Atp Oil & Gas 10Q 2010 Q2 Quarterly report

Atp Oil & Gas (ATPGQ) Inactive 10-Q2010 Q2 Quarterly report

Content analysis

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, 2010

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

Commission file number: 001-32647

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 has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ¨ No ¨

Indicate by check mark whether the Registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

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, 2010 was 51,271,197.

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

TABLE OF CONTENTS


		Page

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements (Unaudited)

Consolidated Balance Sheets: June 30, 2010 and December 31, 2009		3
Consolidated Statements of Operations: For the three and six months ended June 30, 2010 and 2009		4
Consolidated Statements of Cash Flows: For the six months ended June 30, 2010 and 2009		5
Consolidated Statements of Shareholders’ Equity and Noncontrolling Interest: For the six months ended June 30, 2010 and 2009		7
Consolidated Statements of Comprehensive Income (Loss): For the three and six months ended June 30, 2010 and 2009		8
Notes to Consolidated Financial Statements		9

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		24

Item 3. Quantitative and Qualitative Disclosures about Market Risks		40

Item 4. Controls and Procedures		40

PART II. OTHER INFORMATION		42

Item 1. Legal Proceedings		42

Item 1A. Risk Factors		42

Item 6. Exhibits		43

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, 2010			December 31, 2009
Assets
Current assets:
Cash and cash equivalents	$	205,932		$	108,961
Restricted cash		12,940			10,504
Accounts receivable (net of allowance of $225 and $291, respectively)		64,344			52,551
Deferred tax asset		13,368			101,956
Derivative asset		6,318			1,321
Other current assets		4,005			10,615

Total current assets		306,907			285,908

Oil and gas properties (using the successful efforts method of accounting):
Proved properties		4,105,788			3,609,131
Unproved properties		18,374			13,910

		4,124,162			3,623,041
Less accumulated depletion, depreciation, impairment and amortization		(1,232,599	)		(1,137,269	)

Oil and gas properties, net		2,891,563			2,485,772

Furniture and fixtures (net of accumulated depreciation)		246			342
Deferred financing costs, net		43,909			16,378
Derivative asset		6,891			—
Other assets, net		14,916			14,747

Total assets	$	3,264,432		$	2,803,147


Liabilities and Equity
Current liabilities:
Accounts payable and accruals	$	263,225		$	212,736
Current maturities of term loans		1,500			16,838
Asset retirement obligation		43,720			43,418
Derivative liability		5,917			16,216
Other current liabilities		32,204			23,094

Total current liabilities		346,566			312,302

First lien term loans		145,505			—
Senior second lien notes		1,493,229			—
Term loans		—			1,199,847
Other long-term obligations		515,577			274,942
Asset retirement obligation		110,973			106,781
Deferred tax liability		387			146,764
Derivative liability		1,102			7,646
Deferred revenue		852			19,336

Total liabilities		2,614,191			2,067,618

Commitments and contingencies (Note 12)

Temporary equity – redeemable noncontrolling interest		140,699			139,598


Shareholders’ equity:
8% convertible perpetual preferred stock: $0.001 par value, 10,000,000 shares authorized; 1,400,000 issued and outstanding at June 30, 2010 and December 31, 2009; at liquidation value		140,000			140,000
Common stock: $0.001 par value, 100,000,000 shares authorized; 51,346,587 issued and 51,270,747 outstanding at June 30, 2010; 50,755,310 issued and 50,679,470 outstanding at December 31, 2009		51			51
Additional paid-in capital		573,101			571,595
Accumulated deficit		(97,522	)		(19,317	)
Accumulated other comprehensive loss		(105,177	)		(95,487	)
Treasury stock, at cost		(911	)		(911	)

Total shareholders’ equity		509,542			595,931

Total liabilities and equity	$	3,264,432		$	2,803,147

See accompanying notes to consolidated financial statements.

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(In Thousands, Except Per Share Amounts)

(Unaudited)


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2010			2009			2010			2009
Revenues:
Oil and gas production	$	101,099		$	80,897		$	194,128		$	149,153
Other		—			—			—			13,664

		101,099			80,897			194,128			162,817


Costs, operating expenses and other:
Lease operating		32,295			17,358			61,930			37,572
Exploration		9			93			721			267
General and administrative		8,060			7,105			19,569			18,208
Depreciation, depletion and amortization		60,115			43,575			96,116			82,973
Impairment of oil and gas properties		3,853			699			12,090			8,748
Accretion of asset retirement obligation		3,463			3,041			6,853			5,945
Contract termination costs		8,714			—			8,714			—
Loss on abandonment		50			16			201			1,013
Gain on exchange/disposal of properties		(46	)		—			(12,020	)		—
Other, net		—			140			(946	)		288

		116,513			72,027			193,228			155,014

Income (loss) from operations		(15,414	)		8,870			900			7,803


Other income (expense):
Interest income		154			160			298			373
Interest expense, net		(64,645	)		(10,174	)		(76,864	)		(22,797	)
Derivative income		23,929			2,212			27,464			18,457
Loss on debt extinguishment		(78,171	)		—			(78,171	)		—

		(118,733	)		(7,802	)		(127,273	)		(3,967	)


Income (loss) before income taxes		(134,147	)		1,068			(126,373	)		3,836


Income tax (expense) benefit:
Current		326			732			(227	)		354
Deferred		57,473			(1,906	)		56,621			(654	)

		57,799			(1,174	)		56,394			(300	)


Net income (loss)		(76,348	)		(106	)		(69,979	)		3,536
Less income attributable to the redeemable noncontrolling interest		(3,771	)		(4,260	)		(8,226	)		(6,266	)
Less convertible preferred stock dividends		(2,800	)		—			(5,600	)		—

Net loss attributable to common shareholders	$	(82,919	)	$	(4,366	)	$	(83,805	)	$	(2,730	)


Net loss per share attributable to common shareholders:
Basic	$	(1.63	)	$	(0.12	)	$	(1.66	)	$	(0.08	)

Diluted	$	(1.63	)	$	(0.12	)	$	(1.66	)	$	(0.08	)


Weighted average number of common shares:
Basic		50,767			36,878			50,609			36,251
Diluted		50,767			36,878			50,609			36,251

See accompanying notes to consolidated financial statements.

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In Thousands)

(Unaudited)


	Six Months Ended
	June 30,
	2010			2009
Cash flows from operating activities
Net income (loss)	$	(69,979	)	$	3,536
Adjustments to reconcile net income (loss) to net cash provided by operating activities –
Depreciation, depletion and amortization		96,116			82,973
Impairment of oil and gas properties		12,090			8,748
Gain on nonmonetary property exchange		(12,020	)		—
Accretion of asset retirement obligation		6,853			5,945
Deferred income tax expense (benefit)		(56,621	)		654
Derivative (income) expense		(28,732	)		17,914
Loss on debt extinguishment		21,829			—
Stock-based compensation		3,560			4,280
Amortization of deferred revenue		(18,484	)		(22,675	)
Noncash interest expense		12,439			7,435
Other noncash items, net		387			1,949
Changes in assets and liabilities –
Accounts receivable and other current assets		(6,125	)		15,137
Accounts payable and accruals		15,615			(31,222	)
Other assets		210			391
Other long-term liabilities and deferred obligations		5,073			—

Net cash provided by (used in) operating activities		(17,789	)		95,065


Cash flows from investing activities
Additions to oil and gas properties		(377,304	)		(355,258	)
Proceeds from disposal of oil and gas properties		2,053			—
Increase in restricted cash		(2,436	)		(5,726	)
Additions to furniture and fixtures		(25	)		(110	)

Net cash used in investing activities		(377,712	)		(361,094	)


Cash flows from financing activities
Proceeds from senior second lien notes, net of discount		1,492,965			—
Proceeds from first lien term loans, net of discount		147,000			—
Proceeds from revolving credit facility, net of discount		46,000			—
Payments of term loans		(1,262,610	)		(58,664	)
Deferred financing costs		(52,613	)		—
Issuance of common stock		—			68,397
Net profits interests payments		(1,333	)		(907	)
Sale of redeemable noncontrolling interest, net of costs		—			148,751
Distributions to noncontrolling interest		(7,125	)		(11,846	)
Principal payments – pipeline transaction		(1,822	)		—
Proceeds from sales of net profits interests		50,000			—
Proceeds from dollar-denominated overriding royalty transaction (“Overrides”)		121,136			—
Principal payments – Overrides		(36,450	)		—
Preferred stock dividends		(5,656	)		—
Exercise of stock options		3,547			—

Net cash provided by financing activities		493,039			145,731


Effect of exchange rate changes on cash and cash equivalents		(567	)		5,495


Increase (decrease) in cash and cash equivalents		96,971			(114,803	)
Cash and cash equivalents, beginning of year		108,961			214,993

Cash and cash equivalents, end of period	$	205,932		$	100,190

See accompanying notes to consolidated financial statements.

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (Continued)

(In Thousands)

(Unaudited)


	Six Months Ended
	June 30,
	2010		2009
Noncash investing and financing activities
Increase (decrease) in accrued property additions	$	138,882	$	(71,593	)
Net property additions - nonmonetary exchange		11,778		—
Property additions in exchange for net profits interests		—		43,267
Asset retirement costs capitalized		1,258		460
Accrued limited partner distributions		—		3,562

See accompanying notes to consolidated financial statements.

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF

SHAREHOLDERS’ EQUITY AND NONCONTROLLING INTEREST

(In Thousands)

(Unaudited)


	Six Months Ended June 30,
	2010				2009
	Shares	Amount			Shares	Amount
Temporary Equity – Redeemable Noncontrolling Interest:

Balance, beginning of period		$	139,598			$	—
Sale of Class A Limited Partner Interest, net of formation costs			—				148,751
Income attributable to the redeemable noncontrolling interest			8,226				6,266
Limited partner distributions			(7,125	)			(15,408	)

Balance, end of period		$	140,699			$	139,609


Shareholders’ Equity:

8% Convertible Perpetual Preferred Stock, liquidation value
Balance, beginning of period	1,400	$	140,000		—	$	—

Balance, end of period	1,400		140,000		—		—


Common Stock
Balance, beginning of period	50,679		51		35,903		36
Issuance of common stock – exercise of stock options/warrants	415		—		8,750		9
Restricted stock, net of forfeitures	177		—		130		—

Balance, end of period	51,271		51		44,783		45


Paid-in Capital
Balance, beginning of period			571,595				400,334
Issuance of common stock - secondary offering			—				68,195
Issuance of common stock - options/warrants			3,547				—
Preferred stock dividends			(5,600	)			—
Stock-based compensation			3,559				4,280

Balance, end of period			573,101				472,809


Retained Earnings (Accumulated Deficit)
Balance, beginning of period			(19,317	)			29,644
Net income (loss)			(69,979	)			3,536
Less income attributable to the redeemable noncontrolling interest			(8,226	)			(6,266	)

Balance, end of period			(97,522	)			26,914


Accumulated Other Comprehensive Loss
Balance, beginning of period			(95,487	)			(112,754	)
Other comprehensive income (loss)			(9,690	)			23,382

Balance, end of period			(105,177	)			(89,372	)


Treasury Stock, at Cost
Balance, beginning of period	76		(911	)	76		(911	)

Balance, end of period	76		(911	)	76		(911	)

Total Shareholders’ Equity		$	509,542			$	409,485

See accompanying notes to consolidated financial statements.

