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 June 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 August 3, 2007, was 30,360,258.

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

TABLE OF CONTENTS

	Page
PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS (Unaudited)
Consolidated Balance Sheets: June 30, 2007 and December 31, 2006	3
Consolidated Statements of Operations: For the three and six months ended June 30, 2007 and 2006	4
Consolidated Statements of Cash Flows: For the six months ended June 30, 2007 and 2006	5
Consolidated Statements of Comprehensive Income: For the three and six months ended June 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	15
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS	22
ITEM 4. CONTROLS AND PROCEDURES	22
PART II. OTHER INFORMATION	23

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)

	June 30, 2007			December 31, 2006
Assets
Current assets:
Cash and cash equivalents	$	132,602		$	182,592
Restricted cash		28,122			27,497
Accounts receivable (net of allowance of $382 and $409, respectively)		73,560			105,030
Deferred tax asset		1,259			1,113
Derivative asset		5,310			1,170
Other current assets		8,401			9,931
Total current assets		249,254			327,333
Oil and gas properties (using the successful efforts method of accounting)
Proved properties		1,941,707			1,483,163
Unproved properties		69,229			56,189
		2,010,936			1,539,352
Less: Accumulated depletion, impairment and amortization		(557,095	)		(443,707	)
Oil and gas properties, net		1,453,841			1,095,645
Furniture and fixtures (net of accumulated depreciation)		1,013			1,079
Deferred tax asset		1,417			–
Derivative asset		5,902			–
Deferred financing costs, net		18,579			13,272
Other assets, net		7,230			9,729
Total assets	$	1,737,236		$	1,447,058
Liabilities and Shareholders’ Equity
Current liabilities:
Accounts payable and accruals	$	220,678		$	195,846
Current maturities of long-term debt		12,737			8,987
Current maturities of long-term capital lease		–			23,699
Asset retirement obligation		17,064			21,297
Other current liabilities		23,668			–
Total current liabilities		274,147			249,829
Long-term debt		1,252,335			1,062,454
Asset retirement obligation		104,551			87,092
Deferred tax liability		19,843			11,765
Other long-term liabilities		3,468			–
Total liabilities		1,654,344			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; 30,420,348 issued and 30,344,508 outstanding at June 30, 2007; 30,272,210 issued and 30,196,370 outstanding at December 31, 2006		30			30
Additional paid-in capital		155,853			151,467
Accumulated deficit		(107,122	)		(140,681	)
Accumulated other comprehensive income		35,042			26,013
Treasury stock		(911	)		(911	)
Total shareholders’ equity		82,892			35,918
Total liabilities and shareholders’ equity	$	1,737,236		$	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						Six Months Ended
	June 30, 2007			June 30, 2006			June 30, 2007			June 30, 2006
Revenues:
Oil and gas production	$	132,153		$	108,885		$	276,902		$	154,130
Other revenues		–			–			1,598			–
		132,153			108,885			278,500			154,130
Costs and operating expenses:
Lease operating		20,105			21,259			41,174			31,952
Exploration		10,605			367			11,336			508
General and administrative		6,572			7,375			15,340			15,360
Depreciation, depletion and amortization		52,612			43,249			106,012			60,519
Impairment of oil and gas properties		5,770			–			5,770			–
Accretion of asset retirement obligation		3,020			1,671			5,980			3,218
Loss on abandonment		2			3,451			79			3,506
		98,686			77,372			185,691			115,063
Income from operations		33,467			31,513			92,809			39,067
Other income (expense):
Interest income		2,550			1,207			4,618			1,780
Interest expense		(31,025	)		(12,097	)		(57,824	)		(23,269	)
		(28,475	)		(10,890	)		(53,206	)		(21,489	)
Income before income taxes		4,992			20,623			39,603			17,578
Income tax (expense) benefit:
Current		22			(1,841	)		(34	)		(1,841	)
Deferred		1,111			(1,422	)		(6,010	)		(1,422	)
		1,133			(3,263	)		(6,044	)		(3,263	)
Net income		6,125			17,360			33,559			14,315
Preferred stock dividends		–			(10,986	)		–			(17,804	)
Net income (loss) available to common shareholders	$	6,125		$	6,374		$	33,559		$	(3,489	)
Net income (loss) per common share:
Basic	$	0.20		$	0.21		$	1.12		$	(0.12	)
Diluted		0.20			0.21			1.10			(0.12	)
Weighted average number of common shares:
Basic		30,058			29,715			30,031			29,576
Diluted		30,639			30,396			30,612			29,576

See accompanying notes to consolidated financial statements.

