note 4—Asset Retirement Obligations

Following are reconciliations of the beginning and ending asset retirement obligation for the periods ended September 30, 2007 and 2006 (in thousands):

	Nine Months Ended
	September 30,			September 30,
	2007			2006
Asset retirement obligation at beginning of period	$	108,389		$	67,364
Liabilities incurred		20,039			32,203
Liabilities settled		(9,393	)		(3,537	)
Changes in estimates		—			(1,567	)
Accretion		9,019			5,473
Foreign currency translation		1,600			1,232
Asset retirement obligation at end of period	$	129,654		$	101,168

Note 5—Supplemental Disclosures of Cash Flow Information

Following are supplemental disclosures of cash flow information for the periods ended September 30, 2007 and 2006 (in thousands):

	Nine Months Ended
	September 30,		September 30,
	2007		2006
Cash paid during the period for interest, including amounts capitalized	$	74,666	$	26,717
Cash paid during the period for income taxes		8,325		—

During the nine months ended September 30, 2007 we acquired two oil and gas properties, a significant portion of the consideration for which was noncash. See Note 7.

8

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 6—Long-Term Debt

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

	September 30,			December 31,
	2007			2006
First Lien Term Loans	$	1,261,888		$	896,441
Second Lien Term Loans		—			175,000
Subordinated Notes (includes accreted premium of $383; excludes unamortized discount of $10,327)		200,056			—
Total		1,461,944			1,071,441
Less current maturities		(12,737	)		(8,987	)
Total long-term debt	$	1,449,207		$	1,062,454

On March 23, 2007 (the “Amendment Date”) ATP, Credit Suisse (as Administrative Agent and Collateral Agent for the lenders) and the lenders named therein entered into Amendment No. 1 and Agreement (the “Amendment”) amending the Third Amended and Restated Credit Agreement dated as of December 28, 2006 (as so amended, the “Existing Credit Agreement” or “Term Loans”).

As of the Amendment Date, the Company increased its aggregate borrowings by a net $200.0 million (from the aggregate balance outstanding as of December 31, 2006) to $1.268 billion. The Company borrowed additional amounts under terms and provisions (after giving effect to the amendments made to the Existing Credit Agreement on the Amendment Date) identical in all material respects to the existing first lien term loans as of the Amendment Date, in an aggregate principal amount of $375.0 million, all of the proceeds of which were used by the Company (a) to pay fees and expenses incurred in connection with the Existing Credit Agreement in an aggregate amount of $8.4 million, (b) to repay in full all outstanding borrowings under the second lien term loan facility, which had an original face amount of $175.0 million and bore interest at a rate of LIBOR plus 4.75%, and (c) from time to time solely for general corporate purposes, predominantly the development of the properties acquired to-date in 2007. Net cash proceeds to the Company were $191.5 million. The interest rate on outstanding borrowings is based on LIBOR plus 3.5%, and at September 30, 2007 was approximately 9.49%.

Under the Existing Credit Agreement, we have a $50.0 million revolving credit facility (“Revolver”), all of which was available as of September 30, 2007.

During September 2007, the Company, Credit Suisse (as Administrative Agent for the lenders) and the lenders named therein entered into an Unsecured Subordinated Credit Agreement (the “Subordinated Notes”) for aggregate borrowings of $210.0 million. The borrowings bear interest at 11.25%, payable quarterly, and mature in September 2011. Such borrowings are subordinated to the borrowings under the Existing Credit Agreement and may be prepaid at any time at the option of the Company, subject to limitations set forth in the Existing Credit Agreement. The Company has assumed the debt will be paid off at maturity and accordingly recognizes over the term of the facility additional noncash interest expense related to deferred financing costs, an original issue discount and a sliding-scale redemption premium. If held to maturity, the aggregate average effective interest rate on the Subordinated Notes is approximately 15.3%. The Company received net proceeds from the issuance of the Subordinated Notes of $193.8 million after deducting $16.2 million for the original issue discount, fees and expenses.

The Subordinated Notes contain no financial performance covenants, but contain affirmative and negative covenants, including limitations on incurring certain indebtedness, that are usual and customary for transactions of this type.

9

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

The combined effective interest rate on all outstanding borrowings under the Existing Credit Agreement and the Subordinated Notes at September 30, 2007 was approximately 10.97%.

As of September 30, 2007, we were in compliance with all of the financial covenants of our credit agreements. Significant adverse changes in our expected production levels, commodity prices and reserves or material delays or cost overruns could have a material adverse affect on our financial condition and results of operations and result in our noncompliance with these covenants. An event of noncompliance with any of the required covenants could result in a material mandatory repayment under the Existing Credit Agreement and the Subordinated Notes.

Note 7—Oil and Gas Properties

Acquisitions

During January 2007, we completed the acquisition of a 50% working interest in Mississippi Canyon (“MC”) Block 305 (“Aconcagua”), a 16.67% working interest in MC Block 348 (“Camden Hills”), and an additional interest in the Canyon Express Pipeline Common System (“Canyon Express”). Both Aconcagua and Camden Hills, along with MC 217 (“King’s Peak”) produce through Canyon Express, in which we now own a 45.084% working interest as a result of this acquisition. We are the operator of Canyon Express. During January 2007, we completed the acquisition of a 100% working interest in the northwest quarter of MC Block 755 (“Anduin”), a 50% working interest in MC Block 754 (“Anduin West”), and a 25% working interest in MC Block 800 (“Gladden”). These properties are located in the vicinity of the MC Block 711 (“Gomez”) development and, if successful, are expected to produce through the ATP Innovator floating production facility. The aggregate net acquisition price for these properties was $27.2 million. A portion of the acquisition price of one property was financed by granting an interest in the future net profits, discounted to $24.3 million as of September 30, 2007.