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(In Thousands)

(Unaudited)


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2010			2009			2010			2009
Net income (loss)	$	(76,348	)	$	(106	)	$	(69,979	)	$	3,536


Other comprehensive income (loss):
Reclassification adjustment for settled hedge contracts (net of taxes of $0, 442, $0 and $295, respectively)		—			(442	)		—			(295	)
Changes in fair value of outstanding hedge positions (net of taxes of $0, ($619), $0 and ($3,369), respectively)		—			619			—			3,369
Foreign currency translation adjustment		242			20,551			(9,690	)		20,308

Other comprehensive income (loss)		242			20,728			(9,690	)		23,382


Comprehensive income (loss)		(76,106	)		20,622			(79,669	)		26,918
Less comprehensive income attributable to the redeemable noncontrolling interest		(3,771	)		(4,260	)		(8,226	)		(6,266	)

Less convertible preferred stock dividends		(2,800	)		—			(5,600	)		—

Comprehensive income (loss) attributable to common shareholders	$	(82,677	)	$	16,362		$	(93,495	)	$	20,652

See accompanying notes to consolidated financial statements.

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 1 — Organization

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

The consolidated financial statements include our accounts, the accounts of our majority owned limited partnership, ATP Infrastructure Partners, L.P. (“ATP-IP”) and those of our wholly-owned subsidiaries; ATP Energy, Inc.; ATP Oil & Gas (UK) Limited, or “ATP (UK);” ATP Oil & Gas (Netherlands) B.V. and three wholly owned limited liability companies created to own our interests in ATP-IP. All intercompany transactions are eliminated in consolidation, and we separate in the accompanying statements the redeemable noncontrolling interest in ATP-IP.

The accompanying unaudited consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”) for interim financial information and reflect all adjustments (consisting of normal recurring adjustments) which are, in the opinion of management, necessary for a fair statement of the results of operations for the interim periods. The interim financial information and notes hereto should be read in conjunction with our 2009 Annual Report on Form 10-K. The results of operations for the quarter and year-to-date periods ended June 30, 2010 are not necessarily indicative of results to be expected for the entire year.

Note 2 — Recent Accounting Pronouncements

Effective January 1, 2010, the Company partially adopted the provisions of FASB ASU No. 2010-06, “Improving Disclosures about Fair Value Measurements,” which amends ASC 820-10-50 to require new disclosures concerning (1) transfers into and out of Levels 1 and 2 of the fair value measurement hierarchy, and (2) activity in Level 3 measurements. In addition, ASU No. 2010-06 clarifies certain existing disclosure requirements regarding the level of disaggregation and inputs and valuation techniques and makes conforming amendments to the guidance on employers’ disclosures about postretirement benefit plans assets. The requirements to disclose separately purchases, sales, issuances, and settlements in the Level 3 reconciliation are effective for fiscal years beginning after December 15, 2010 (and for interim periods within such years). Accordingly, we will apply the disclosure requirements relative to the Level 3 reconciliation in the first quarter of 2011. There was no impact on our financial position, results of operations or cash flows as a result of the partial adoption of this standard.

Effective April 2010, the Company adopted the provisions of FASB ASU No. 2010-14 “Accounting for Extractive Activities – Oil & Gas,” which amends ASC 932-10-S99-1 to provide definitions of some of the terms used in the standard. There was no impact on our financial position, results of operations or cash flows as a result of the adoption of this standard.

Note 3 — Risks and Uncertainties

As an independent oil and gas producer, our revenue, profitability, cash flows, and future rate of growth are substantially dependent on prevailing prices for oil and natural gas. Historically, the energy markets have been very volatile, and we expect such price volatility to continue. Any extended decline in oil or gas prices could have a material adverse effect on our financial position, results of operations, cash flows, the quantities of oil and gas reserves that we can economically produce, and may restrict our ability to obtain additional financing or to meet the contractual requirements of our long-term obligations.

In addition, our estimates of proved oil and natural gas reserves and the estimated future net revenues from such reserves are based upon various assumptions, including assumptions relating to oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. This process requires significant assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir. Therefore, these estimates are inherently imprecise and the quality and reliability of this data can vary. Estimates of our oil and natural gas reserves and the costs and timing associated with developing these reserves are subject to change, which could materially impact the quantities of oil and natural gas that we ultimately produce. As of December 31, 2009, approximately 87% of our total proved reserves are undeveloped. Throughout the year, we intend to continue to develop these reserves, but there can be no assurance we will be successful. Development of these reserves may not yield the expected results, or the development may be delayed or the costs may exceed our estimates, any of which may materially affect our financial position, results of operations, cash flows and our ability to meet the requirements of our financing obligations.

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

In addition to the numerous risks associated with offshore operations, some of which may not be covered by insurance, these properties are also characterized by rapid production declines, which require us to incur significant capital expenditures to replace declining production. Complications in the development of any single material well or infrastructure installation, including lack of sufficient capital, or operational problems may materially affect our financial condition, results of operations and cash flows.

We are also vulnerable to certain concentrations that could expose our revenues, profitability, cash flows and access to capital to the risk of a near-term severe impact. The size of our operations and our capital expenditures budget limit the number of properties that we can develop in any given year and a substantial portion of our current production is contributed from relatively few wells located offshore in the Gulf of Mexico and in the North Sea. In 2008 and 2009 and thus far in 2010, a significant amount of time and money has been spent by us on our Telemark Hub development. Our results of operations, financial position and cash flows for the next twelve months as well as longer term, will be significantly impacted by the timing and success at this development, which began production at the end of the first quarter of 2010. We have also recently conveyed to certain vendors and financial parties dollar-denominated net profits interests and overriding royalty interests in our Telemark Hub and Gomez Hub oil and gas properties in exchange for development services, equipment and cash. We have also negotiated with certain other vendors involved in the development of the Telemark Hub to partially defer payments until after production has begun. These net profits interests and deferrals, while they allowed development to continue, will burden the net cash flows available to us from Telemark Hub and Gomez Hub production activities until the obligations have been satisfied.

Although we believe that we will have adequate liquidity to meet our future capital requirements, the factors described above create uncertainty. We consider the control and flexibility afforded by operating our properties under development to be key to our business plan and strategy. By operating our properties, we retain significant control over the development plans and their timing. Within certain constraints, we can conserve capital by delaying or eliminating capital expenditures. While postponing or eliminating capital projects will delay or reduce future cash flows from scheduled new production, this control and flexibility helps us to match our capital commitments to our available capital resources.

On April 20, 2010, a semi-submersible drilling rig operating in the deepwater Gulf of Mexico exploded, burned for two days and sank, resulting in an oil spill in Gulf of Mexico waters. In response to this crisis, the U.S. Secretary of the Interior, on May 6, 2010, announced a moratorium on U.S. offshore drilling permits issued after April 20, 2010, until May 28, 2010, when a report on the accident was expected to be completed. On May 28, 2010, the U.S. Secretary of the Interior issued a second moratorium, originally scheduled to last for six months, that essentially halted all drilling in water depths greater than 500 feet in the Gulf of Mexico. On June 7, 2010, a lawsuit was filed by a supplier of services to Gulf of Mexico exploration and production companies challenging the legality of the six-month moratorium. This challenge was successful and on June 22, 2010, a Federal District Court issued a preliminary injunction preventing the moratorium from taking effect. The Fifth Circuit Court of Appeals is scheduled to hear the injunction case in late August. On July 12, 2010, in response to the Court’s actions, the U.S. Department of Interior issued a revised moratorium essentially canceling all permits for drilling at locations using a floating drilling rig or platform. Although lawsuits have been filed challenging the moratorium, there is no resolution to the challenge as of the date of this filing.

While the revised moratorium is not scheduled to end before November 30, 2010, we cannot predict with certainty when it will end. We cannot predict how federal and state authorities will further respond to the incident or whether additional changes in laws and regulations governing oil and gas operations in the Gulf of Mexico will result. On July 30, 2010, the U.S. House of Representatives passed H.R. 3534 which contains significant changes to the way we and all companies operating in the Gulf of Mexico conduct business. The U.S. Senate has not yet enacted a similar bill, but has introduced a bill that contains some of the same provisions contained in the H.R. 3534. If ultimately enacted, these bills will require higher insurance levels, increased liability exposure, additional fees on production, as well as numerous additional operating constraints and procedures. Such regulations or limitations will require a change in the way we conduct our business, will increase our costs of doing business or may ultimately prohibit us from drilling for or producing hydrocarbons in the Gulf of Mexico. We cannot predict if or how the governments of other countries will respond to the accident in the Gulf of Mexico.

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

We have ongoing and planned drilling operations in the deepwater Gulf of Mexico, some of which were permitted prior to April 20, 2010, and some of which are not yet permitted. Such permits, among other required approvals, are necessary prior to commencement of offshore drilling operations. The revised moratorium has caused us to delay the third and fourth wells scheduled at our Telemark location and may delay a drilling operation scheduled late in 2010 at our Gomez location. During June 2010, we agreed to terminate a contract for services of a drilling rig as a result of the Gulf of Mexico deep water drilling moratorium. Under the termination agreement, we obtained a full release from our obligations under the contract and incurred net costs of $8.7 million. We are pursuing recovery from BP of these and other direct costs incurred as a result of the accident in the Gulf of Mexico.

We project a substantial increase in production over the next year as development wells are brought to production. Absent alternative funding sources, achieving our projected production growth is necessary to provide the cash flow required to fund our capital plan and meet our existing obligations, both over the next twelve months and on a longer term basis. Our ability to execute on our plan depends, in part, on our ability to continue drilling for and producing hydrocarbons in the Gulf of Mexico. Our plan is currently based upon resuming suspended activities upon the expiration of the revised moratorium currently scheduled to occur on November 30, 2010, obtaining necessary drilling permits, and successfully achieving expected commercial production from existing wells presently scheduled for completion during the remainder of 2010 and the first quarter of 2011. Delays in resuming those activities due to circumstances such as an extension of the moratorium, delays in receiving necessary permits reduced access to equipment and services, or weather delays, could have a material adverse effect on our financial position, results of operations and cash flows In addition to the risks associated with achieving our projected production growth, additional regulatory requirements and increased costs for which funding must be secured, or a negative change in commodity prices and operating cost levels could also have a material adverse effect on our financial position, results of operations and cash flows. While we are pursuing various other sources of funding, including monetizing selected assets such as the ATP Titan and bringing partners into our projects, there is no current assurance that these alternative sources will be available should any of the above risks or uncertainties materialize.

Note 4 — Income Taxes

Income tax expense during interim periods is based on the estimated annual effective income tax rate plus any significant, unusual or infrequently occurring items that are recorded in the period the specific item occurs. We compute income taxes using an asset and liability approach which results in the recognition of deferred tax liabilities and assets for the expected future tax consequences of temporary differences between the financial basis and the tax basis of those assets and liabilities. We recognized income tax benefit of $57.8 million and income tax expense of $1.2 million for the three months ended June 30, 2010 and 2009, respectively. We recognized income tax benefit of $56.4 million and income tax expense of $0.3 million for the six months ended June 30, 2010 and 2009, respectively. The worldwide effective tax rates for the three months ended June 30, 2010 and 2009 were 43% and 110%, respectively. The worldwide effective tax rates for the first six months of 2010 and 2009 were 44% and 8%, respectively.