4

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In Thousands)

(Unaudited)

	Six Months Ended
	June 30, 2007			June 30, 2006
Cash flows from operating activities
Net income	$	33,559		$	14,315
Adjustments to reconcile net income to net cash provided by operating activities –
Depreciation, depletion and amortization		106,012			60,519
Impairment of oil and gas properties		5,770			–
Accretion of asset retirement obligation		5,980			3,218
Deferred income taxes		6,010			1,422
Dry hole costs		10,251			–
Amortization of deferred financing costs		3,138			2,341
Stock-based compensation		3,245			5,526
Ineffectiveness of cash flow hedges		(309	)		(28	)
Other noncash items		1,439			3,801
Changes in assets and liabilities –
Accounts receivable and other current assets		32,538			(20,779	)
Accounts payable and accruals		(26,828	)		(19,676	)
Other assets		(3,276	)		(4,072	)
Net cash provided by operating activities		177,529			46,587
Cash flows from investing activities
Additions and acquisitions of oil and gas properties		(389,972	)		(203,445	)
Additions to furniture and fixtures		(207	)		(250	)
Decrease in restricted cash		1			129
Net cash used in investing activities		(390,178	)		(203,566	)
Cash flows from financing activities
Proceeds from long-term debt		375,000			178,500
Payments of long-term debt		(181,369	)		(875	)
Deferred financing costs		(8,445	)		(11,116	)
Issuance of preferred stock, net of issuance costs		–			145,463
Payments of capital lease		(23,950	)		(20,869	)
Exercise of stock options		1,140			4,231
Net cash provided by financing activities		162,376			295,334
Effect of exchange rate changes on cash		283			(1,112	)
Increase (decrease) in cash and cash equivalents		(49,990	)		137,243
Cash and cash equivalents, beginning of period		182,592			65,566
Cash and cash equivalents, end of period	$	132,602		$	202,809

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						Six Months Ended
	June 30, 2007			June 30, 2006			June 30, 2007			June 30, 2006
Net income	$	6,125		$	17,360		$	33,559		$	14,315
Other comprehensive income, net of tax:
Reclassification adjustment for settled hedge contracts (net of income tax of $0)		182			727			1,637			2,009
Change in fair value of outstanding hedge positions (net of income tax of $0)		(1,206	)		(796	)		(2,151	)		(4,346	)
Foreign currency translation adjustment		8,705			8,864			9,543			10,782
Other comprehensive income		7,681			8,795			9,029			8,445
Comprehensive income	$	13,806		$	26,155		$	42,588		$	22,760

See accompanying notes to consolidated financial statements.

6

ATP OIL & GAS CORPORATION AN D 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 six months ended June 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

In June 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.

During September 2006, the FASB issued Statement of Financial Accounting Standards (“SFAS”) No. 157. 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. Adoption of this guidance did not materially impact 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 established 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 will 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 AN D SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

recoverable, and that future expectations about income are overshadowed by such history of losses. As of June 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 United Kingdom is 84.7% and in the Netherlands is 33.2% and 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 non-deductible interest expense and property basis differences. Year to date, we recorded taxes resulting in a worldwide effective tax rate of 15.3%.

We adopted FIN No. 48, effective January 1, 2007, as discussed in Note 2 above. The adoption of FIN No. 48 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 and in 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 interest and penalties, if any, 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 June 30, 2007, the amount of the uncertain tax position is $3.7 million, which is the difference between the tax filing position and the amounts provided for in the 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 ending June 30, 2007 and 2006 (in thousands):

	Six Months Ended
	June 30, 2007			June 30, 2006
Asset retirement obligation at beginning of period	$	108,389		$	67,364
Liabilities incurred		13,278			22,996
Liabilities settled		(6,766	)		(857	)
Accretion		5,980			3,218
Foreign currency translation		734			657
Asset retirement obligation at end of period	$	121,615		$	93,378

Note 5 — Supplemental Disclosures of Cash Flow Information

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

	Six Months Ended
	June 30, 2007		June 30, 2006
Cash paid during the period for interest	$	51,072	$	16,975
Cash paid during the period for income taxes		1,825		–

During the first half of 2007 we acquired two oil and gas properties, a significant portion of the consideration for which was noncash. See Note 7.