During July 2007, we acquired the remaining 22% working interest in South Timbalier 77, an additional 44% working interest in High Island 74 and a 100% working interest in Ship Shoal 350. During August 2007, we were the apparent high bidder and we subsequently acquired a 100% working interest in High Island Block A-580 and East Breaks Block 563 at an MMS offshore lease sale. The accompanying financial statements reflect an aggregate cash purchase price for these properties of $7.0 million.

Capitalized Interest

During the quarter, we capitalized $3.6 million of interest costs to oil and gas properties related to the construction of a floating production system at our Mississippi Canyon 941/942 and Atwater Valley 63 properties in the Gulf of Mexico.

Impairment

We recorded impairment of oil and gas properties totaling $4.0 million and $5.8 million during the third and second quarters of 2007, respectively, related to properties in the Gulf of Mexico. These amounts represent the remaining carrying cost of those properties, and resulted from a well becoming nonproductive and the surrender of the lease, respectively.

10

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 8—Stock–Based Compensation

We recognized stock option compensation expense of approximately $0.4 million and $1.0 million for the three months and nine months ended September 30, 2007, respectively. The weighted average grant-date fair value of options granted during the nine months ended September 30, 2007 and 2006 was $14.82 and $16.21, respectively.

The fair values of options granted are 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 periods indicated:

	Three Months Ended				Nine Months Ended
	September 30,		September 30,		September 30,		September 30,
	2007		2006		2007		2006
Weighted average volatility	36	%	52	%	36	%	51	%
Expected term (in years)	3.8		4.3		3.8		4.3
Risk-free rate	4.0	%	4.8	%	4.0	%	4.6	%

The following table sets forth a summary of option transactions for the nine month period ended September 30, 2007:

	Number of Options		Weighted Average Grant Price		Aggregate Intrinsic Value ($000)(1)		Weighted Average Remaining Contractual Life
							(in years)
Outstanding at beginning of period	693,851		$	24.76
Granted	286,750			45.28
Exercised	(107,376	)		18.67
Forfeited	(31,751	)		28.40
Outstanding at end of period	841,474			32.39	$	12,348	3.59
Vested and expected to vest	771,692			32.29		11,398	3.51
Options exercisable at end of period	181,233			23.56		4,254	2.78

(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, 2007, unrecognized compensation expense related to nonvested stock option grants totaled $5.0 million. Such unrecognized expense will be recognized as vesting occurs over the weighted average remaining vesting period.

During the three and nine months ended September 30, 2007, we recognized aggregate compensation expense of $1.5 million and $4.1 million, respectively, related to all of our outstanding restricted stock grants. The following table sets forth the restricted stock transactions for the nine month period ended September 30, 2007:

	Number of Shares		Weighted Average Grant Date Fair Value		Aggregate Intrinsic Value ($000) (1)
Nonvested at beginning of period	233,502		$	38.03
Granted	145,887			43.52
Vested	(66,154	)		40.85
Nonvested at end of period	313,235			39.99	$	14,731

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

11

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

At September 30, 2007, unrecognized compensation expense related to restricted stock totaled $6.4 million. Such unrecognized expense will be recognized as vesting occurs over the weighted average remaining vesting period of 1.9 years.

Note 9—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 unvested restricted stock) outstanding during the period. Diluted EPS is determined on the assumption that outstanding stock options and warrants have been converted using the average price for the period. For purposes of computing earnings per share in a loss year, potential common shares are excluded from the computation of weighted average common shares outstanding as their effect is antidilutive. For the three months and nine months ended September 30, 2007, stock-based awards for 25,500 and 294,000 average shares of common stock, respectively, were excluded from the diluted EPS calculation because their inclusion would have been antidilutive. For the three months and nine months ended September 30, 2006, stock-based awards for 20,500 and 715,341 average shares of common stock, respectively, were excluded from the diluted EPS calculation because their inclusion would have been antidilutive.

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

	Three Months Ended					Nine Months Ended
	September 30, 2007		September 30, 2006			September 30, 2007		September 30, 2006
Income
Net income	$	2,321	$	12,709		$	35,880	$	27,024
Less preferred dividends		—		(11,536	)		—		(29,340	)
Net income (loss) available to common shareholders	$	2,321	$	1,173		$	35,880	$	(2,316	)
Shares outstanding
Weighted average shares outstanding—basic		30,118		29,776			30,060		29,643
Effect of potentially dilutive securities—stock options and warrants		507		471			471		—
Nonvested restricted stock		146		159			138		—
Weighted average shares outstanding—diluted		30,771		30,406			30,669		29,643
Net income (loss) per common share:
Basic	$	0.08	$	0.04		$	1.19	$	(0.08	)
Diluted	$	0.08	$	0.04		$	1.17	$	(0.08	)

Note 10—Derivative Instruments and Risk Management Activities

At September 30, 2007 and December 31, 2006, Accumulated Other Comprehensive Income included $8.1 million and $1.0 million of unrealized losses, respectively, on our cash flow hedges. Gains and losses are reclassified from Accumulated Other Comprehensive Income to the consolidated statement of operations as a component of oil and gas production revenues in the period the forecasted hedged production occurs. If any ineffectiveness occurs, amounts are recorded directly to the consolidated statement of operations as a component of oil and gas production revenues.

12

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

At September 30, 2007, we had oil and natural gas derivatives that qualified as cash flow hedges with respect to our future production as follows:

Description	Type	Volumes	Price		Net Fair Value Asset (Liability)
			$/Unit		($000)
Oil (Bbls)—Gulf of Mexico
2007	Puts	92,000	$	60.00	$	3
2008	Puts	2,488,800		54.67		1,436
2009	Puts	1,496,500		54.00		2,340
Natural Gas (MMBtu)—North Sea
2007	Swaps	310,000	$	10.07	$	279
2008	Swaps	5,216,500		8.31		(1,941	)
2009	Swaps	3,130,000		7.86		(4,692	)

We also manage our exposure to oil and gas price risks by periodically entering into fixed-price forward sale contracts. These physical contracts qualified and have been designated for the normal purchase and sale exemption under SFAS 133, as amended.