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

Note 5 — Oil and Gas Properties

Acquisitions and Dispositions

During the six months ended June 30, 2010, the U.S. Department of Interior Minerals Management Service awarded us leases for 100% of the working interests in the Ship Shoal (“SS”) Block 361 and the Garden Banks Block 782 (“Entrada”). SS Block 361 is in close proximity to our SS Block 358 Hub. Entrada is in the vicinity of existing infrastructure owned by others. We paid $0.4 million for these leases.

During January 2010, we consummated a nonmonetary exchange of our 10% nonoperated working interest in Mississippi Canyon (“MC”) Block 800, for an incremental 50% working interest in MC Block 754, both proved undeveloped properties. The consolidated financial statements reflect the incremental interest acquired in MC Block 754 at fair value and removal of the carrying costs of MC Block 800, resulting in recognition of a $12.0 million gain.

Also during January 2010, we acquired a 100% working interest in MC Block 710, an exploratory prospect adjacent to our Gomez Hub in MC Block 711 and surrounding blocks, in exchange for the conveyance of an overriding royalty interest.

Impairment of Oil and Gas Properties

We recorded impairments during the six months ended June 30, 2010 and 2009 of $12.1 million and $8.7 million, respectively. Of these amounts, $4.5 million and $0.7 million in the six months ended June 30, 2010 and 2009, respectively, were related to unproved properties in the Gulf of Mexico. The 2010 amounts were associated with leases which were approaching their expiration dates and became unlikely to be drilled primarily due to the revised moratorium on drilling discussed above. We recorded impairments of proved properties during the six months ended June 30, 2010 and 2009 of $7.6 million and $8.0 million, respectively. These amounts represented the remaining carrying costs of those properties, and were primarily due to relinquishment of the leases. We also recorded a $1.0 million loss on abandonment related to the property impaired in 2009.

Note 6 — Long-term Debt

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


	June 30,			December 31,
	2010			2009
First lien term loans, net of $2,995 unamortized discount	$	147,005		$	—
Senior second lien notes, net of $6,771 unamortized discount		1,493,229			—
Term Loans, net of $28,266 unamortized discount		—			1,216,685

Total debt		1,640,234			1,216,685
Less current maturities		(1,500	)		(16,838	)

Total debt - noncurrent	$	1,638,734		$	1,199,847

In April 2010, we entered into a first lien revolving credit facility (the “Original Credit Facility”) with an initial borrowing base of $100.0 million, due April 23, 2013, and issued senior second lien notes (the “Notes”) in an aggregate principal amount of $1.5 billion, due May 1, 2015. We used proceeds from the Notes to repay the entire amount outstanding under the Term Loans. The combined effective annual interest rate under the Notes and the New Credit Facility, discussed below, was 12.4% at June 30, 2010. The fair value of the debt as of June 30, 2010 was approximately $1.2 billion.

The Notes bear interest at an annual rate of 11.875%, payable each May 1 and November 1, and contain customary covenants and restrictions that, among other things, limit the incurrence of additional indebtedness, mergers and consolidations, and certain restricted payments. In connection with the issuance of the Notes, we granted registration rights to the holders of the Notes and agreed to register the Notes with the SEC within 270 days of their initial issuance. The Notes were issued at 99.531% of their face amount to yield 12.0% and we incurred issuance costs of $38.2 million.

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

At any time (which may be more than once), on or prior to May 1, 2013, the Company may, at its option, redeem up to 35% of the outstanding Notes with money raised in certain equity offerings, at a redemption price of 111.9%, plus accrued interest, if any. In addition, the Company may redeem the Notes, in whole or in part, at any time before May 1, 2013 at a redemption price equal to par plus an applicable make-whole premium plus accrued and unpaid interest to the date of redemption. The Company may also redeem any of the Notes at any time on or after May 1, 2013, in whole or in part, at specified redemption prices, plus accrued and unpaid interest to the date of redemption.

The Notes also contain a provision allowing the holders thereof to require the Company to purchase some or all of those Notes at a purchase price equal to 101% of their aggregate principal amount, plus accrued and unpaid interest to the date of repurchase, upon the occurrence of specified change of control events.

In June 2010, we entered into a first lien credit agreement (the “New Credit Facility”) with an initial balance of $150.0 million, due May 15, 2014, to replace the Original Credit Facility. Proceeds of the New Credit Facility were $144.3 million, net of original issue discount and transaction fees. Principal outstanding under the term loans issued pursuant to the New Credit Facility bears interest at an annual rate of 11.0%. As security for the Company’s obligations under the New Credit Facility, the Company granted the lenders a security interest in and a first lien on 80% of its proved oil and gas reserves in the Gulf of Mexico, capital stock of material subsidiaries (limited in the case of the Company’s non-U.S. subsidiaries to not more than 65% of the capital stock) and, initially, certain infrastructure assets, which are subject to release. Principal of $750,000 is due each June 18 and December 18 beginning December 18, 2010 until June 18, 2014. The remaining balance is due October 15, 2014. The New Credit Facility allows the Company to incur up to $350.0 million of additional indebtedness as Consolidated Net Tangible Assets increase.

New Credit Facility contains certain negative covenants which place limits on the Company’s ability to, among other things:

•

incur additional indebtedness;

•

pay dividends on the Company’s capital stock or purchase, repurchase, redeem, defease or retire the Company’s capital stock or subordinated indebtedness;

•

make investments outside of our normal course of business;

•

incur liens;

•

create any consensual restriction on the ability of the Company’s restricted subsidiaries to pay dividends, make loans or transfer property to the Company;

•

engage in transactions with affiliates;

•

sell assets; and

•

consolidate, merge or transfer assets.

Note 7 — Other Long-term Obligations

Other long-term obligations consisted of the following (in thousands):


	June 30,			December 31,
	2010			2009
Net profits interests	$	278,398		$	180,818
Dollar-denominated overriding royalty interests		100,629			14,941
Gomez pipeline obligation		74,252			75,152
Vendor deferrals - Gulf of Mexico		13,196			7,490
Vendor deferrals - North Sea		78,724			17,053
Other		2,582			2,582

Total		547,781			298,036
Less current portion (included in other current liabilities)		(32,204	)		(23,094	)

Other long-term obligations	$	515,577		$	274,942

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

Net Profits Interests

During 2009, we granted dollar-denominated overriding royalty interests in the form of net profits interests (“NPIs”) in certain of our oil and gas properties in and around the Telemark Hub and Clipper to certain of our vendors in exchange for oil and gas property development services. The interests earned by the vendors are paid solely from the net profits, as defined, of the subject properties. As the net profits increase or decrease, primarily through higher or lower production levels and higher or lower prices of oil and natural gas, the payments due the holders of the net profits interests increase or decrease accordingly. If there is no production from a property or if the net profits are negative during a payment period, there is no payment required. We accrue the present value of the NPIs as a liability on our consolidated balance sheet. As the NPI is earned, we also accrete the liability over the estimated term in which the NPI is expected to be settled using the effective interest method with related interest reflected in interest expense net of amounts capitalized on the consolidated statement of operations. The term of the NPIs will be dependent on the value of the services contributed by these vendors coupled with the estimated timing of production and future economic conditions, including commodity prices and operating costs. Because we have accounted for these NPI’s as financing obligations on our consolidated balance sheet, the reserves and production revenues associated with the NPIs are retained by the Company. A portion of the NPI balance relates to financing of property acquisitions prior to 2009. During the first six months of 2010, we granted additional NPIs and received cash proceeds of $49.5 million net of costs.

Dollar-denominated Overriding Royalty Interests

In October 2009, we sold a dollar-denominated overriding royalty interest (“Override”) in our Gomez Hub properties for $14.5 million, net of costs. During the six months ended June 30, 2010, we sold Overrides (primarily dollar-denominated) in future production from the Gomez Hub properties for $140 million ($121.1 million net of transaction costs and fourth quarter 2009 royalty payments). These Overrides obligate us to deliver proceeds from the future sale of hydrocarbons from the specified properties equal to the purchasers’ original investments, plus an overall rate of return. As with the NPIs, as the proceeds from the sale of hydrocarbons increase or decrease, primarily through higher or lower production levels and higher or lower prices of oil and natural gas, the payments due the holders of the overriding royalty interests will increase or decrease accordingly. If there is no production from a property during a payment period, there is no payment required. The percentage of property revenues available to satisfy these obligations is dependent upon certain conditions specified in the agreement. Upon payment of the agreed dollar amounts, the ownership of the Overrides reverts to us. Because of the explicit rate of return, dollar-denomination and limited payment terms of the Overrides, they are reflected in the accompanying financial statements as financing obligations and the reserves and production revenues are retained by the company.

Gomez Pipeline Transaction

In 2009, we executed an asset purchase and sale agreement for net proceeds of $74.5 million pursuant to which, the Company sold to a third party both the oil and natural gas pipelines that service the Gomez Hub at MC Block 711. In conjunction with the sale, we entered into agreements with the third party to transport oil and natural gas production for the remaining production life of the fields serviced by theATP Innovator for a per-unit fee that is subject to a minimum monthly payment through December 31, 2016. Such minimum fees, if applicable, can be recovered by the company in future periods within the same calendar year whenever fees owed during a month exceed the minimum due. We remain the operator of the pipeline and are responsible for all of the related operating costs. As a result of the retained asset retirement obligation and the purchaser’s option to convey the pipeline back to us at the end of the life of the fields in the Gomez Hub, the transaction has been accounted for as a financing obligation equal to the net proceeds received. This obligation is being amortized based on the estimated proved reserve life of the Gomez properties using the effective interest method with related interest reflected in interest expense net of amounts capitalized on the Consolidated Statement of Operations. All payments made in excess of the minimum fee in future periods will be reflected as interest expense of the financing obligation.

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

Vendor Deferrals

In the Gulf of Mexico, in addition to the net profits interests exchanged for development services described above, we have negotiated with certain other vendors involved in the development of the Telemark Hub and Clipper to partially defer payments until after production has begun.

In the U.K. North Sea, development of our interest in the Cheviot field continues and we have arranged with the fabricator of the floating production and drilling facility to defer $99 million of payments until construction is complete, which is expected to be in 2011. As work is completed, we record obligations and related interest expense, net of amounts capitalized on the Consolidated Statement of Operations.

The weighted average effective interest rate on other long-term obligations was 16.5% at June 30, 2010.

Note 8 — Asset Retirement Obligation

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


	Six Months Ended
	June 30,
	2010			2009
Asset retirement obligation, beginning of period	$	150,199		$	132,108
Liabilities incurred		1,459			461
Liabilities settled		(2,626	)		(2,365	)
Property dispositions		(242	)		(292	)
Accretion of asset retirement obligation		6,853			5,945
Changes in estimates		(950	)		2,470

Total asset retirement obligation		154,693			138,327
Less current portion		(43,720	)		(35,923	)

Total long-term asset retirement obligation, end of period	$	110,973		$	102,404

Note 9 — Stock–Based Compensation

We recognized stock option compensation expense of $0.6 million and $0.8 million for the three months ended June 30, 2010 and 2009, respectively, and $1.4 million and $1.6 million during the six months ended June 30, 2010 and 2009, respectively. We recognized restricted stock compensation expense of $1.1 million and $1.3 million for the three months ended June 30, 2010 and 2009, respectively, and $2.2 million and $2.7 million during the six months ended June 30, 2010 and 2009, respectively.