Note 6 — Long-Term Debt

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

	June 30, 2007		December 31, 2006
First Lien Term Loans	$	1,265,072	$	896,441

8

ATP OIL & GAS CORPORATION AN D SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Second Lien Term Loans		–			175,000
Total		1,265,072			1,071,441
Less current maturities		(12,737	)		(8,987	)
Total long-term debt	$	1,252,335		$	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 or will be 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 June 30, 2007 was approximately 9.22%.

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

As of June 30, 2007, we were in compliance with all of the financial covenants of our 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 non-compliance with these covenants. An event of non-compliance with any of the required covenants could result in a material mandatory repayment under the Existing Credit Agreement.

Note 7 — Oil and Gas Properties

Acquisitions

On January 8, 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. ATP is the operator of Canyon Express. On January 23, 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 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 $23.7 million as of June 30, 2007.

Impairment

We recorded an impairment of oil and gas properties for second quarter of 2007 totaling $5.8 million related to one property in the Gulf of Mexico. This amount represents the remaining carrying cost of that property, and was the result of the surrender of the lease.

9

ATP OIL & GAS CORPORATION AN D SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 8 — Stock–Based Compensation

We recognized stock option compensation expense of approximately $0.3 million and $0.7 million for the three months and six months ended June 30, 2007, respectively. We recognized stock option compensation expense of approximately $0.8 million and $1.0 million for the three months and six months ended June 30, 2006, respectively. The weighted average grant-date fair value of options granted during the six months ended June 30, 2007 and 2006 was $16.26 and $16.30, 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				Six Months Ended
	June 30, 2007		June 30, 2006		June 30, 2007		June 30, 2006
Weighted average volatility	36	%	55	%	36	%	51	%
Expected term (in years)	3.8		4.3		3.8		4.3
Risk-free rate	4.9	%	4.9	%	4.9	%	4.6	%

The following table sets forth a summary of option transactions for the six-month period ended June 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	18,000			48.38
Exercised	(72,251	)		15.78
Forfeited	(20,251	)		29.49
Outstanding at end of period	619,349			26.34	$	13,813	3.16
Vested and expected to vest	572,846			26.36		12,766	3.11
Options exercisable at end of period	101,611			28.02		2,095	3.17

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

At June 30, 2007, unrecognized compensation expense related to nonvested stock option grants totaled $1.9 million. Such unrecognized expense will be recognized as vesting occurs over the weighted average remaining vesting period of 2.3 years.

During the three and six months ended June 30, 2007, we recognized aggregate compensation expense of $1.4 million and $2.6 million, respectively, related to all of our outstanding restricted stock grants. The following table sets forth the restricted stock transactions for the six-month period ended June 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	75,887			42.09
Vested	(64,654	)		40.95
Nonvested at end of period	244,735			38.52	$	11,904

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

10

ATP OIL & GAS CORPORATION AN D SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

At June 30, 2007, unrecognized compensation expense related to restricted stock totaled $4.7 million. Such unrecognized expense will be recognized as vesting occurs over the weighted average remaining vesting period of 1.8 years.