At September 30, 2007, we had fixed-price contracts in place for the following natural gas and oil volumes:

Period	Volumes	Average Fixed Price (1)
		$/Unit
Natural gas (MMBtu)
Gulf of Mexico:
2007	5,188,000	$	8.04
2008	13,188,000		8.30
2009	8,175,000		8.04
North Sea:
2007	5,520,000	$	9.25
2008	16,460,000		7.96
2009	2,700,000		8.19
Oil (Bbl)—Gulf of Mexico:
2007	977,600	$	72.23
2008	3,078,000		72.15
2009	1,368,000		67.63
2010	365,000		68.20
2011	273,000		68.20

(1) Includes the effect of basis differentials.

Subsequent to September 30, 2007, we entered into U.S. fixed-price oil contracts for the periods between April 2008 and December 2009 for 1.9 million Bbl at an average price of $83.98 per Bbl. We also entered into U.K. gas swaps for the periods between April 2008 and December 2009 for 1,569,750 MMBtu at an average price equating to approximately $8.63 per MMBtu.

Note 11—Commitments and Contingencies

Contingencies

During 2005, Hurricanes Rita and Katrina caused minimal direct damage to most of our platforms with some platforms, primarily in the Western Gulf, sustaining no damage. In addition, we lost potential revenues due to shut-in production resulting from the storms. We maintain property casualty insurance for such physical damages and loss-of-production insurance to replace lost cash flows resulting from downtime in excess of a specified deductible period after the event. We have submitted claims for the insured damages and any recoveries available under the loss-of-production income (“LOPI”) insurance policy. At September 30, 2007, we had a receivable for expected recovery of repair costs incurred related to the 2005 storms in the amount of $12.4 million, net of $4.4 million already received through that date. Additionally, we recorded other revenues in the amount of $1.6 million realized from the LOPI insurance policy during the first nine months of 2007. We expect to receive additional amounts related to LOPI insurance; however no such amounts will be recorded to the financial statements until they are realized.

13

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

We are a party to a multi-year (life of reserves) firm transportation agreement covering certain production in the U.K. 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 acquire proved properties with little or no upfront costs, but with a commitment to make payments out of future production, if any. As initial production or designated production levels are achieved, the contingent consideration is accrued and capitalized to the appropriate property. At September 30, 2007, our aggregate exposure under such arrangements totaled approximately $39.6 million, and included net profits interests payable, including accrued interest, of approximately $24.3 million, representing the present value of amounts expected ultimately to be paid from future production from the properties.

Litigation

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.

Note 12—Segment Information

Our 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. Each segment is an aggregation of operations subject to similar economic and regulatory conditions such that they are likely to have similar long-term prospects for financial performance. The operations of both segments include natural gas and liquid hydrocarbon production and sales. We evaluate the segments based on income (loss) from operations. Segment activity for the three months and nine months ended September 30, 2007 and 2006 is as follows (in thousands):

For the Three Months Ended—	Gulf of Mexico		North Sea			Eliminations			Total
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		28,810		(1,548	)		—			27,262
Interest income		6,350		606			(5,627	)		1,329
Interest expense		29,717		5,627			(5,627	)		29,717
Income tax benefit		—		3,447			—			3,447
Additions to oil and gas properties		144,928		65,634			—			210,562
September 30, 2006:
Revenues	$	102,963	$	29,859		$	—		$	132,822
Depreciation, depletion and amortization		41,475		13,551			—			55,026
Impairment of oil and gas properties		11,760		—			—			11,760
Income from operations		22,489		8,632			—			31,121
Interest income		2,291		131			(1,045	)		1,377
Interest expense		14,802		1,023			(1,045	)		14,780
Income tax expense		—		5,009			—			5,009
Additions to oil and gas properties		137,855		82,423			—			220,278

14

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Nine Months Ended—	Gulf of Mexico		North Sea		Eliminations			Total
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		107,068		13,003		—			120,071
Interest income		17,632		1,707		(13,392	)		5,947
Interest expense		87,541		13,392		(13,392	)		87,541
Income tax expense		—		2,597		—			2,597
Total assets		1,303,961		585,731		—			1,889,692
Additions to oil and gas properties		504,302		188,097		—			692,399
September 30, 2006:
Revenues	$	228,547	$	58,405	$	—		$	286,952
Depreciation, depletion and amortization		87,993		27,552		—			115,545
Impairment of oil and gas properties		11,760		—					11,760
Income from operations		55,004		15,184		—			70,188
Interest income		3,773		429		(1,045	)		3,157
Interest expense		37,945		1,149		(1,045	)		38,049
Income tax expense		—		8,272		—			8,272
Total assets		874,947		400,274		—			1,275,221
Additions to oil and gas properties		308,873		174,525		—			483,398

15

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 (“we” or the “Company”) 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 (“PUD”) that are economically attractive to us but may not be 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 us to contain commercially productive quantities of oil and gas even though the reservoirs do not meet the SEC definition of proved reserves. The wells we drill into the reservoirs that are not classified as proved are considered exploration wells. Additionally, we periodically drill extension wells across a fault from existing proved reservoirs, which are also considered exploration wells. We believe that our strategy provides assets for us to develop and produce without the risk, cost or time of traditional exploration.

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

• significant undeveloped reserves and reservoirs;

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

• existing infrastructure of oil and natural gas pipelines and production and processing platforms; and

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

Our focus is on acquiring properties that have become 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 offer greater reserve potential. Some projects provide lower economic returns to a company due to its cost structure within that company. Also, due to timing or budget constraints, a company may be 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. Given our primary strategy of acquiring properties that contain proved reserves, our operations typically are lower risk than exploration-focused Gulf of Mexico and North Sea operators.