The fair values of options granted were estimated at the date of grant using a Black-Scholes option-pricing model assuming no dividends and with the following weighted average assumptions for grants during the periods indicated:


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2010			2009			2010			2009
Weighted average volatility		85	%		71	%		82	%		71	%
Expected term (in years)		3.8			3.8			3.8			3.8
Risk-free rate		1.4	%		1.7	%		1.8	%		1.7	%
Weighted average fair value of options – grant date	$	3.75		$	3.63		$	7.77		$	3.63

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

The following table sets forth a summary of option transactions for the six months ended June 30, 2010:


	Number of Options		Weighted Average Grant Price		Aggregate Intrinsic Value (1) ($000)		Weighted Average Remaining Contractual Life
							(in years)
Outstanding at beginning of period	1,634,105		$	24.69
Granted	7,000			15.29
Forfeited	(17,230	)		21.70
Expired	(247,271	)		19.55
Exercised	(63,947	)		16.19	$	377

Outstanding at end of period	1,312,657			26.06	$	1,539	2.9

Vested and expected to vest	1,146,763			26.28	$	1,312	2.8

Options exercisable at end of period	470,499			34.41	$	318	1.9

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

At June 30, 2010, unrecognized compensation expense related to nonvested stock option grants totaled $2.7 million. Such unrecognized expense will be recognized as vesting occurs over a weighted average period of 2.5 years. At June 30, 2010, unrecognized compensation expense related to restricted stock totaled $4.0 million. Such unrecognized expense will be recognized as vesting occurs over a weighted average period of 1.9 years. The following table sets forth the changes in nonvested restricted stock for the three months ended March 31, 2010:


	Number of Shares		Weighted Average Grant-date Fair Value		Aggregate Intrinsic Value (1) ($000)
Nonvested at beginning of period	419,293		$	26.25
Granted	179,179			13.85
Forfeited	(2,181	)		8.84
Vested	(112,029	)		24.38

Nonvested at end of period	484,262			22.17	$	5,128

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

Note 10 — Earnings Per Share

Basic earnings per share (“EPS”) is computed by dividing net income or loss attributable to common shareholders by the weighted average number of common shares (other than nonvested restricted stock) outstanding during the period. Weighted average shares outstanding for diluted EPS also includes a hypothetical number of additional shares (“Common Stock Equivalents”) calculated assuming the exercise or conversion of all in-the-money options, warrants and convertible preferred stock and full vesting of restricted stock awards. Common Stock Equivalents are excluded from the computation of weighted average common shares outstanding when the per share effect is antidilutive. The impact of assumed conversion of preferred stock on net income (loss) is excluded from the computation of EPS when its impact is antidilutive. For each of the three months ended June 30, 2010 and 2009, 1.4 million and 1.1 million, respectively, Common Stock Equivalents were excluded from the diluted EPS calculation in the table below because their inclusion would

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

have been antidilutive. For each of the six months ended June 30, 2010 and 2009, 1.3 million and 1.5 million, respectively, Common Stock Equivalents were excluded from the diluted EPS calculation in the table below because their inclusion would have been antidilutive. For the three and six months ended June 30, 2010, preferred stock dividends of $2.8 million and $5.6 million, respectively, were excluded from the diluted EPS computation of net loss attributable to common shareholders for each such period because their inclusion would have been antidilutive. A total of 6.3 million potential shares from the assumed conversion of preferred stock have been excluded from each 2010 period because their effect would have been antidilutive.

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


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2010			2009			2010			2009
Net loss attributable to common shareholders	$	(82,919	)	$	(4,366	)	$	(83,805	)	$	(2,730	)
Add impact of assumed preferred stock conversions (if-converted method)		—			—			—			—

Net loss attributable to common shareholders and impact of assumed conversions	$	(82,919	)	$	(4,366	)	$	(83,805	)	$	(2,730	)


Shares outstanding:
Weighted average shares outstanding - basic		50,767			36,878			50,609			36,251
Effect of potentially dilutive securities - stock options and warrants		—			—			—			—
Nonvested restricted stock		—			—			—			—
Preferred stock		—			—			—			—

Weighted average shares outstanding - diluted		50,767			36,878			50,609			36,251


Net loss per share attributable to common shareholders:
Basic	$	(1.63	)	$	(0.12	)	$	(1.66	)	$	(0.08	)

Diluted	$	(1.63	)	$	(0.12	)	$	(1.66	)	$	(0.08	)

Note 11 — Derivative Instruments and Risk Management Activities

We periodically enter into commodity price derivative contracts and fixed-price physical contracts to manage our exposure to oil and natural gas price volatility. We primarily utilize fixed-price physical forward contracts, price swaps, price collars and put options which are generally placed with major financial institutions or with counterparties of high credit quality in order to minimize our credit risks. The oil and natural gas reference prices of these commodity derivative contracts are based upon oil and natural gas market exchanges which have a high degree of historical correlation with the actual prices we receive. All derivative instruments are recorded on the balance sheet at fair value.

Gains and losses for derivatives which have not been designated as hedges are recorded as components of derivative income (expense) in our consolidated statement of operations. Gains and losses for derivatives which have been designated as hedges are recorded instead to accumulated other comprehensive income

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

(“AOCI”) until the period in which the forecasted hedged transactions occur, at which time the gains and losses are reclassified from AOCI to the consolidated statement of operations as components of the revenue items to which they relate. Settlements of commodity derivative instruments are included in cash flows from operating activities in our consolidated statement of cash flows.

At June 30, 2010, we had the following derivative contracts in place:


				Net Fair Value Asset (Liability) (2)
Period	Type	Volumes	Price	Current			Noncurrent
			$/Unit (1)	($000)			($000)

Oil (Bbl) –Gulf of Mexico
Remainder 2010	Puts	184,000	24.70	$	—		$	—

Remainder 2010	Swaps	828,000	77.83		759			—
2011	Swaps	1,987,500	81.60		1,594			2,240
2012	Swaps	479,750	89.07		—			3,685

Remainder 2010	Swaps (3)	368,000	70.00		(2,407	)		—
2011	Swaps (3)	911,000	78.41		(122	)		966

Total				$	(176	)	$	6,891


Natural Gas (MMBtu)
North Sea
Remainder 2010	Fixed-price physicals	552,000	6.63	$	(364	)	$	—

Remainder 2010	Swaps	920,000	5.47		(1,672	)		—
2011	Swaps	1,275,000	7.00		(1,352	)		(279	)
2012	Swaps	1,098,000	8.08		—			(823	)

Gulf of Mexico
Remainder 2010	Fixed-price physicals	3,660,000	5.57		2,717			—
2011	Fixed-price physicals	900,000	5.42		35			—

Remainder 2010	Collars	2,760,000	4.75-7.95		893			—
2011	Collars	1,350,000	4.75-7.95		320			—

Total				$	577		$	(1,102	)


Derivative asset				$	6,318		$	6,891
Derivative liability					(5,917	)		(1,102	)

Total				$	401		$	5,789

(1)	Unit price for collars reflects the floor and the ceiling prices, respectively.

(2)	None of the derivatives outstanding are designated as hedges for accounting purposes.

(3)	These swaps include call options to allow us to participate in per barrel price increases above $110 and $111 in 2010 and 2011, respectively.

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

At December 31, 2009, we had the following derivative contracts in place:


				Net Fair Value Asset (Liability) (2)
Period	Type	Volumes	Price	Current			Noncurrent
			$/Unit (1)	($000)			($000)

Oil (Bbl) –Gulf of Mexico
2010	Puts	365,000	24.70	$	2		$	—

2010	Swaps	733,000	79.76		(2,212	)		—
2011	Swaps	1,095,000	80.17		—			(5,625	)

2010	Swaps (3)	1,273,000	68.29		(13,402	)		—
2011	Swaps (3)	181,000	72.00		—			(1,508	)

Total				$	(15,612	)	$	(7,133	)


Natural Gas (MMBtu)
North Sea
2010	Fixed-price physicals	1,095,000	7.01	$	1,321		$	—

Gulf of Mexico
2010	Fixed-price physicals	4,525,000	5.58		(778	)		—

2010	Collars	4,575,000	4.68-7.86		173			—
2011	Collars	1,350,000	4.75-7.95		—			(512	)

Total				$	716		$	(512	)


Derivative asset				$	1,321		$	—
Derivative liability					(16,216	)		(7,646	)

Total				$	(14,895	)	$	(7,646	)

(1)	Unit price for collars reflects the floor and the ceiling prices, respectively.

(2)	None of the derivatives outstanding are designated as hedges for accounting purposes.

(3)	These swaps include call options to allow us to participate in per barrel price increases above $99.34 and $115.00 in 2010 and 2011, respectively.

There was no hedge AOCI during the six months ended June 30, 2010. The following AOCI table shows where gains and losses (net of taxes) on cash flow hedge derivatives have been reported in the six months ended June 30, 2009 (in thousands):


	Three Months			Six Months
	Ended June 30, 2009
AOCI for cash flow hedges - beginning of period	$	20		$	(2,877	)
Derivative gains		619			3,369
Losses reclassified from AOCI to oil and gas revenues		(442	)		(295	)

AOCI for cash flow hedges - end of period	$	197		$	197

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

During the six months ended June 30, 2010, we paid net cash settlements of $1.3 million of our price hedge derivatives. Our derivative income for the six months ended June 30, 2010 and 2009 is based entirely on nondesignated derivatives and consists of the following (in thousands):


	Three Months Ended June 30,
	2010			2009
Realized gains (losses) from:
Settlements of contracts	$	620		$	5,087
Early terminations of contracts		—			14,923
Unrealized gains (losses) on open contracts		23,309			(17,798	)


Derivative income	$	23,929		$	2,212


	Six Months Ended June 30,
	2010			2009
Realized gains (losses) from:
Settlements of contracts	$	(1,449	)	$	18,714
Early terminations of contracts		—			17,657
Unrealized gains (losses) on open contracts		28,913			(17,914	)


Derivative income	$	27,464		$	18,457

Note 12 — Commitments and Contingencies

The development, production and sale of oil and natural gas in the Gulf of Mexico and in the North Sea are subject to extensive laws and regulations, including environmental laws and regulations. We may be required to make large expenditures to comply with environmental and other governmental regulations. Under these laws and regulations, we could be liable for personal injuries, property damage, oil spills, discharge of hazardous materials, remediation and clean-up costs and other environmental damages. Failure to comply with these laws and regulations also may result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties. Moreover, these laws and regulations could change in ways that substantially increase our costs (see the discussion in Note 3, “Risks and Uncertainties”). Accordingly, any of these liabilities, penalties, suspensions, terminations or regulatory changes could materially adversely affect our financial condition and results of operations. We believe that we are in compliance with all of the laws and regulations which apply to our operations.

During the term of the Platform Use Agreement governing theATP Innovator, we are obligated to pay to ATP-IP, our consolidated partnership, a per unit fee for all hydrocarbons processed by theATP Innovator, subject to a minimum throughput fee of $53,000 per day. We may also be subject to a minimum fee of $53,000 per day for up to 180 days under certain circumstances, including if we fail to provide the minimum notification period before the Gomez Hub fields ceases production. We are responsible for all of the operating costs and periodic maintenance of theATP Innovator. We could also be required to repurchase the Class A limited partner interest if certain change of control events were to occur. If a change of control were to become probable in a future period, we would be required to adjust the carrying amount of the redeemable noncontrolling interest to its redemption amount, to the extent it differed from the carrying amount, at the time the change of control was deemed to be probable. We do not currently believe a change of control is probable.