Note 9 — Earnings Per Share

Basic earnings per share 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 earnings per share 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 ended June 30, 2007 and 2006, stock-based awards for 25,250 and no average shares, respectively, of common stock were excluded from the diluted EPS calculation because their inclusion would have been antidilutive. For the six months ended June 30, 2007 and 2006, stock-based awards for 30,250 and 726,000 average shares, respectively, of common stock 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					Six Months Ended
	June 30, 2007		June 30, 2006			June 30, 2007		June 30, 2006
Income
Net income	$	6,125	$	17,360		$	33,559	$	14,315
Less preferred dividends		–		(10,986	)		–		(17,804	)
Net income (loss) available to common shareholders	$	6,125	$	6,374		$	33,559	$	(3,489	)
Shares outstanding
Weighted average shares outstanding—basic		30,058		29,715			30,031		29,576
Effect of potentially dilutive securities—stock options and warrants		467		565			465		–
Nonvested restricted stock		114		116			116		–
Weighted average shares outstanding—diluted		30,639		30,396			30,612		29,576
Net income (loss) per common share:
Basic	$	0.20	$	0.21		$	1.12	$	(0.12	)
Diluted		0.20		0.21			1.10		(0.12	)

Note 10 — Derivative Instruments and Risk Management Activities

At June 30, 2007 and December 31, 2006, Accumulated Other Comprehensive Income included $1.5 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 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. These deferrals will be reversed during the period in which the forecasted transactions actually occur.

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

Area	Period	Type	Volumes	Floor Price		Net Fair Value Asset (Liability)
				$/Unit		($000)
Oil (Bbls)
Gulf of Mexico	2007	Puts	184,000	$	60.00	$	120
Gulf of Mexico	2008	Puts	2,488,800		54.67		4,152

11

ATP OIL & GAS CORPORATION AN D SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Gulf of Mexico	2009	Puts	1,496,500		54.00		3,374
Natural Gas (MMBtu)
North Sea	2007	Swaps	1,840,000	$	6.01	$	3,566
North Sea	2008	Swaps	1,104,000		7.38		(894	)
North Sea	2009	Swaps	1,080,000		7.38		(2,574	)

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

At June 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	6,388,000	$	8.37
2008	13,188,000		8.30
2009	8,175,000		8.04
North Sea:
2007	6,440,000	$	9.04
2008	16,460,000		7.92
2009	2,700,000		8.15
Oil (Bbl) – Gulf of Mexico:
2007	791,200	$	70.90
2008	1,098,000		70.76
2009	730,000		66.23

(1) Includes the effect of basis differentials.

We entered into a foreign currency swap agreement on July 26, 2007. The agreement locks in a $2.049 USD/GBP exchange rate for £33.0 million during the period from October 2007 to March 2008.

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, the company lost potential revenues due to shut-in production resulting from the storms. The company maintains property casualty insurance for such physical damages and loss-of-production insurance to replace lost cash flows resulting from downtime in excess of ninety days after the event. The company has submitted claims for the insured damages and any recoveries available under the loss-of-production income (“LOPI”) insurance policy. At June 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 six months of 2007 ($5.6 million was realized from the policy in the second half of 2006). 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.

We are a party to a multi-year (life of reserves) firm transportation agreement covering certain production in the U.K. that require 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

12

ATP OIL & GAS CORPORATION AN D SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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 June 30, 2007, our aggregate exposure under such arrangements totaled approximately $37.8 million, and included net profits interests payable, including accrued interest, of approximately $23.7 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

The Company’s operations are focused in the Gulf of Mexico and in the North Sea. Management reviews and evaluates the operations separately 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. The Company evaluates the segments based on income (loss) from operations. Segment activity for the three months and six months ended June 30, 2007 and 2006 is as follows (in thousands):

	Gulf of Mexico		North Sea			Eliminations			Total
For the Three Months Ended –
June 30, 2007:
Revenues	$	121,261	$	10,892		$	–		$	132,153
Depreciation, depletion and amortization		46,097		6,515			–			52,612
Impairment of oil and gas properties		5,770		–			–			5,770
Income from operations		34,379		(912	)		–			33,467
Interest income		6,629		592			(4,671	)		2,550
Interest expense		31,026		4,670			(4,671	)		31,025
Income tax benefit		–		1,133			–			1,133
Additions to oil and gas properties		165,371		63,668			–			229,039
June 30, 2006:
Revenues	$	86,111	$	22,774		$	–		$	108,885
Depreciation, depletion and amortization		31,478		11,771			–			43,249
Income from operations		26,140		5,373			–			31,513
Interest income		1,029		140			38			1,207
Interest expense		11,971		88			38			12,097
Income tax expense		–		3,263			–			3,263
Additions to oil and gas properties		108,167		58,876			–			167,043