We focus on developing projects in the shortest time possible between initial significant investment and first revenue generated in order to maximize our rate of return. Since we operate a significant number 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 typically 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 in a relatively short period of time.

Source of Revenue

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

16

Third Quarter 2007 Highlights

Our financial and operating performance for the third quarter of 2007 included the following highlights:

• Achieved quarterly production revenue of $116.7 million and achieved net income of $2.3 million or $0.08 per basic and diluted share;

• Achieved 250 MMcfe/d November to-date company-wide production rate including five wells producing near the facility limits as a result of the upgrade to the ATP Innovator and expansion of the Gomez Hub;

• Completed the four-well development at Ship Shoal 351 on the Gulf of Mexico shelf which is currently producing at the facilities’ limit;

• Encountered the targeted reservoir and completed the first lateral of the Tors K3 well;

A more complete overview and discussion of full year expectations can be found in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our 2006 Annual Report on Form 10-K.

Results of Operations

Three Months Ended September 30, 2007 Compared to Three Months Ended September 30, 2006

For the three months ended September 30, 2007, we reported net income available to common shareholders of $2.3 million, or $0.08 per basic and diluted share on total revenue of $116.7 million, as compared with a net income available to common shareholders of $1.2 million, or $0.04 per basic and diluted share, on total revenue of $132.8 million for the three months ended September 30, 2006.

Oil and Natural Gas Revenues. Revenues presented in the table and in the discussion below represent revenues from sales of our oil and natural gas production volumes, and exclude the impact, if any, of hedging ineffectiveness. 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. Approximately 34% and 16% of our natural gas production was sold under these contracts during the three months ended September 30, 2007 and 2006, respectively. Approximately 45% and 66% of our oil production was sold under these contracts during the comparable periods. The realized prices below may differ from the market prices in effect during the periods depending on when the fixed price delivery contract was executed.

	Three Months Ended September 30,						% Change in 2007 from 2006
	2007			2006
Production:
Natural gas (MMcf)		8,021			8,726		(8	)%
Oil and condensate (MBbls)		887			1,215		(27	)%
Total (MMcfe)		13,343			16,017		(17	)%
Revenues from production (in thousands):
Natural gas	$	58,276		$	60,045		(3	)%
Effects of cash flow hedges		(118	)		2,934		(104	)%
Total	$	58,158		$	62,979		(8	)%
Oil and condensate	$	59,046		$	71,056		(17	)%
Effects of cash flow hedges		(230	)		(1,140	)	80	%
Total	$	58,816		$	69,916		(16	)%
Natural gas, oil and condensate	$	117,322		$	131,101		(11	)%
Effects of cash flow hedges		(348	)		1,794		(119	)%
Total	$	116,974		$	132,895		(12	)%

17

	Three Months Ended September 30,						% Change in 2007 from 2006
	2007			2006
Average sales price per unit:
Natural gas (per Mcf)	$	7.27		$	6.88		6	%
Effects of cash flow hedges (per Mcf)		(0.02	)		0.34		(106	)%
Total (per Mcf)	$	7.25		$	7.22		—
Oil and condensate (per Bbl)	$	66.56		$	58.46		14	%
Effects of cash flow hedges (per Bbl)		(0.26	)		(0.94	)	72	%
Total (per Bbl)	$	66.30		$	57.52		15	%
Natural gas, oil and condensate (per Mcfe)	$	8.79		$	8.19		7	%
Effects of cash flow hedges (per Mcfe)		(0.02	)		0.11		(118	)%
Total (per Mcfe)	$	8.77		$	8.30		6	%

Revenues from production decreased 12% in the third quarter of 2007 compared to the same period in 2006. During the third quarter of 2007, production decreased 17% from the comparable period in 2006. This decrease was primarily a result of a decrease in oil production on Mississippi Canyon (“MC”) 711 due to the lease being shut in during installation of new production facilities and production decline at L-06 in the Dutch sector North Sea. The decreases are partially offset by increases from production on the Canyon Express Hub and Ship Shoal 351 and increased production at Garden Banks 409. The comparable revenues were impacted favorably by an overall 6% increase in our average realized sales price including the effect of hedges per equivalent Mcf.

Lease Operating. Lease operating expenses for the third quarter of 2007 decreased to $21.2 million ($1.59 per Mcfe) from $22.8 million ($1.43 per Mcfe) in the third quarter of 2006. Lease operating expenses declined in the Netherlands and UK during the three months ended September 30, 2007 compared to the same period of the prior year due to production declines and certain vendor credits, respectively. These decreases were partially offset by increased Gulf of Mexico costs primarily attributable to higher insurance premiums and an increase in costs due to our newly acquired Canyon Express Pipeline interests, resulting in the expense increase per unit of production. During the three months ended September 30, 2007 and 2006, such costs included $2.2 million ($0.21 per Mcfe) and $0.4 million ($0.03 per Mcfe) of nonrecurring workover expenses.

Exploration. Exploration expense for the third quarter of 2007 was $1.8 million compared to $1.7 million for the third quarter of 2006 with both periods including geological and geophysical costs incurred in connection with evaluating oil and gas properties.

General and Administrative. General and administrative expense decreased 2% to $7.6 million for the third quarter of 2007 compared to $7.8 million for the same period of 2006. Noncash stock-based compensation expense decreased to $1.8 million for the three months ended September 30, 2007 compared to $3.2 million for the three months ended September 30, 2006. This 2007 decrease was offset by an increase in other salary expense.