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

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

In the normal course of business, we occasionally purchase oil and gas properties for little or no up-front costs and instead commit to pay consideration contingent upon the successful development and operation of the properties. The contingent consideration generally includes amounts to be paid upon achieving specified operational milestones, such as first commercial production and again upon achieving designated cumulative sales volumes. At June 30, 2010, the aggregate amount of such contingent commitments related to unmet operational milestones was $7.6 million.

In February 2010, Bison Capital Corporation filed suit against ATP alleging that fees totaling $102 million related to certain financing transactions had not been paid by ATP. We believe we have paid Bison Capital Corporation all amounts due under our 2004 agreement with them. ATP plans to vigorously defend against these allegations.

We are, in the ordinary course of business, involved in various other legal proceedings from time to time. Management does not believe that the outcome of these proceedings as of June 30, 2010, either individually or in the aggregate, will have a material adverse effect on our financial condition, results of operations or cash flows.

Note 13 — Segment Information

The Company’s operations are focused in the Gulf of Mexico and the North Sea. Management reviews and evaluates separately the operations of its Gulf of Mexico segment and its North Sea segment. The operations of both segments include natural gas and liquid hydrocarbon production and sales. Segment activity is as follows (in thousands):


For the Three Months Ended –	Gulf of Mexico		North Sea			Total

June 30, 2010:
Revenues	$	96,002	$	5,097		$	101,099
Depreciation, depletion and amortization		54,451		5,664			60,115
Impairment		3,853		—			3,853
loss from operations		12,517		2,897			15,414
Interest income		39		115			154
Interest expense, net		64,645		—			64,645
Derivative income (loss)		30,288		(6,359	)		23,929
Loss on debt extinguishment		78,171		—			78,171
Income tax benefit		57,799		—			57,799
Additions to oil and gas properties		168,078		39,934			208,012

June 30, 2009:
Revenues	$	75,871	$	5,026		$	80,897
Depreciation, depletion and amortization		35,605		7,970			43,575
Impairment		699		—			699
Income (loss) from operations		15,446		(6,576	)		8,870
Interest income		160		—			160
Interest expense, net		10,174		—			10,174
Derivative income		1,031		1,181			2,212
Income tax expense		1,174		—			1,174
Additions to oil and gas properties		124,076		65,695			189,771

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)


For the Six Months Ended –	Gulf of Mexico		North Sea			Total

June 30, 2010:
Revenues	$	183,370	$	10,758		$	194,128
Depreciation, depletion and amortization		84,862		11,254			96,116
Impairment		12,090		—			12,090
Income (loss) from operations		5,742		(4,842	)		900
Interest income		76		222			298
Interest expense, net		76,864		—			76,864
Derivative income (loss)		32,902		(5,438	)		27,464
Loss on debt extinguishment		78,171		—			78,171
Income tax benefit		56,394		—			56,394
Additions to oil and gas properties		448,495		64,805			513,300
Total assets		2,924,795		339,637			3,264,432

June 30, 2009:
Revenues	$	154,592	$	8,225		$	162,817
Depreciation, depletion and amortization		69,668		13,305			82,973
Impairment		8,748		—			8,748
Income (loss) from operations		19,450		(11,647	)		7,803
Interest income		373		—			373
Interest expense, net		22,797		—			22,797
Derivative income		13,198		5,259			18,457
Income tax expense		300		—			300
Additions to oil and gas properties		282,527		76,100			358,627
Total assets		2,104,210		289,084			2,393,294

Note 14 — Fair Value Measurements

Assets and Liabilities Measured at Fair Value on a Recurring Basis

The fair value of our derivative contracts is based on significant unobservable (or Level 3) inputs into our expected present value models. The following table sets forth a reconciliation of changes in the fair value of these financial assets (liabilities) during the six months ended June 30, 2010 (in thousands):


	Gas Fixed- Price Physicals			Gas Price Collars			Oil Swaps			Oil Swaps⁽¹⁾			Oil Puts			Subtotal U.S.
U.S.

Balance at beginning of period	$	(778	)	$	(339	)	$	(7,837	)	$	(14,910	)	$	2		$	(23,862	)
Derivative income (expense)		6,212			2,487			13,894			10,311			(2	)		32,902
Settlements and terminations		(2,682	)		(935	)		2,221			3,036			—			1,640


Balance at end of period	$	2,752		$	1,213		$	8,278		$	(1,563	)	$	—		$	10,680


Changes in unrealized gain (loss) included in derivative income (expense) relating to derivatives still held at June 30, 2010	$	3,195		$	1,762		$	15,682		$	3,687		$	(2	)	$	24,324

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)


	Gas Fixed- Price Physicals			Gas Swaps			Subtotal U.K.			Grand Total
U.K.

Balance at beginning of period	$	1,321		$	—		$	1,321		$	(22,541	)
Derivative income (expense)		(1,213	)		(4,225	)		(5,438	)		27,464
Settlements and terminations		(472	)		99			(373	)		1,267


Balance at end of period	$	(364	)	$	(4,126	)	$	(4,490	)	$	6,190


Changes in unrealized gain (loss) included in derivative income (expense) relating to derivatives still held at June 30, 2010	$	(802	)	$	(4,126	)	$	(4,928	)	$	19,396

(1)	These swaps include call options to allow us to participate in price increases above certain levels.

Assets Measured at Fair Value on a Nonrecurring Basis

Oil and gas property is measured at fair value on a nonrecurring basis upon impairment and when acquired in a nonmonetary property exchange. During the six months ended June 30, 2010, we recorded impairment expense of $12.1 million on proved and unproved properties and gain on nonmonetary property exchange of $12.0 million related to proved Gulf of Mexico properties. The impairment charges reduce the oil and gas properties’ carrying values to their estimated fair values and are classified as Level 3. Fair value is calculated as the estimated discounted future net cash flows attributable to the assets. The gain on nonmonetary property exchange reflects the difference between the carrying value of the property surrendered and the estimated fair value of the property received, classified as Level 3, and is calculated based on the estimated discounted future net cash flows attributable to that asset.

The Company’s primary assumptions in preparing the estimated discounted future net cash flows to be recovered from oil and gas properties are based on (i) proved reserves and risk-adjusted probable and possible reserves, (ii) commodity forward-curve prices and assumptions as to costs and expenses, and (iii) the estimated discount rate that would be used by potential purchasers to determine the fair value of the assets.

Note 15 — Subsequent Events

Our evaluation has identified the following matters which require disclosure as events subsequent to June 30, 2010: During July 2010, we sold the deep rights to one of our producing deepwater blocks for $15 million. Also in July 2010, there were additional developments related to the deepwater drilling moratorium as discussed in Note 3, “Risks and Uncertainties.”

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 U.K. and Dutch Sectors of the North Sea. We seek to acquire and develop properties with proved undeveloped reserves (“PUD”) that are economically attractive to us but are not strategic to major or large exploration-oriented independent oil and gas companies. Occasionally we will acquire properties that are already producing or where previous drilling has encountered reservoirs that appear to contain commercially productive quantities of oil and gas even though the reservoirs do not meet the SEC definition of proved reserves. We believe that our strategy provides assets for us to develop and produce without the risk, cost or time of traditional exploration. Our management team has extensive engineering, geological, geophysical, technical and operational expertise in successfully developing and operating properties in both our current and planned areas of operation.

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

•

significant undeveloped reserves;

•

close proximity to developed markets for oil and natural gas;

•

existing infrastructure or the ability to install our own infrastructure of oil and natural gas pipelines and production/processing platforms;

•

opportunities to aggregate production and create operating efficiencies that capitalize upon our Hub concept; and

•

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

Our focus is on acquiring properties that are noncore or nonstrategic to their current 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 they believe offer greater reserve potential. Some projects may provide lower economic returns to a company due to the cost structure and focus of 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. With our cost structure and acquisition strategy, it is not unusual for us to have an acquisition cost of a property that is less than the total development costs incurred by the previous owner. This strategy, coupled with our expertise in our areas of focus and our ability to develop projects, tend to make our oil and gas property acquisitions more financially attractive to us than to the seller. Given our strategy of acquiring properties that contain proved reserves, or where previous drilling by others indicates to us the presence of recoverable hydrocarbons, our operations typically are lower risk than exploration-focused Gulf of Mexico and North Sea operators.

Since we operate a significant number of the properties in which we acquire a working interest, we are able to significantly influence the plans and timing of a project’s development. In addition, practically all of our properties have previously defined and targeted reservoirs, eliminating from our development plan the time necessary in typical exploration efforts to locate and determine the extent of oil and gas reservoirs. Without the exploration time constraint, 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. We may initiate new development projects by simultaneously obtaining the various required components such as the pipeline and the production platform or subsea well completion equipment. We believe this strategy, combined with our strong technical abilities to evaluate and implement a project’s requirements, gives us an advantage over exploration-oriented operators and allows us to efficiently complete development projects and commence production.

Beginning in 2003, we made a concerted effort to expand our presence into the deeper water of the Gulf of Mexico. In 2003 we acquired Mississippi Canyon (“MC”) Block 711 (now part of our Gomez Hub) in 3,000

feet of water; in 2005, we acquired MC Block 217 (now part of our Canyon Express Hub) in 7,000 feet of water; and in 2006, we acquired MC Block 941, MC Block 942 and Atwater Valley (“AT”) Block 63 (now part of our Telemark Hub) in 4,000 feet of water. The Telemark Hub was placed on production March 28, 2010 with the first well at AT 63. On June 15, 2010, we began completion operations of the MC 941 #3 well, the second development well. The third and fourth wells at our Telemark Hub are currently impacted by the revised drilling moratorium and cannot be completed until the moratorium for these types of wells is lifted. These two development wells are drilled to approximately 12,000 feet and require additional drilling to reach the target depth of approximately 20,000 feet. With the acquisition and subsequent development of these properties, our proved reserves in the deepwater Gulf of Mexico account for 62% of our total proved reserves as of December 31, 2009. Our proved reserves on the Gulf of Mexico Shelf account for 6% of our total proved reserves with the remaining 32% in the North Sea.

In conjunction with our move to the deeper water of the Gulf of Mexico, we also made the commitment to increase our investment in reusable floating infrastructure. We own interests in two floating production facilities, theATP Innovator and theATP Titan. TheATP Innovator is located in the Gulf of Mexico at our Gomez Hub and theATP Titan is located in the Gulf of Mexico at our Telemark Hub. These floating production facilities are fundamental to our hub strategy and business plan. We believe the presence of these facilities allows us a competitive advantage for additional acquisitions in a large area surrounding each installation. A third floating production facility called an Octabuoy is under construction in China for initial deployment at our Cheviot Hub in the U.K. North Sea during 2012. We operate theATP Innovator and theATP Titan and also expect to operate the Octabuoy when it is placed in service. The floating production facilities have longer useful lives than the underlying reserves and are capable of redeployment to new productive locations upon depletion of the reserves. Accordingly, they are expected to be moved several times over their useful lives.

Risks and Uncertainties

Results of Operations

Three Months Ended June 30, 2010 Compared to Three Months Ended June 30, 2009

For the three months ended June 30, 2010 and 2009 we reported net loss attributable to common shareholders of $82.9 million and $4.4 million, or $1.63 and $0.12 per diluted share, respectively.

Oil and Gas Production Revenues

Revenues presented in the table and the discussion below represent revenues from sales of oil and natural gas production volumes. The table below also includes oil and natural gas production revenues from amortization of deferred revenue related to the second quarter 2008 sale of the limited-term overriding royalty interest. We do not reflect any production volumes associated with those revenues.