	Gulf of Mexico		North Sea		Eliminations			Total
For the Six Months Ended –
June 30, 2007:
Revenues	$	229,384	$	49,116	$	–		$	278,500
Depreciation, depletion and amortization		83,915		22,097		–			106,012
Impairment of oil and gas properties		5,770		–		–			5,770
Income from operations		78,258		14,551		–			92,809
Interest income		11,282		1,101		(7,765	)		4,618

13

ATP OIL & GAS CORPORATION AN D SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Interest expense		57,824		7,765		(7,765	)		57,824
Income tax expense		–		6,044		–			6,044
Total assets		1,210,259		526,977		–			1,737,236
Additions to oil and gas properties		359,374		122,463		–			481,837
June 30, 2006:
Revenues	$	125,584	$	28,546	$	–		$	154,130
Depreciation, depletion and amortization		46,518		14,001		–			60,519
Income from operations		32,515		6,552		–			39,067
Interest income		1,482		298		–			1,780
Interest expense		23,143		126		–			23,269
Income tax expense		–		3,263		–			3,263
Total assets		901,218		300,652		–			1,201,870
Additions to oil and gas properties		171,018		92,102		–			263,120

14

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 (“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 these reservoirs 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 / 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 non-core or non-strategic 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.

Second Quarter 2007 Highlights

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

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• Achieved quarterly production of 160.3 MMcfe per day resulting in revenue of $132.2 million;

• Achieved net income of $6.1 million or $0.20 per basic and diluted share;

• Drilled and completed Wenlock W1 well in the U.K. sector North Sea with a company record 3,900’ horizontal completion;

• Placed two wells on production at Ship Shoal 351 in the Gulf of Mexico and expanded the development plan to include two additional extension wells;

• Commenced activities to increase throughput capacity of Gomez Hub to approximately 220 MMcfe per day, gross;

• Began the tie-in of the fourth and fifth wells at our Gomez Hub.

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

For the three months ended June 30, 2007, we reported net income available to common shareholders of $6.1 million, or $0.20 per basic and diluted share on total revenue of $132.2 million, as compared with a net income available to common shareholders of $6.4 million, or $0.21 per basic and diluted share, on total revenue of $108.9 million for the three months ended June 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 38% and 25% of our natural gas production was sold under these contracts during the three months ended June 30, 2007 and 2006, respectively. Approximately 37% and 13% 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 June 30,						% Change in 2007 from 2006
	2007			2006
Production:
Natural gas (MMcf)		8,426			8,621		(2	)%
Oil and condensate (MBbls)		1,027			816		26	%
Total (MMcfe)		14,590			13,518		8	%
Revenues from production (in thousands):
Natural gas	$	68,419		$	61,738		11	%
Effects of cash flow hedges		1,035			(879	)	218	%
Total	$	69,454		$	60,859		14	%
Oil and condensate	$	62,692		$	48,018		31	%
Effects of cash flow hedges		(227	)		–		–
Total	$	62,465		$	48,018		30	%
Natural gas, oil and condensate	$	131,111		$	109,756		19	%
Effects of cash flow hedges		808			(879	)	192	%
Total	$	131,919		$	108,877		21	%
Average sales price per unit:
Natural gas (per Mcf)	$	8.12		$	7.16		13	%
Effects of cash flow hedges (per Mcf)		0.12			(0.10	)	220	%
Total (per Mcf)	$	8.24		$	7.06		17	%
Oil and condensate (per Bbl)	$	61.02		$	58.85		4	%
Effects of cash flow hedges (per Bbl)		(0.22	)		–		–
Total (per Bbl)	$	60.80		$	58.85		3	%
Natural gas, oil and condensate (per Mcfe)	$	8.99		$	8.12		11	%
Effects of cash flow hedges (per Mcfe)		0.06			(0.07	)	186	%
Total (per Mcfe)	$	9.05		$	8.05		12	%

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Revenues from production increased 21% in the second quarter of 2007 compared to the same period in 2006. During the second quarter of 2007, production increased 8% from the comparative period in 2006 due to greater production in the Gulf of Mexico from Mississippi Canyon (“MC”) 711 (Gomez), Canyon Express Hub and Garden Banks (“GB”) 409, partially offset by production declines at High Island (“HI”) 74 and temporary shut-ins at Ship Shoal 351/358 experienced during development and completion operations. Production declined at L-06 in the Dutch sector North Sea as a result of increased water production, and production from Tors in the U.K. sector North Sea was temporarily curtailed due to unfavorable market prices for natural gas. The comparable revenues were impacted favorably by an overall 12% increase in our average realized sales price including the effect of hedges per equivalent Mcf.

