Atp Oil & Gas 10Q 2009 Q2 Quarterly report

Atp Oil & Gas (ATPGQ) Inactive 10-Q2009 Q2 Quarterly report

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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, 2009

¨	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 definition 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 6, 2009, was 44,783,420.

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

TABLE OF CONTENTS


		Page
PART I. FINANCIAL INFORMATION

Item 1. Financial Statements (Unaudited)

Consolidated Balance Sheets: June 30, 2009 and December 31, 2008		3

Consolidated Statements of Operations: For the three and six months ended June 30, 2009 and 2008		4

Consolidated Statements of Cash Flows: For the six months ended June 30, 2009 and 2008		5

Consolidated Statements of Equity: For the six months ended June 30, 2009		6

Consolidated Statements of Comprehensive Income (Loss): For the three and six months ended June 30, 2009 and 2008		7

Notes to Consolidated Financial Statements		8

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		20

Item 3. Quantitative and Qualitative Disclosures about Market Risks		31

Item 4. Controls and Procedures		31

PART II. OTHER INFORMATION		33

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, 2009			December 31, 2008
Assets
Current assets:
Cash and cash equivalents	$	100,190		$	214,993
Restricted cash		5,726			—
Accounts receivable (net of allowance of $204 and $352, respectively)		74,820			93,915
Deferred tax asset		35,629			39,150
Derivative asset		1,404			15,366
Other current assets		19,062			11,954

Total current assets		236,831			375,378

Oil and gas properties (using the successful efforts method of accounting):
Proved properties		3,148,366			2,802,315
Unproved properties		15,124			14,705

		3,163,490			2,817,020
Less accumulated depletion, depreciation, impairment and amortization		(1,033,520	)		(944,817	)

Oil and gas properties, net		2,129,970			1,872,203

Furniture and fixtures (net of accumulated depreciation)		450			470
Deferred financing costs, net		11,589			13,493
Other assets, net		14,454			14,066

Total assets	$	2,393,294		$	2,275,610


Liabilities and Equity
Current liabilities:
Accounts payable and accruals	$	191,784		$	277,914
Current maturities of long-term debt		10,500			10,500
Asset retirement obligation		35,923			32,854
Derivative liability		645			8,114
Deferred tax liability		148			—
Other current liabilities		9,159			9,537

Total current liabilities		248,159			338,919

Long-term debt		1,302,694			1,356,130
Asset retirement obligation		102,404			99,254
Deferred tax liability		105,161			101,953
Derivative liability		2,262			1,194
Deferred revenue		36,554			59,229
Net profits interests		43,267			—
Other liabilities		3,699			2,582

Total liabilities		1,844,200			1,959,261

Commitments and contingencies (Note 14)

Temporary equity – redeemable noncontrolling interest		139,609			—

Shareholders’ equity:
Preferred stock: $0.001 par value, 10,000,000 shares authorized; none issued		—			—
Common stock: $0.001 par value, 100,000,000 shares authorized; 44,859,260 issued and 44,783,420 outstanding at June 30, 2009; 35,979,170 issued and 35,903,330 outstanding at December 31, 2008		45			36
Additional paid-in capital		472,809			400,334
Retained earnings		26,914			29,644
Accumulated other comprehensive loss		(89,372	)		(112,754	)
Treasury stock, at cost		(911	)		(911	)

Total shareholders’ equity		409,485			316,349
Total equity		549,094			316,349

Total liabilities and equity	$	2,393,294		$	2,275,610

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 June 30,						Six Months Ended June 30,
	2009			2008			2009			2008
Revenues:
Oil and gas production	$	80,897		$	191,809		$	149,153		$	417,846
Insurance proceeds and other		—			—			13,664			897

		80,897			191,809			162,817			418,743


Costs, operating expenses and other:
Lease operating		17,358			23,770			37,572			48,388
Exploration		93			—			267			—
General and administrative		7,105			8,831			18,208			18,067
Depreciation, depletion and amortization		43,575			79,873			82,973			169,272
Impairment of oil and gas properties		699			—			8,748			—
Accretion of asset retirement obligation		3,041			4,281			5,945			8,581
Loss on abandonment		16			1,036			1,013			1,413
Other, net		140			(264	)		288			(110	)