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization (“DD&A”) expense decreased $1.4 million (3%) during the third quarter of 2007 to $53.6 million from $55.0 million for the same period in 2006. The decrease was primarily due to the decreases in production discussed above. The average DD&A rate increased 17% to $4.02 per Mcfe in the third quarter of 2007 compared to $3.44 per Mcfe in the same quarter of 2006. This per unit increase is primarily a result of higher costs incurred on our new developments relative to some of our older properties.

Impairment of oil and gas properties. We recorded impairment during the third quarter of 2007 totaling $4.0 million related to a property in the Gulf of Mexico. This amount represents the remaining carrying cost of that property and resulted from the well becoming nonproductive. We recorded an impairment of oil and gas properties for the third quarter of 2006 totaling $11.8 million related to certain producing properties acquired during 2005.

Accretion of asset retirement obligation. Accretion expense increased to $3.0 million for the third quarter of 2007 compared to $2.3 million for the same period of 2006, primarily due to accretion associated with new abandonment liabilities incurred late in 2006 and the first half of 2007.

18

Interest Expense. Interest expense increased to $29.7 million for the third quarter of 2007 compared to $14.8 million for the same period of 2006, primarily due to the increase in borrowings under our term loans to $1.268 billion when last amended on March 23, 2007 and the issuance of $210.0 million face value subordinated notes in September 2007. Partially offsetting this increase are $3.6 million of capitalized interest costs related to the construction of a floating production system at our MC 941/942 and Atwater 63 properties in the Gulf of Mexico (collectively, the “Telemark Hub”).

Other, net. During the third quarter of 2007, we recognized a foreign currency transaction gain of $1.8 million related to our deposits.

Income Taxes. We recorded a net tax benefit of $3.4 million during the quarter ended September 30, 2007, related to our foreign jurisdictions, based on the expected 2007 effective tax rate of each jurisdiction. The rates were determined based on the projected results of operations for the year, the valuation allowance released associated with the U.S. income before taxes for the quarter and permanent differences affecting the overall tax rate in each foreign jurisdiction. In the comparable quarter of 2006 we recorded a tax provision of $5.0 million related to our foreign jurisdictions. In the U.S., the tax provision recorded on our book income for both periods was offset by a release of valuation allowance.

Nine Months Ended September 30, 2007 Compared to Nine Months Ended September 30, 2006

For the nine months ended September 30, 2007, we reported net income available to common shareholders of $35.9 million, or $1.19 per basic share and $1.17 per diluted share on total revenue of $395.2 million as compared with a net loss available to common shareholders of $2.3 million, or $0.08 per share, on total revenue of $287.0 million for the nine months ended September 30, 2006.

Oil and Natural Gas Revenues. Revenues presented in the table and in the discussion below represent revenues from sales of our oil and natural gas production volumes, and exclude the impact, if any, of hedging ineffectiveness. 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. Approximately 31% and 22% of our natural gas production was sold under these contracts during the nine months ended September 30, 2007 and 2006, respectively. Approximately 35% and 63%, respectively, of our oil production was sold under these contracts during the comparable periods. The realized prices below may differ from the market prices in effect during the periods depending on when the fixed price delivery contract was executed.

	Nine Months Ended September 30,						% Change in 2007 from 2006
	2007			2006
Production:
Natural gas (MMcf)		26,271			22,380		17	%
Oil and condensate (MBbls)		2,926			2,181		34	%
Total (MMcfe)		43,830			35,469		24	%
Revenues from production (in thousands):
Natural gas	$	216,628		$	160,739		35	%
Effects of cash flow hedges		917			2,479		(63	)%
Total	$	217,545		$	163,218		33	%
Oil and condensate	$	177,341		$	125,793		41	%
Effects of cash flow hedges		(1,320	)		(2,014	)	34	%
Total	$	176,021		$	123,779		42	%
Natural gas, oil and condensate	$	393,969		$	286,532		37	%
Effects of cash flow hedges		(403	)		465		(186	)%
Total	$	393,566		$	286,997		37	%

19

	Nine Months Ended September 30,						% Change in 2007 from 2006
	2007			2006
Average sales price per unit:
Natural gas (per Mcf)	$	8.25		$	7.18		15	%
Effects of cash flow hedges (per Mcf)		0.03			0.11		(73	)%
Total (per Mcf)	$	8.28		$	7.29		14	%
Oil and condensate (per Bbl)	$	60.60		$	57.66		5	%
Effects of cash flow hedges (per Bbl)		(0.45	)		(0.92	)	51	%
Total (per Bbl)	$	60.15		$	56.74		6	%
Natural gas, oil and condensate (per Mcfe)	$	8.99		$	8.08		11	%
Effects of cash flow hedges (per Mcfe)		(0.01	)		0.01		(200	)%
Total (per Mcfe)	$	8.98		$	8.09		11	%

Revenues from production increased 37% in the nine months ended September 30, 2007 compared to the same period in 2006. During the current period our production increased 24% from the comparative period in 2006 primarily due to greater production in the Gulf of Mexico from MC 711, and new production at the Canyon Express Hub and West Cameron 663, partially offset by production decline at High Island 74 and Eugene Island 281. The comparable revenues were impacted favorably by an overall 11% increase in our average sales price per Mcfe.

Lease Operating. Lease operating expenses for the nine months ended September 30, 2007 increased to $62.3 million ($1.42 per Mcfe) from $54.8 million ($1.55 per Mcfe) in the first nine months of 2006. The increase was primarily attributable to the production increases noted above and higher insurance premiums, partially offset by first half 2006 hurricane-related costs on certain of our oil and gas properties in the Gulf of Mexico. The decrease per unit of production was mainly attributable to increased production relative to fixed costs partially offset by increased overall operating costs. During the nine months ended September 30, 2007 and 2006, such costs included $2.8 million ($0.08 per Mcfe) and $4.0 million ($0.15 per Mcfe) of nonrecurring workover expenses.