Lease Operating. Lease operating expenses for the second quarter of 2007 decreased to $20.1 million ($1.38 per Mcfe) from $21.3 million ($1.57 per Mcfe) in the second quarter of 2006. The 2006 period included hurricane-related costs on certain of our oil and gas properties in the Gulf of Mexico. The 2007 period included increased costs primarily attributable to the production gains noted above, higher insurance premiums and an increase in chemical cost as a result of methanol use at our newly acquired Canyon Express Pipeline interests. The decrease per unit of production was mainly attributable to increased production, partially offset by increased costs.

Exploration. Exploration expense for the periods included geological and geophysical costs incurred in connection with evaluating oil and gas properties. Additionally, during the second quarter of 2007, exploration expense included costs related to an exploratory well at MC 667 which was drilled across a fault from existing proved reserves at our MC 711 Block. This well found non-commercial quantities of hydrocarbons, resulting in exploration expense of approximately $10.3 million in the second quarter of 2007.

General and Administrative. General and administrative expense decreased 11% to $6.6 million for the second quarter of 2007 compared to $7.4 million for the same period of 2006, primarily due to lower noncash employee compensation related charges and professional fees, partially offset by higher general office costs. Noncash stock-based compensation expense was $1.7 million and $3.3 million for the three months ended June 30, 2007 and 2006, respectively.

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization (“DD&A”) expense increased $9.4 million (22%) during the second quarter of 2007 to $52.6 million from $43.2 million for the same period in 2006. The overall DD&A expense increase was primarily due to the overall increased production. The average DD&A rate increased 13% to $3.61 per Mcfe in the second quarter of 2007 compared to $3.20 per Mcfe in the same quarter 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. We recorded an impairment of oil and gas properties for second quarter of 2007 totaling $5.8 million related to one property in the Gulf of Mexico. This amount represents the remaining carrying cost of that property, and was the result of the surrender of the lease.

Accretion. Accretion expense increased to $3.0 million for the second quarter of 2007 compared to $1.7 million for the same period of 2006, primarily due to accretion associated with new abandonment liabilities incurred late in 2006 and early 2007.

Loss on Abandonment. During the second quarter of 2006 we recorded a $3.5 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.

Interest Expense. Interest expense increased to $31.0 million for the second quarter of 2007 compared to $12.1 million for the same period of 2006, primarily due to the increase in borrowing under our term loans to $1.268 billion when last amended on March 23, 2007.

Income Taxes. We recorded a net tax benefit of $1.1 million during the quarter ended June 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

17

foreign jurisdiction. In the comparable quarter of 2006 we recorded a tax provision of $3.3 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.

Six Months Ended June 30, 2007 Compared to Six Months Ended June 30, 2006

For the six months ended June 30, 2007, we reported net income available to common shareholders of $33.6 million, or $1.12 per basic share and $1.10 per diluted share on total revenue of $278.5 million as compared with a net loss available to common shareholders of $3.5 million, or $0.12 per share, on total revenue of $154.1 million for the six months ended June 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 30% our natural gas production was sold under these contracts during the six months ended June 30, 2007 and 2006. Approximately 34% and 22%, 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.