	Three Months Ended June 30,				% Change from 2009
	2010		2009		to 2010
Production:
Oil and condensate (MBbl)		934		898	4	%
Natural gas (MMcf)		6,014		3,950	52	%
Total (MBoe)		1,937		1,556	24	%
Gulf of Mexico (MBoe)		1,783		1,393	28	%
North Sea (MBoe)		154		164	(6	%)

Revenues from production (in thousands):
Oil and condensate	$	65,492	$	52,764	24	%
Amortization of deferred revenue		7,864		9,015

Total	$	73,356	$	61,779	19	%


Natural gas	$	27,742	$	15,933	74	%
Effects of cash flow hedges		—		885
Amortization of deferred revenue		—		2,300

Total	$	27,742	$	19,118	45	%


Oil, condensate and natural gas	$	93,234	$	68,697	36	%
Effects of cash flow hedges		—		885
Amortization of deferred revenue		7,865		11,315

Total	$	101,099	$	80,897	25	%


Average realized sales price:
Oil and condensate average realized price (per Bbl)	$	70.12	$	58.76	19	%

Natural gas (per Mcf)	$	4.61	$	4.03	14	%
Effects of cash flow hedges (per Mcf)		—		0.22

Average realized price (per Mcf)	$	4.61	$	4.25	8	%


Gulf of Mexico (per Mcf)		4.47		3.97
North Sea (per Mcf)		5.41		5.18

Oil, condensate and natural gas (per Boe)	$	48.12	$	44.10	9	%
Effects of cash flow hedges (per Boe)		—		0.54

Average realized price (per Boe)	$	48.12	$	44.64	8	%


Gulf of Mexico (per Boe)		49.43		46.29
North Sea (per Boe)		33.12		30.65

Revenues from production increased in 2010 compared to 2009 due to a 24% increase in production and an 8% increase in average realized sales price. The production increase is in the Gulf of Mexico where our Canyon Express property has been returned to operation and production has commenced at the Telemark Hub The higher average realized sales price is due to increased commodity market prices.

Lease Operating

Lease operating expenses include costs incurred to operate and maintain wells. These costs include, among others, workover expenses, operator fees, processing fees and insurance. Lease operating expense was as follows (in thousands except per Boe amounts):


	Three Months Ended June 30,				% Change from 2009
	2010		2009		to 2010
Recurring operating expenses	$	25,650	$	16,595	55	%
Workover expenses		6,645		763	771	%

Lease operating	$	32,295	$	17,358	86	%


Recurring operating expenses per Boe	$	13.26	$	10.68	24	%
Gulf of Mexico		13.50		10.50	29	%
North Sea		10.08		12.00	(16	%)

Lease operating expense for the second quarter of 2010 increased $14.9 million compared to the second quarter of 2009. The increase in recurring operating expense was primarily due to additional insurance costs. The workover expenses during the second quarter of 2010 were primarily due to hydrate remediation and facilities inspection activities on our Gomez Hub. The North Sea per unit cost has decreased primarily due to the effect of higher production on fixed costs.

General and Administrative

General and administrative expenses are overhead-related expenses, including employee compensation, legal and accounting fees, insurance (other than that included in lease operating expense) and investor relations expenses. General and administrative expense was as follows:


	Three Months Ended June 30,				% Change from 2009
	2010		2009		to 2010
General and administrative (in thousands)	$	8,060	$	7,105	13	%
Per Boe		4.16		4.56	(9	%)

General and administrative expense increased $1.0 million from the second quarter of 2009. The increase was primarily due to a reversal of accrued compensation associated with a terminated employee bonus plan in 2009.

Depreciation, Depletion and Amortization

Depreciation, depletion and amortization (“DD&A”) expense was as follows:


	Three Months Ended June 30,				% Change from 2009
	2010		2009		to 2010
DD&A (in thousands)	$	60,115	$	43,575	38	%
Per Boe		31.02		28.02	11	%
Gulf of Mexico		30.54		25.56	19	%
North Sea		36.78		48.72	(25	%)

DD&A expense for the second quarter of 2010 increased compared to the second quarter of 2009 primarily due to amounts related to commencement of production at the Telemark Hub. The per unit increase in the Gulf of Mexico is primarily a result of higher costs incurred on our new developments relative to some of our older properties. The per unit decrease in the North Sea is primarily due to increases in reserves.

Impairment of Oil and Gas Properties

We recorded impairments during the three months ended June 30, 2010 and 2009 of $3.9 million and $0.7 million, respectively which were primarily related to unproved properties in the Gulf of Mexico. The 2010 amounts were associated with leases which were approaching their expiration dates and became unlikely to be drilled primarily due to the moratorium on drilling in the Gulf of Mexico discussed above.

Accretion of Asset Retirement Obligation

Accretion expense of $3.5 million in the second quarter of 2010 is increased compared to $3.0 million in the second quarter of 2009 primarily due to the addition of the future retirement obligations associated with our Telemark Hub.

Contract Termination Costs

During June 2010, we terminated a contract for services of a drilling rig as a result of the Gulf of Mexico deep water drilling moratorium discussed above. We obtained a full release from our obligations under the contract. We incurred net costs of $8.7 million as a result of terminating this contract.

Interest Expense, Net

Interest expense, net of amounts capitalized, was $64.6 million in the second quarter of 2010 compared to $10.2 million in the second quarter of 2009. In the second quarter of 2010, we capitalized interest of $3.0 million (related to Cheviot in the U.K.) compared to the second quarter of 2009 capitalized interest of $22.9 million ($21.3 million related to the Telemark Hub development and $1.6 million related to Cheviot). Interest expense has increased primarily because production commenced at the Telemark Hub and we ceased capitalizing related interest costs. Also, in the second quarter of 2010, we refinanced our long-term debt and increased our outstanding debt balance.

Derivative Income

Derivative income (loss) during the second quarter of 2010 was $23.9 million consisting of $30.3 million in the Gulf of Mexico and ($6.3) million in the North Sea. Derivative income during the second quarter of 2009 was $2.2 million ($1.0 million and $1.2 million in the Gulf of Mexico and North Sea, respectively). This income is related to net gains associated with our oil and gas price derivative contracts.

Loss on Debt Extinguishment

Loss on debt extinguishment in the second quarter of 2010 is $78.2 million. As discussed below, during the second quarter of 2010, we refinanced the Term Loans and charged to expense the remaining unamortized deferred financing costs, debt discount related to the retired debt and repayment premiums.

Income Tax (Expense) Benefit

We recorded income tax benefit of $57.8 million during the second quarter of 2010 resulting in an overall effective tax rate of 43%. In each jurisdiction, the rates were determined based on our expectations of net income or loss for the year, taking into consideration permanent differences. In the comparable quarter of 2009 we recorded income tax expense of $1.2 million resulting in an overall effective tax rate of 110%. The effective tax rate at June 30, 2010 differs from the statutory rates primarily because taxes are not provided for the noncontrolling interest of ATP-IP. Our current deferred tax asset at June 30, 2010 is based upon our forecast of taxable income and was reduced by $31.4 million from March 31, 2010 due to the impact of reductions in our forecast of income as a result of our new financings and updated forecasts of operating results for 2010.

Income Attributable to the Redeemable Noncontrolling Interest

Income attributable to the redeemable noncontrolling interest represents the 49% Class A limited partner interest in ATP Infrastructure Partners, LP (“ATP-IP”).

Convertible Preferred Stock Dividends

Convertible preferred stock dividends in 2010 represent declared cash dividends due for the three months ended June 30, 2010. The outstanding shares of convertible preferred stock accrue cumulative preferred dividends at the annual rate of 8% of the $140.0 million liquidation value.

Six Months Ended June 30, 2010 Compared to Six Months Ended June 30, 2009

For the six months ended June 30, 2010 and 2009 we reported net loss attributable to common shareholders of $83.8 million and $2.7 million, or $1.66 and $0.08 per diluted share, respectively.

Oil and Gas Production Revenues


	Six Months Ended June 30,				% Change from 2009
	2010		2009		to 2010
Production:
Oil and condensate (MBbl)		1,806		1,813	—
Natural gas (MMcf)		9,765		8,424	16	%
Total (MBoe)		3,434		3,217	7	%
Gulf of Mexico (MBoe)		3,116		2,955	5	%
North Sea (MBoe)		318		262	21	%

Revenues from production (in thousands):
Oil and condensate	$	127,968	$	88,426	45	%
Amortization of deferred revenue		16,967		18,419

Total	$	144,935	$	106,845	36	%


Natural gas	$	47,676	$	37,463	27	%
Effects of cash flow hedges		—		589
Amortization of deferred revenue		1,517		4,256

Total	$	49,193	$	42,308	16	%


Oil, condensate and natural gas	$	175,644	$	125,889	40	%
Effects of cash flow hedges		—		589
Amortization of deferred revenue		18,484		22,675

Total	$	194,128	$	149,153	30	%


Average realized sales price:
Oil and condensate average realized price (per Bbl)	$	70.86	$	48.77	45	%

Natural gas (per Mcf)	$	4.88	$	4.44	10	%
Effects of cash flow hedges (per Mcf)		–		0.07

Average realized price (per Mcf)	$	4.88	$	4.51	8	%


Gulf of Mexico (per Mcf)		4.74		4.31
North Sea (per Mcf)		5.50		5.01

Oil, condensate and natural gas (per Boe)	$	51.12	$	39.12	31	%
Effects of cash flow hedges (per Boe)		—		0.18

Average realized price (per Boe)	$	51.12	$	39.30	30	%


Gulf of Mexico (per Boe)		52.93		39.99
North Sea (per Boe)		33.83		31.40

Revenues from production increased in 2010 compared to 2009 due to a 30% increase in average realized sales price and a 7% increase in production. The higher average realized sales price is due to increased

commodity market prices. The production increase is primarily in the Gulf of Mexico where our Canyon Express property has been returned to operation and production has commenced at the Telemark Hub.

Lease Operating


	Six Months Ended June 30,				% Change from 2009
	2010		2009		to 2010
Recurring operating expenses	$	43,816	$	36,801	19	%
Workover expenses		18,114		771	2,249	%

Lease operating	$	61,930	$	37,572	65	%

Recurring operating expenses per Boe	$	12.78	$	11.46	12	%
Gulf of Mexico		13.02		11.10	17	%
North Sea		10.08		15.00	(33	%)

Lease operating expense for the first six months of 2010 increased $24.4 million compared to the first six months of 2009. The increase in recurring operating expense was primarily due to additional insurance costs. The workover expenses during the first six months of 2010 were primarily due to hydrate remediation activities on our Gomez Hub and Canyon Express Hub properties which enabled us to commence production at our new well at Kings Peak (MC Block 217) and to re-establish production from two wells at Aconcagua (MC Block 305). The costs for the first six months of 2009 included Hurricane Ike repairs. The North Sea per unit cost has decreased primarily due to the effect of higher production on fixed costs.

General and Administrative


	Six Months Ended June 30,				% Change from 2009
	2010		2009		to 2010
General and administrative (in thousands)	$	19,569	$	18,208	7	%
Per Boe		5.70		5.64	1	%

General and administrative expense increased $1.4 million from the first six months of 2009. The increase was primarily due to a reversal of accrued compensation associated with a terminated employee bonus plan in 2009.