Exploration. Exploration expense for the periods included geological and geophysical costs incurred in connection with evaluating oil and gas properties. Additionally, during the nine months ended September 30, 2007, exploration expense included costs related to an exploratory well at MC 667. This well found noncommercial quantities of hydrocarbons, resulting in exploration expense of approximately $10.3 million in the nine months ended September 30, 2007.

General and Administrative. General and administrative expense decreased to $23.0 million for the nine months ended September 30, 2007 compared to $23.2 million for the same period of 2006. Noncash stock-based compensation expense decreased to $5.1 million for the nine months ended September 30, 2007 compared to $8.7 million for the nine months ended September 30, 2006. This decrease was offset by an increase in other salary expense.

Depreciation, Depletion and Amortization. DD&A expense increased $44.1 million (38%) during the nine months ended September 30, 2007 to $159.6 million from $115.5 million for the same period in 2006. The overall DD&A expense increase was due primarily to the overall increased production. The average DD&A rate increased 12% to $3.64 per Mcfe in the nine months ended September 30, 2007 compared to $3.26 per Mcfe in the first nine months of 2006. This per unit increase is primarily a result of slightly higher costs incurred on our new developments relative to some of our older properties.

Impairment of oil and gas properties. We recorded impairment totaling $4.0 million and $5.8 million during the third and second quarters of 2007, respectively, related to properties in the Gulf of Mexico. These amounts represent the remaining carrying cost of those properties, and resulted from the well becoming nonproductive and surrender of a lease, respectively. We recorded an impairment of oil and gas properties in the first nine months of 2006 totaling $11.8 million related to certain producing properties acquired during 2005.

20

Accretion of asset retirement obligation. Accretion expense increased to $9.0 million for the nine months ended September 30, 2007 compared to $5.5 million for the same period of 2006 primarily due to the accretion associated with the new abandonment liabilities incurred late in 2006 and early in 2007.

Loss on Abandonment. During the third quarter of 2006 we recorded a $3.9 million loss on abandonment as we were unexpectedly required to abandon a Gulf of Mexico well with a drilling rig instead of the intended lower cost method originally estimated. During the same period in 2007 we recognized a loss of $0.4 million.

Interest Expense. Interest expense increased to $87.5 million for the nine months ended September 30, 2007 compared to $38.0 million for the same period of 2006 primarily due to the increase in borrowings under our term loans to $1.268 billion when last amended on March 23, 2007 and to the issuance of $210.0 million face value subordinated notes in September 2007. Partially offsetting this increase are $3.6 million of capitalized interest costs related to the construction of a floating production system at the Telemark Hub.

Other, net. During the third quarter of 2007, we recognized a foreign currency transaction gain of $1.8 million related to our deposits.

Income Taxes. We recorded a tax provision of $2.6 million during the nine months ended September 30, 2007, related to our foreign jurisdictions, based on the expected 2007 effective tax rate of each jurisdiction. The rates were determined based on the projected results of operations for the year, the valuation allowance released and permanent differences affecting the overall tax rate in each foreign jurisdiction. In the comparable period of 2006 we recorded a tax provision of $8.3 million related to our foreign jurisdictions. In the U.S., we recorded book income and book loss before taxes for the nine months ended September 30, 2007 and 2006, respectively; however, the resulting income tax provision and benefit were offset for the periods against our net deferred tax asset valuation allowance.

Liquidity and Capital Resources

Under the Existing Credit Agreement (as defined below), we have a $50.0 million revolving credit facility (“Revolver”), all of which was available as of September 30, 2007. At that date, we had working capital of approximately $36.0 million, a decrease of approximately $41.5 million from December 31, 2006. 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, 2007.

Historically, we have financed our acquisition and development activities through a combination of bank borrowings, proceeds from equity offerings, cash from operations and, occasionally, the sale on a promoted basis of interests in selected properties. We intend to continue to finance our near-term development projects utilizing these potential sources of capital. As operator of all 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 potential for available third-party capital will enable us to meet our future capital requirements.

Cash Flows

	Nine Months Ended
	September 30, 2007			September 30, 2006
Cash provided by (used in):
Operating activities	$	237,751		$	105,346
Investing activities		(622,797	)		(404,543	)
Financing activities		354,553			294,206

Cash provided by operating activities during the nine months ended September 30, 2007 and 2006 was $237.8 million and $105.3 million, respectively. Cash flow from operations increased due to higher oil and gas production revenues during the nine months ended September 30, 2007 compared to the first nine months of 2006. The increase in sales revenue was attributable to higher oil and gas production and higher average oil and gas prices during the nine months ended September 30, 2007. The increase in cash flows as a result of the increased revenues was partially offset by higher interest costs, the higher lease operating expense associated with increased production and by the timing of payments and receipts in our payables and receivables.

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Cash used in investing activities was $622.8 million and $404.5 million during the nine months ended September 30, 2007 and 2006, respectively. Cash expended in the Gulf of Mexico and North Sea was approximately $470.4 million and $166.2 million in the nine months ended September 30, 2007. Cash expended in the Gulf of Mexico and North Sea was approximately $257.9 million and $133.0 million, respectively, in the first nine months of 2006.

Cash provided by financing activities was $354.6 million and $294.2 million during the nine months ended September 30, 2007 and 2006, respectively. Such amount for the 2007 period was primarily due to the increase in our Term Loans and Subordinated Notes (as defined below) of $561.1 million (net of issuance costs), partially offset by the aggregate $208.5 million repayments of our second lien term loans and other debt and lease payments. Such amount for the 2006 period was primarily due to the increase in our Term Loans of $167.4 million (net of issuance costs) and the issuance of our 12.5% Series B Cumulative Preferred Stock for $145.5 million (net of issuance costs), partially offset by capital lease and debt payments.