	Six Months Ended June 30,						% Change in 2007 from 2006
	2007			2006
Production:
Natural gas (MMcf)		18,250			13,654		34	%
Oil and condensate (MBbls)		2,039			966		111	%
Total (MMcfe)		30,486			19,452		57	%
Revenues from production (in thousands):
Natural gas	$	158,352		$	100,694		57	%
Effects of cash flow hedges		1,035			(1,329	)	178	%
Total	$	159,387		$	99,365		60	%
Oil and condensate	$	118,295		$	54,737		116	%
Effects of cash flow hedges		(1,089	)		–		–
Total	$	117,206		$	54,737		114	%
Natural gas, oil and condensate	$	276,647		$	155,431		78	%
Effects of cash flow hedges		(54	)		(1,329	)	96	%
Total	$	276,593		$	154,102		79	%
Average sales price per unit:
Natural gas (per Mcf)	$	8.68		$	7.37		18	%
Effects of cash flow hedges (per Mcf)		0.06			(0.10	)	160	%
Total (per Mcf)	$	8.74		$	7.28		20	%
Oil and condensate (per Bbl)	$	58.01		$	56.64		2	%
Effects of cash flow hedges (per Bbl)		(0.53	)		–		–
Total (per Bbl)	$	57.48		$	56.64		1	%
Natural gas, oil and condensate (per Mcfe)	$	9.07		$	7.99		14	%
Effects of cash flow hedges (per Mcfe)		–			(0.07	)	100	%
Total (per Mcfe)	$	9.07		$	7.92		15	%

Revenues from production increased 79% in the first half of 2007 compared to the same period in 2006. During the current period our production increased 57% from the comparative period in 2006 due to greater production in the Gulf of Mexico from MC 711, GB 142 Hub and GB 409, partially offset by production declines at HI 74 and temporary shut-ins at Canyon Express Hub. Production increased in the U.K. sector North Sea during the six months ended June 30, 2007 compared to the same period of the prior year due to new production from Tors, and declined at L-06 in the Dutch sector North Sea. The comparable revenues were impacted favorably by an overall 15% increase in our average sales price per Mcfe.

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Lease Operating. Lease operating expenses for the first half of 2007 increased to $41.2 million ($1.35 per Mcfe) from $32.0 million ($1.64 per Mcfe) in the first half 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 partially offset by increased costs.

Exploration. Exploration expense for the periods included geological and geophysical costs incurred in connection with evaluating oil and gas properties. Additionally, during the first half of 2007, exploration expense included costs related to an exploratory well at MC 667. This well found non-commercial quantities of hydrocarbons, resulting in exploration expense of approximately $10.3 million in the first half of 2007.

General and Administrative. General and administrative expense decreased to $15.3 million for the first half of 2007 compared to $15.4 million for the same period of 2006. The slight decrease was primarily attributable to lower noncash employee compensation related charges, virtually offset by increased professional and consulting fees related to development activity incurred in the first half of 2007. Noncash stock-based compensation expense was $3.2 million and $5.5 million for the six months ended June 30, 2007 and 2006, respectively.

Depreciation, Depletion and Amortization. DD&A expense increased $45.5 million (75%) during the first half of 2007 to $106.0 million from $60.5 million for the same period in 2006. The overall DD&A expense increase was due to the overall increased production. The average DD&A rate increased 12% to $3.48 per Mcfe in the first half of 2007 compared to $3.11 per Mcfe in the first half 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. We recorded an impairment of oil and gas properties for first half of 2007 totaling $5.8 million related to one property in the Gulf of Mexico. This amount represents the entire carrying cost of that property, and was the result of the surrender of the lease.

Accretion. Accretion expense increased to $6.0 million for the first half of 2007 compared to $3.2 million for the same period of 2006 primarily due to the accretion associated with the new abandonment liabilities incurred late in 2006 and early 2007.

Loss on Abandonment. During the second quarter of 2006 we recorded a $3.5 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.

Interest Expense. Interest expense increased to $57.8 million for the first half of 2007 compared to $23.3 million for the same period of 2006 primarily due to the increase in borrowing under our term loans to $1.268 billion when last amended on March 23, 2007.