Depreciation, Depletion and Amortization

Depreciation, depletion and amortization (“DD&A”) expense was as follows:


	Six Months Ended June 30,				% Change from 2009
	2010		2009		to 2010
DD&A (in thousands)	$	96,116	$	82,973	16	%
Per Boe		27.96		25.80	8	%
Gulf of Mexico		27.24		23.58	16	%
North Sea		35.39		50.70	(30	%)

DD&A expense for the first six months of 2010 increased compared to the first six months of 2009 primarily due to amounts related to commencement of production at the Telemark Hub. The per unit increase in the Gulf of Mexico is primarily a result of higher costs incurred on our new developments relative to some of our older properties. The per unit decrease in the North Sea is primarily due to increases in reserves.

Impairment of Oil and Gas Properties

We recorded impairments during the six months ended June 30, 2010 and 2009 of $12.1 million and $8.7 million, respectively. Of these amounts, $4.5 million and $0.7 million in the six months ended June 30, 2010 and 2009, respectively, were related to unproved properties in the Gulf of Mexico. The 2010 amounts were associated with leases which were approaching their expiration dates and became unlikely to be drilled primarily due to the moratorium on drilling in the Gulf of Mexico discussed above. We recorded impairments of proved properties during the six months ended June 30, 2010 and 2009 of $7.6 million and $8.0 million, respectively. These amounts represented the remaining carrying costs of those properties, and were primarily due to relinquishment of the leases. We also recorded a $1.0 million loss on abandonment related to the property impaired in 2009.

Accretion of Asset Retirement Obligation

Accretion expense of $6.9 million in first six months of 2010 is increased compared to $5.9 million in the first six months of 2009 primarily due to the addition of the future retirement obligations associated with our Telemark Hub.

Contract Termination Costs

Loss on Abandonment

We recognized aggregate loss on abandonment during the first six months of 2010 and 2009 which were the result of actual abandonment costs exceeding the previously accrued estimates, due to unforeseen circumstances that required additional work or the use of equipment more expensive than anticipated and unanticipated vendor price increases.

Gain on Exchange/Disposal of Properties

During January 2010, we consummated a nonmonetary exchange of our 10% nonoperated working interest in MC Block 800, for an incremental 50% working interest in MC Block 754, both proved undeveloped properties. The consolidated financial statements reflect the incremental interest acquired in MC Block 754 at fair value and removal of the carrying costs of MC Block 800, resulting in recognition of a $12.0 million gain.

Interest Expense, Net

Interest expense, net of amounts capitalized was $76.9 million in the first six months of 2010 compared to $22.8 million in the first six months of 2009. In the first six months of 2010, we capitalized interest of $46.2 million ($40.4 million related to the construction of the Telemark Hub development in the Gulf of Mexico and $5.8 million related to Cheviot in the U.K.) compared to the first six months of 2009 capitalized interest of $43.8 million ($41.0 million related to the Telemark Hub development and $2.8 million related to Cheviot). Interest expense has increased primarily because production commenced at the Telemark Hub and we ceased capitalizing related interest costs. Also, in the second quarter of 2010, we refinanced our long-term debt and increased our outstanding debt balance.

Derivative Income

Derivative income (loss) during the first six months of 2010 was $27.5 million consisting of $32.9 million in the Gulf of Mexico and ($5.4) million in the North Sea. Derivative income during the first six months of

2009 was $18.5 million ($13.2 million and $5.3 million in the Gulf of Mexico and North Sea, respectively). This income is related to net gains associated with our oil and gas price derivative contracts.

Loss on Debt Extinguishment

Income Tax (Expense) Benefit

We recorded income tax benefit of $56.4 million during the second half of 2010 resulting in an overall effective tax rate of 45%. In each jurisdiction, the rates were determined based on our expectations of net income or loss for the year, taking into consideration permanent differences. In the comparable period of 2009 we recorded income tax expense of $0.3 million resulting in an overall effective tax rate of 8%. The effective tax rate at June 30, 2010 differs from the statutory rates primarily because taxes are not provided for the noncontrolling interest of ATP-IP. Our current deferred tax asset at June 30, 2010 is based upon our forecast of taxable income and was reduced by $88.6 million from December 31, 2009 due to the impact of reductions in our forecast of income as a result of our new financings and updated forecasts of operating results for 2010.

Income Attributable to the Redeemable Noncontrolling Interest

Income attributable to the redeemable noncontrolling interest represents the 49% Class A limited partner interest in the earnings of ATP-IP. The amount of $8.2 million in the first six months of 2010 is higher than the first six months of 2009 amount primarily because of the inception of this arrangement in the middle of the first quarter 2009.

Convertible Preferred Stock Dividends

Convertible preferred stock dividends in 2010 represent declared cash dividends due for the six months ended June 30, 2010. The outstanding shares of convertible preferred stock accrue cumulative preferred dividends at the annual rate of 8% of the $140.0 million liquidation value.

Liquidity and Capital Resources

Historically, we have funded our acquisition and development activities through a combination of bank borrowings, proceeds from equity offerings, cash from operations, the sale or conveyance of interests in selected properties and vendor financings. The disarray in the credit markets that began in 2008 has continued into 2010. Capital market transactions are limited and when they can be completed they are more expensive than similar transactions in the past three years. Despite this, so far in 2010, we have refinanced the Term Loans and obtained additional financing from other transactions, all of which are discussed below.

In June 2010, we entered into a first lien credit agreement (the “New Credit Facility”) for $150.0 million, due October 15, 2014, to replace the Original Credit Facility. Proceeds of the New Credit Facility were $144.3 million, net of original issue discount and transaction fees. The New Credit Facility allows the Company to incur up to $350.0 million of additional indebtedness as Consolidated Net Tangible Assets increase.

During the first six months of 2010, we sold overriding royalty interests (primarily limited term) in future production from the Gomez Hub properties for cash proceeds of $121.1 million, net of costs. The dollar-denominated overriding royalty interests obligate us to deliver proceeds from the future sale of hydrocarbons from the specified properties equal to the purchasers’ original investment plus an overall rate of return. The

percentage of property revenues available to satisfy this obligation is dependent upon certain conditions specified in the agreement. Upon payment of the agreed dollar amounts, the ownership of the dollar-denominated interests reverts to us. Also during the first six months of 2010, we granted dollar-denominated overriding royalty interests in the form of net profits interests in certain of our oil and gas properties in and around the Telemark Hub and Gomez Hub and received cash proceeds of $49.5 million, net of costs.

We anticipate our 2010 cash capital expenditures (including abandonment) will be between $450 and $500 million, which is the level that we expect can be funded with cash on hand and cash flows from operations. Because of the uncertainty associated with the revised moratorium, our capital expenditures could increase or decrease from these levels. As operator of most of our projects under development, we have the ability to control the timing and extent of most of our capital expenditures should future market conditions warrant. Coupled with that control, we believe we have sufficient liquidity to enable us to meet our future capital and debt service requirements.

We desire to monetize selected assets during the remainder of 2010, and the ability of potential buyers to access the credit markets and the commodity price outlook may be important factors to our success in doing so. For example, we are actively in discussions to monetize a portion of our interest in theATP Titan. Still, we believe that we will be able to monetize more selected assets, providing us with additional capital for development activities. In the near term, our revenues, profitability and cash flows are highly dependent upon many factors, particularly our ability to bring other major development projects at Telemark on production, performance of other properties and the price of oil and natural gas. To mitigate future price volatility, we may continue to hedge the sales price of a portion of our future production.

For the longer term, we will continue to deploy the same or similar strategies. Operating our properties has always been a significant focus of our strategy. As stated previously, we believe operating our properties provides us the ability to control expenditures and adjust development timing and programs where needed. We do not expect to see a significant change in this focus over the next several years.

Cash Flows


	Six Months Ended June 30,
	2010			2009
Cash provided by (used in) (in thousands):
Operating activities	$	(17,789	)	$	95,065
Investing activities		(377,712	)		(361,094	)
Financing activities		493,039			145,731

We had working capital deficits of approximately $39.7 million and $26.4 million as of June 30, 2010 and December 31, 2009, respectively.

Cash provided by (used in) operating activities during the six months ended June 30, 2010 and 2009 was ($17.8) million and $95.1 million, respectively. Cash flow from operating activities decreased primarily due to increased interest expense, costs related to the extinguishment of long-term debt and lease operating expenses partially offset by increased oil and gas revenues discussed above and changes in working capital.

Cash used in investing activities was $377.7 million and $361.1 million during the six months ended June 30, 2010 and 2009, respectively. Cash expended in the Gulf of Mexico and North Sea for additions to oil and gas properties was approximately $354.0 million and $23.3 million, respectively, in the first six months of 2010. Cash expended in the Gulf of Mexico and North Sea for additions to oil and gas properties was approximately $312.5 million and $42.7 million, respectively, in the first six months of 2009.

Cash provided by financing activities was $493.0 million and $145.7 million during the six months ended June 30, 2010 and 2009, respectively. The amount in the first six months of 2010 is primarily related to $336.4 million net proceeds from the debt refinancing discussed in Note 6 “Long-term Debt” to the Consolidated Financial Statements, $46.0 million net proceeds from our prior revolving credit facility, $170.6 million proceeds net of costs from sales of limited-term overriding royalty interests and net profit interests discussed in Note 7, “Other Long-term Obligations,” to the Consolidated Financial Statements, partially offset by principal payments of Term Loans and other long-term obligations. The amount in the first six months of 2009 is from the sale of a

redeemable noncontrolling interest in ATP-IP and issuance of common stock partially offset by $58.7 million of debt repayments and $11.8 million of distributions to the noncontrolling interest of ATP-IP.

Long-term Debt

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


	June 30, 2010			December 31, 2009
First lien term loans, net of $2,995 unamortized discount	$	147,005		$	—
Senior second lien notes, net of $6,771 unamortized discount		1,493,229			—
Term Loans, net of $28,266 unamortized discount		—			1,216,685

Total debt		1,640,234			1,216,685
Less current maturities		(1,500	)		(16,838	)

Total debt—noncurrent	$	1,638,734		$	1,199,847

In June 2010, we entered into a first lien credit agreement (the “New Credit Facility”) with an initial balance of $150.0 million, due May 15, 2014, to replace the Original Credit Facility. Proceeds of the New Credit Facility were $144.3 million, net of original issue discount and transaction fees. Principal outstanding under the term loans issued pursuant to the New Credit Facility bears interest at an annual rate of 11.0%. As security for the Company’s obligations under the New Credit Facility, the Company granted the lenders a security interest in and a first lien on 80% of its proved oil and gas reserves in the Gulf of Mexico, capital stock of material subsidiaries (limited in the case of the Company’s non-U.S. subsidiaries to not more than 65% of the capital stock) and, initially, certain infrastructure assets, which are subject to release. Principal of $750,000 is due each June 18 and December 18 beginning December 18, 2010 until June 18, 2014. The remaining balance is due October 15, 2014. The New Credit Facility allows the Company to incur additional indebtedness up to $350.0 million as Consolidated Net Tangible Assets increase.

New Credit Facility contains certain negative covenants which place limits on the Company’s ability to, among other things:

•

incur additional indebtedness;

•

pay dividends on the Company’s capital stock or purchase, repurchase, redeem, defease or retire the Company’s capital stock or subordinated indebtedness;

•

make investments outside of our normal course of business;

•

incur liens;

•

create any consensual restriction on the ability of the Company’s restricted subsidiaries to pay dividends, make loans or transfer property to the Company;

•

engage in transactions with affiliates;

•

sell assets; and

•

consolidate, merge or transfer assets.