Long-Term Debt

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

	September 30,			December 31,
	2007			2006
First Lien Term Loans	$	1,261,888		$	896,441
Second Lien Term Loans		—			175,000
Subordinated Notes (includes accreted premium of $383; excludes unamortized discount of $10,327)		200,056			—
Total		1,461,944			1,071,441
Less current maturities		(12,737	)		(8,987	)
Total long-term debt	$	1,449,207		$	1,062,454

On March 23, 2007 (the “Amendment Date”) ATP, Credit Suisse (as Administrative Agent and Collateral Agent for the lenders) and the lenders named therein entered into Amendment No. 1 and Agreement (the “Amendment”) amending the Third Amended and Restated Credit Agreement dated as of December 28, 2006 (as so amended, the “Existing Credit Agreement” or “Term Loans”).

As of the Amendment Date, we increased our aggregate borrowings by a net $200.0 million (from the aggregate balance outstanding as of December 31, 2006) to $1.268 billion. We borrowed additional amounts under terms and provisions (after giving effect to the amendments made to the Existing Credit Agreement on the Amendment Date) identical in all material respects to the existing first lien term loans as of the Amendment Date, in an aggregate principal amount of $375.0 million, all of the proceeds of which were or will be used by us (a) to pay fees and expenses incurred in connection with the Existing Credit Agreement in an aggregate amount of $8.4 million, (b) to repay in full all outstanding borrowings under the Second Lien Term Loan Facility, which had an original face amount of $175.0 million and bore interest at a rate of LIBOR plus 4.75%, and (c) from time to time solely for general corporate purposes, predominantly the development of the properties acquired to-date in 2007. Our net cash proceeds were $191.5 million. The interest rate on outstanding borrowings is based on LIBOR plus 3.5%, and at September 30, 2007 was approximately 9.49%.

The terms of the Existing Credit Agreement require us to maintain certain covenants. Capitalized terms are defined in the Existing Credit Agreement. The covenants include:

• 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 to Net Debt of at least 0.5 to 1.0 at September 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 3.0 to 1.0 at September 30 or December 31 of any fiscal year;

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• Commodity Hedging Agreements, based on forecasted production attributable to our proved producing reserves and calculated on a twelve rolling month basis, of (i) not less than 60% during the year subsequent to measurement, and (ii) not less than 40% during the second year subsequent to measurement;

• limit during any fiscal year Permitted Business Investments, as defined, to $150.0 million or 7.5% of PV-10 value of our total proved reserves.

The foregoing description of the Existing Credit Agreement does not purport to be complete and is qualified in its entirety by reference to Amendment No. 1 filed as an exhibit to our current report on Form 8-K, dated March 23, 2007, and incorporated by reference herein. In addition, capitalized terms used but not defined in the foregoing description have the respective meanings assigned to such terms in the Existing Credit Agreement.

As of September 30, 2007, we were in compliance with all of the financial covenants of the Existing Credit Agreement. Significant adverse changes in our expected production levels, commodity prices and reserves or material delays or cost overruns could have a material adverse affect on our financial condition and results of operations and result in our noncompliance with these covenants. An event of noncompliance with any of the required covenants could result in a material mandatory repayment under the Existing Credit Agreement.

During September 2007, the Company, Credit Suisse (as Administrative Agent for the lenders) and the lenders named therein entered into an Unsecured Subordinated Credit Agreement (the “Subordinated Notes”) for aggregate borrowings of $210.0 million. The borrowings bear interest at 11.25%, payable quarterly, and mature in September 2011. Such borrowings are subordinated to the borrowings under the Existing Credit Agreement and may be prepaid at any time at the option of the Company, subject to limitations set forth in the Existing Credit Agreement. The Company has assumed that debt will be paid off at maturity and accordingly recognizes over the term of the facility additional noncash interest expense related to deferred financing costs, an original issue discount and a sliding-scale redemption premium. If held to maturity, the aggregate average effective interest rate on the Subordinated Notes is approximately 15.3%. The Company received net proceeds from the issuance of the Subordinated Notes of $193.8 million after deducting $16.2 million for the original issue discount, fees and expenses. The foregoing description of the Subordinated Notes does not purport to be complete and is qualified in its entirety by reference to the Unsecured Subordinated Credit Agreement dated as of September 7, 2007 (as amended on September 14, 2007) filed as exhibits to our current reports on Form 8-K dated September 7 and 14, 2007, and incorporated by reference herein.

The proceeds of the Subordinated Notes will be used to fund near-term development and acquisition opportunities and other general corporate purposes of the Company and its subsidiaries. The Subordinated Notes contain no financial performance covenants, but contain affirmative and negative covenants, including limitations on incurring certain indebtedness, that are usual and customary for transactions of this type. As of September 30, 2007, we were in compliance with all of the financial covenants of the Subordinated Notes.

Commitments and Contingencies

In preparing financial statements at any point in time, management is periodically faced with uncertainties, the outcomes of which are not within its control and will not be known for prolonged periods of time. As discussed in Note 11 to the Consolidated Financial Statements, we are involved in actions from time to time, which if determined adversely, could have a material negative impact on our financial position, results of operations and cash flows. Management, with the assistance of counsel makes estimates, if determinable, of ATP’s probable liabilities and records such amounts in the consolidated financial statements. Such estimates may be the minimum amount of a range of probable loss when no single best estimate is determinable. Disclosure is made, when determinable, of any additional possible amount of loss on these claims, or if such estimate cannot be made, that fact is disclosed. Along with our counsel, we monitor developments related to these legal matters and, when appropriate, we make adjustments to recorded liabilities to reflect current facts and circumstances. Although it is difficult to predict the ultimate outcome of these matters, management is not aware of any amounts that need to be recorded and believes that the recorded amounts, if any, are reasonable.