Income Taxes. We recorded a tax provision of $6.0 million during the six months ended June 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 $3.3 million related to our foreign jurisdictions. In the U.S., we recorded book income and book loss before taxes for the six months ended June 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 June 30, 2007. At that date, we had a working capital deficit of approximately $24.9 million, a decrease of approximately $102.4 million from December 31, 2006. Our credit agreement covenants specify a minimum liquidity ratio under which we include 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 June 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

19

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	Six Months Ended
	June 30, 2007			June 30, 2006
Cash provided by (used in):
Operating activities	$	177,529		$	46,587
Investing activities		(390,178	)		(203,566	)
Financing activities		162,376			295,334

Cash provided by operating activities during the six months ended June 30, 2007 and 2006 was $177.5 million and $46.6 million, respectively. Cash flow from operations increased due to higher oil and gas production revenues during the first half of 2007 compared to the first half of 2006. The increase in sales revenue was attributable to higher oil and gas production and higher average oil and gas prices during the first half of 2007. The increase in cash flows as a result of the increased revenues was offset by the higher lease operating expense associated with that production and by the timing of payments and receipts in our payables and receivables.

Cash used in investing activities was $390.2 million and $203.6 million during the six months ended June 30, 2007 and 2006, respectively. Cash expended in the Gulf of Mexico and North Sea was approximately $279.6 million and $110.3 million in the first half of 2007. Cash expended in the Gulf of Mexico and North Sea was approximately $130.8 million and $72.6 million, respectively, in the first half of 2006.

Cash provided by financing activities was $162.4 million and $295.3 million during the six months ended June 30, 2007 and 2006, respectively. Such amount for the 2007 period was primarily due to the increase in our Term Loans (as defined below) of $366.6 million (net of issuance costs), partially offset by the $175.0 million repayment 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.

Term Loans

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

	June 30, 2007			December 31, 2006
First Lien Term Loans	$	1,265,072		$	896,441
Second Lien Term Loans		–			175,000
Total		1,265,072			1,071,441
Less current maturities		(12,737	)		(8,987	)
Total long-term debt	$	1,252,335		$	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

20

proceeds were $191.5 million. The interest rate on outstanding borrowings is based on LIBOR plus 3.5%, and at June 30, 2007 was approximately 9.22%.

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 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 3.0 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 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 June 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 non-compliance with these covenants. An event of non-compliance with any of the required covenants could result in a material mandatory repayment under the Existing Credit Agreement.

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.

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

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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 Loan. See the discussion of our Term Loan 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.

We entered into a foreign currency swap agreement on July 26, 2007. The agreement 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.

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 June 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

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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 June 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 Form 10-K.

PART II. OTHER INFORMATION

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

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

The following items were presented for approval to stockholders of record on April 11, 2007 at the Company’s annual meeting of stockholders which was held on June 8, 2007 in Houston, Texas:

	For	Against	Withheld or Abstained
(i)     Election of Directors:
T. Paul Bulmahn	21,706,505	–	3,171,935
Gerard J. Swonke	24,339,149	–	539,291
Robert J. Karow	24,639,848	–	238,595
(ii)    Ratification of Deloitte & Touche LLP, as independent auditors of the Company for the fiscal year ending December 31, 2007	24,721,122	22,527	134,791

All matters received the required number of votes for approval.

In May, 2007, Institutional Shareholder Services (ISS) recommended that shareholders withhold votes from Mr. Bulmahn solely for not establishing an independent nominating committee. ISS noted that companies should have a formal nominating committee comprised of independent board members. In the same report, ISS recognized that a substantial majority (8 out of 9) of the ATP Board members are independent outsiders. ATP’s Board of Directors, comprised entirely of independent directors except for Mr. Bulmahn, believes the functions of a nominating committee are adequately addressed by the established process adopted by the Board for the nomination of director candidates.

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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	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	Second Lien Credit Agreement dated November 22, 2006, among ATP, the lenders from time to time party thereto and CS, as administrative and collateral agent for the Lenders, incorporated by reference to Exhibit 10.2 of ATP’s Current Report on Form 8-K filed on November 29, 2006.
10.4	Intercreditor Agreement dated as of November 22, 2006 among ATP and CS, as first and second lien collateral agents, incorporated by reference to Annex I to Exhibit 10.1 of ATP’s Current Report on Form 8-K filed on November 29, 2006.
†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 Gerald W. Schlief, dated December 29, 2005, incorporated by reference to Exhibit 10.6 to ATP’s Form 8-K dated December 30, 2005.
†10.11	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.
†10.12	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.
†10.13	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.
†10.14	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.

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†10.15	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.
†10.16	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

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

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