Contractual Obligations

The following table summarizes certain contractual obligations at June 30, 2010 (in thousands):


	Total		Less than 1 year		1 – 3 years		3 – 5 years		More than 5 years
First lien term loans	$	150,000	$	1,500	$	3,000	$	145,500	$	—
Interest on first lien term loans (1)		69,466		16,459		32,423		20,584		—
Senior second lien notes		1,500,000		—		—		1,500,000		—
Interest on senior second lien notes (1)		860,938		178,125		356,250		326,563		—
Other long-term obligations (2)		206,848		43,824		124,691		20,000		18,333
Other trade commitments		15,570		13,320		2,250		—		—
Noncancelable operating leases		1,298		837		461		—		—

Total contractual obligations	$	2,804,120	$	254,065	$	519,075	$	2,012,647	$	18,333

(1)	Interest is based on rates and principal repayment requirements in effect at June 30, 2010.

(2)

Omitted from other long-term obligations in this table are $278.4 million of net profits interests payable and overriding royalty interests of $100.6 million as of June 30, 2010 that are payable only from the future cash flows of specified properties. The ultimate amount and timing of the payments will depend on production from the properties and future commodity prices and operating costs. Included in the table above are $25.6 million of contractual commitments that are expected to be paid that are not yet incurred.

Our liabilities include asset retirement obligations (“ARO”) ($43.7 million current and $111.0 million long-term) that represent our estimate of the amount at June 30, 2010 of our obligations with respect to the retirement/plugging and abandonment of our oil and gas properties. The ultimate settlement amounts and the timing of the settlements of such obligations are uncertain because they are subject to, among other things, federal, state and local regulation, economic and operational factors. Consequently, ARO is not reflected in the table above.

Commitments and Contingencies

Management is periodically faced with uncertainties, the outcomes of which are not within its control and will not be known for a long time. We are involved in actions from time to time, which if determined adversely, could have a material negative impact on our financial position, results of operations and cash flows. Management, with the assistance of counsel makes estimates, if determinable, of our 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 as of June 30, 2010. See Note 12, “Commitments and Contingencies” to Consolidated Financial Statements in Item 1 for additional discussion.

Accounting Pronouncements

See Note 2, “Recent Accounting Pronouncements” to Consolidated Financial Statements in Item 1 for a discussion of recently issued accounting pronouncements.

Critical Accounting Policies

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

consolidated financial statements. Critical accounting policies have not changed materially from those disclosed on our 2009 Annual Report on Form 10-K .

Item 3.

Quantitative and Qualitative Disclosures about Market Risks

Interest Rate Risk

We have essentially no exposure to changes in interest rates because the interest rate on long-term debt is fixed as discussed in Note 6, “Long-term Debt” to Consolidated Financial Statements in Item 1.

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 and operations due to fluctuations in the value of the local currency relative to the U.S. dollar arising from the process of re-measuring the local currency in U.S. dollars.

Commodity Price Risk

Our revenues, profitability and future growth depend substantially on prevailing prices for oil and natural gas. Prices also affect the amount of cash flow available for capital expenditures and our ability to borrow and raise additional capital. Lower prices may also reduce the amount of oil and natural gas that we can economically produce. We currently sell a portion of our oil and natural gas production under market price contracts. We periodically use derivative instruments to hedge our commodity price risk. We hedge a portion of our projected oil and natural gas production through a variety of financial and physical arrangements intended to support oil and natural gas prices at targeted levels and to manage our exposure to price fluctuations. We may use futures contracts, swaps, put options, price collars and fixed-price physical forward contracts to hedge our commodity prices. See Note 11, “Derivative Instruments and Risk Management Activities” to Consolidated Financial Statements in Item 1.

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

Item 4.

Controls and Procedures

Evaluation of Disclosure Controls and Procedures

Our management, under the supervision of and with the participation of our chief executive officer and chief financial officer has 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, 2010 (the “Evaluation Date”). Based on this evaluation, the chief executive officer and chief financial officer have concluded that ATP’s disclosure controls and procedures were not effective as of the Evaluation Date due to the material weakness in internal control over financial reporting described below. Disclosure controls and procedures are those controls and procedures designed to provide reasonable assurance that information that is required to be disclosed by ATP in the reports it files or submits under the Exchange Act is (i) recorded, processed, summarized and reported, within the time periods specified in the Securities and Exchange Commission’s rules and forms and (ii) accumulated and communicated to ATP’s management, including our chief executive officer and chief financial officer, as appropriate to allow timely decisions regarding required disclosure.

In preparing our Exchange Act filings, including this Quarterly Report on Form 10-Q, we implemented additional processes and procedures to provide reasonable assurance that the identified material weakness in our internal control over financial reporting was mitigated with respect to the information that we are required to disclose. As a result, we believe the Company’s consolidated financial statements included in this Quarterly Report on Form 10-Q present fairly, in all material respects, the Company’s financial position, results of operations and cash flows for the periods presented.

Material Weakness in Internal Control over Financial Reporting

A material weakness is a deficiency, or combination of deficiencies, such that there is a reasonable possibility that a material misstatement of the annual or interim financial statements will not be prevented or detected on a timely basis. At December 31, 2009, we identified the following material weakness which continues to exist as of the Evaluation Date:

We did not maintain effective controls over accounting for outstanding liabilities. Specifically, our procedures were not adequate to ensure proper cut-off associated with goods received or services rendered by our vendors and that liabilities were recorded in the appropriate periods.

Changes in Internal Control Over Financial Reporting

As discussed in the remediation section below, during the three months ended June 30, 2010, we have made changes to our internal controls over financial reporting that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

Remediation Plan

We believe that the material weakness identified at December 31, 2009 was attributable to factors caused by the substantial activity at year-end 2009 focused on the completion of our major development project at our Telemark Hub. During the six months ended June 30, 2010, we have enhanced our processes to address such changes in activity by implementing new procedures to seek out additional information from major vendors at each balance sheet date to ensure that we have adequate information to ensure proper cut-off when preparing capital accruals. We believe those process changes have adequately improved our controls over accounting for outstanding liabilities but will perform additional tests in future periods to ensure the controls around this area are operating effectively. After performing additional tests, we will evaluate the effectiveness of those controls in order to conclude if the material weakness has been remediated.

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 2009 Annual Report on Form 10-K with additional factors discussed in Item 1A of this Quarterly Report.

PART II. OTHER INFORMATION

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

Item 1.

Legal Proceedings.

No material changes in any legal proceeding have occurred since our last report.

Item 1A.

Risk Factors.

Our operations in the deepwater Gulf of Mexico could be adversely affected by changes in laws and regulations which are expected to occur as a result of the Deepwater Horizon incident.

Potential regulations regarding derivatives could adversely impact our ability to engage in commodity price risk management activities.

We use derivative instruments to manage our commodity price risk. The Dodd-Frank Wall Street Reform and Consumer Protection Act, or the Dodd-Frank Act, which was signed into law in July 2010, contains measures aimed at increasing the transparency and stability of the over-the-counter, or OTC, derivative markets and preventing excessive speculation. The Dodd-Frank Act could restrict trading positions in the energy futures markets. If we are required to post collateral as a result of new legislation, we would have to do so by utilizing cash or letters of credit, which would reduce our liquidity position and increase costs. These changes could materially reduce our hedging opportunities and increase the costs associated with our hedging programs, both of which could negatively affect our cash flow.

Item 6.

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		Statement of Resolutions Establishing the 8.00% Convertible Perpetual Preferred Stock of ATP Oil & Gas Corporation, incorporated by reference to Exhibit 4.4 of Registration Statement No. 333-162574 on Form S-3 of ATP filed October 19, 2009.

3.3		Third Amended and Restated Bylaws of ATP Oil & Gas Corporation, incorporated by reference to Exhibit 3.1 of ATP’s Current Report on Form 8-K filed December 15, 2009.

3.4		Amended and Restated Certificate of Formation, incorporated by reference to Exhibit 3.1 of ATP’s Current Report on Form 8-K filed June 4, 2010.

4.1		Indenture dated as of April 23, 2010 between the Company and The Bank of New York Mellon Trust Company, N.A., as trustee (“Trustee”), incorporated by reference to Exhibit 4.1 to ATP’s Current Report on Form 8-K dated April 29, 2010.

4.2		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.

4.3		Form of Stock Certificate for 8.00% Convertible Perpetual Preferred Stock, incorporated by reference to Exhibit 4.1 of ATP’s Form 8-K dated September 29, 2009.

10.1		Registration Rights Agreement dated as of April 23, 2010 between the Company and J.P. Morgan Securities Inc., incorporated by reference to Exhibit 10.2 to ATP’s Current Report on Form 8-K dated April 29, 2010.

10.2		Credit Agreement dated as of June 18, 2010 among ATP Oil & Gas Corporation, Credit Suisse AG and the lenders party thereto, incorporated by reference to Exhibit 10.1 of ATP’s Current Report on Form 8-K dated June 18, 2010.


†10.3		ATP Oil & Gas Corporation 2010 Stock Plan incorporated by reference to Appendix A to ATP’s Schedule 14A dated April 29, 2010.

10.4		Intercreditor Agreement dated as of April 23, 2010 among the Company, the Trustee and Credit Suisse AG, incorporated by reference to Exhibit 10.3 to ATP’s Current Report on Form 8-K dated April 29, 2010.

10.5		Sale and Purchase Agreement between ATP Oil & Gas (UK) Limited and EDF Production UK Ltd., as amended and restated on October 23, 2008, incorporated by reference to Exhibit 10.1 to ATP’s Report on Form 10-Q for the quarter ended September 30, 2008.

†10.6		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.

†10.7		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.

†10.8		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.

†10.9		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.

†10.10		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.

†10.11		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.

†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.

†10.17		Employment Agreement between ATP and George R. Morris, dated May 27, 2008, incorporated by reference to Exhibit 99.1 to ATP’s Form 8-K dated May 21, 2008.

†10.18		All Employee Bonus Policy, incorporated by reference to exhibit 10.16 to ATP’s Annual Report on Form 10-K for the year ended December 31, 2008.

†10.19		Discretionary Bonus Policy, incorporated by reference to exhibit 10.17 to ATP’s Annual Report on Form 10-K for the year ended December 31, 2008.

10.20		Purchase Agreement dated September 23, 2009 among the Company, J.P. Morgan Securities Inc. and Credit Suisse Securities (USA) LLC, as representatives of the several Initial Purchasers named therein, incorporated by reference to Exhibit 10.1 of ATP’s Form 8-K dated September 29, 2009.

21.1		Subsidiaries of ATP, incorporated by reference to Exhibit 21.1 to ATP’s Report on Form 10-Q for the quarter ended March 31, 2009.

*31.1		Certification of Principal Executive Officer pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934, the “Act.”

*31.2		Certification of Principal Financial Officer pursuant to Rule 13a-14(a) of the Act

*32.1		Certification of Principal Executive Officer pursuant to 18 U.S.C. Section 1350

*32.2		Certification of Principal Financial Officer pursuant to 18 U.S.C. Section 1350

†	Management contract or compensatory plan or arrangement

*	Filed herewith

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 9, 2010	By:	/S/ ALBERT L. REESE JR.
		Albert L. Reese Jr. Chief Financial Officer
		Albert L. Reese Jr. Chief Financial Officer

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

Large accelerated filer

Accelerated filer

Non-accelerated filer

Smaller reporting company