Accounting Pronouncements

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

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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 2006 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. Changes in interest rates affect the interest earned on our cash and cash equivalents and the interest rate paid on borrowings under the Term Loans. See the discussion of our Term Loans in Note 6 to the consolidated financial statements. Under our current policies, we do not use interest rate derivative instruments to manage exposure to interest rate changes.

Foreign Currency Risk

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

In July 2007, we entered into a foreign currency swap agreement which locks in a $2.049 USD/GBP exchange rate for £33.0 million during the period from October 2007 to March 2008.

Commodity Price Risk

Our revenues, profitability and future growth depend substantially on prevailing prices for oil and gas. Prices also affect the amount of cash flow available for capital expenditures and our ability to borrow and raise additional capital. Lower prices may also reduce the amount of oil and gas that we can economically produce. We currently sell a portion of our oil and gas production under price sensitive or market price contracts. We periodically use derivative instruments to hedge our commodity price risk. We hedge a portion of our projected oil and gas production through a variety of financial and physical arrangements intended to support oil and gas prices at targeted levels and to manage our exposure to price fluctuations. We may use futures contracts, swaps and fixed price physical contracts to hedge our commodity prices. Realized gains and losses from our price risk management activities are recognized in oil and gas sales when the associated production occurs. For derivatives designated as cash flow hedges, the unrecognized gains and losses are included as a component of other comprehensive income (loss) to the extent the hedge is effective. See Note 10 to the Consolidated Financial Statements for additional information. We do not hold or issue derivative instruments for speculative purposes.

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

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Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

In order to ensure that the information we must disclose in our filings with the Securities and Exchange Commission is recorded, processed, summarized, and reported on a timely basis, we have formalized our 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, 2007 (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 as appropriate to allow timely decisions regarding required disclosure.

Changes in Internal Control Over Financial Reporting

During the three months ended September 30, 2007, 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.

Item 4T is not applicable and has been omitted.

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 2006 Annual Report on Form 10-K.

PART II. OTHER INFORMATION

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

Item 5. Other Information

On November 5, 2007, we announced the retirement of Gerald W. Schlief, Sr. Vice President of the Corporation. Mr. Schlief’s retirement will be effective December 31, 2007.

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.

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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	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.
10.2	Third Amended and Restated Credit Agreement dated December 28, 2006 among ATP, the Lenders named therein and Credit Suisse (“CS”), as administrative and collateral agent, incorporated by reference to Exhibit 10.2 of ATP’s Form 10-K for the year ended December 31, 2006.
10.3	Unsecured Subordinated Credit Agreement dated as of September 7, 2007 (as amended on September 14, 2007), among ATP Oil & Gas Corporation, the lenders from time to time party thereto and CS, as administrative agent for such lenders, incorporated by reference to Exhibit 10.1 of ATP’s Form 8-K filed on September 7, 2007 and Exhibit 10.1 of ATP’s Form 8-K filed on September 14, 2007.
†10.4	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.
†10.5	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.
†10.6	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.
†10.7	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.
†10.8	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.
†10.9	Employment Agreement between ATP and Gerald W. Schlief, dated December 29, 2005, incorporated by reference to Exhibit 10.6 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.
†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.
*31.1	Certification of Chief Executive Officer pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934.
*31.2	Certification of Chief Financial Officer pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934.
*32.1	Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350.
*32.2	Certification of Chief 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 8, 2007	By:	/s/ Albert L. Reese, Jr.
		Albert L. Reese, Jr.
		Chief Financial Officer

27

EX-31.1

EXHIBIT 31.1

ATP OIL & GAS CORPORATION

Section 302 Certification of Principal Executive Officer

I, T. Paul Bulmahn, Chief Executive Officer and President (Principal Executive Officer) certify that:

1. I have reviewed this Form 10-Q for the nine month period ended September 30, 2007 of ATP Oil & Gas Corporation;

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

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

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

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

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: November 8, 2007	/s/ T. Paul Bulmahn
	CEO & President

EX-31.2

EXHIBIT 31.2

ATP OIL & GAS CORPORATION

Section 302 Certification of Principal Financial Officer

I, Albert L. Reese, Jr., Chief Financial Officer (Principal Financial Officer) certify that:

1. I have reviewed this Form 10-Q for the nine month period ended September 30, 2007 of ATP Oil & Gas Corporation;

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

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

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

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

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: November 8, 2007	/s/ Albert L. Reese, Jr.
	Chief Financial Officer

EX-32.1

Exhibit 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

I, T. Paul Bulmahn, Chairman and Chief Executive Officer of ATP Oil & Gas Corporation (the “Company”), do hereby certify that the Quarterly Report on Form 10-Q (the “Report”) for the nine months ended September 30, 2007, filed with the Securities Exchange Commission on the date hereof:

1) fully complies with the requirements of section 13 (a) or 15 (d) of the Securities Exchange Act of 1934; and

2) the information contained in the Report fairly represents, in all material respects, the financial condition and the results of operations of the Company.

Date: November 8, 2007	By:	/s/ T. Paul Bulmahn
		T. Paul Bulmahn
		Chairman, Chief Executive Officer and President

EX-32.2

Exhibit 32.2

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

I, Albert L. Reese, Jr., Chief Financial Officer of ATP Oil & Gas Corporation (the “Company”), do hereby certify that the Quarterly Report on Form 10-Q (the “Report”) for the nine months ended September 30, 2007, filed with the Securities Exchange Commission on the date hereof:

1) fully complies with the requirements of section 13 (a) or 15 (d) of the Securities Exchange Act of 1934; and

2) the information contained in the Report fairly represents, in all material respects, the financial condition and the results of operations of the Company.

Date: November 8, 2007	By:	/s/ Albert L. Reese, Jr.
		Albert L. Reese, Jr.
		Chief Financial Officer