		72,027			117,527			155,014			245,611

Income from operations		8,870			74,282			7,803			173,132


Other income (expense):
Interest income		160			644			373			1,872
Interest expense, net		(10,174	)		(24,236	)		(22,797	)		(52,363	)
Derivative income (expense)		2,212			(50,190	)		18,457			(50,150	)
Loss on debt extinguishment		—			(24,220	)		—			(24,220	)

		(7,802	)		(98,002	)		(3,967	)		(124,861	)


Income (loss) before income taxes		1,068			(23,720	)		3,836			48,271


Income tax (expense) benefit:
Current		732			2,078			354			(10,358	)
Deferred		(1,906	)		9,862			(654	)		(2,848	)
				��
		(1,174	)		11,940			(300	)		(13,206	)


Net income (loss)		(106	)		(11,780	)		3,536			35,065
Less net income attributable to the redeemable noncontrolling interest		(4,260	)		—			(6,266	)		—

Net income (loss) attributable to common shareholders	$	(4,366	)	$	(11,780	)	$	(2,730	)	$	35,065


Net income (loss) per share attributable to common shareholders:

Basic	$	(0.12	)	$	(0.33	)	$	(0.08	)	$	0.98

Diluted	$	(0.12	)	$	(0.33	)	$	(0.08	)	$	0.97


Weighted average number of common shares:
Basic		36,878			35,440			36,251			35,631
Diluted		36,878			35,440			36,360			36,072

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,
	2009			2008
				(Restated)
Cash flows from operating activities
Net income	$	3,536		$	35,065
Adjustments to reconcile net income to net cash provided by operating activities –
Depreciation, depletion and amortization		82,973			169,272
Impairment of oil and gas properties		8,748			—
Accretion of asset retirement obligation		5,945			8,581
Deferred income taxes		654			2,848
Derivative expense		17,914			49,054
Loss on extinguishment of debt		—			15,370
Stock-based compensation		4,280			5,795
Amortization of deferred revenue		(22,675	)		(6,856	)
Noncash interest expense		7,435			8,942
Other noncash items, net		1,949			2,859
Changes in assets and liabilities –
Accounts receivable and other current assets		15,137			10,938
Accounts payable and accruals		(31,222	)		(24,474	)
Other assets		391			13

Net cash provided by operating activities		95,065			277,407


Cash flows from investing activities
Additions to oil and gas properties		(355,258	)		(461,623	)
Increase in restricted cash		(5,726	)		—
Proceeds from disposition of oil and gas properties		—			82,450
Additions to furniture and fixtures		(110	)		(93	)

Net cash used in investing activities		(361,094	)		(379,266	)


Cash flows from financing activities
Proceeds from long-term debt		—			1,608,750
Payments of long-term debt		(58,664	)		(1,401,653	)
Deferred financing costs		—			(15,391	)
Issuance of common stock		68,397			—
Net profits interest payments		(907	)		(10,871	)
Sale of redeemable noncontrolling interest, net of issuance costs		148,751			—
Limited partner distributions		(11,846	)		—
Exercise of stock options		—			28

Net cash provided by financing activities		145,731			180,863


Effect of exchange rate changes on cash and cash equivalents		5,495			(130	)


Increase (decrease) in cash and cash equivalents		(114,803	)		78,874
Cash and cash equivalents, beginning of period		214,993			199,449


Cash and cash equivalents, end of period	$	100,190		$	278,323


Noncash investing and financing activities
Decrease in accrued property additions	$	(71,593	)	$	44,942
Property additions in exchange for net profits interests		43,267			—
Asset retirement costs capitalized		460			2,147
Accrued distributions to noncontrolling interest		3,562			—

See accompanying notes to consolidated financial statements.

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF EQUITY

(In Thousands)

(Unaudited)


	Six Months Ended June 30, 2009
	Shares	Amount
Temporary Equity—Redeemable Noncontrolling Interest
Balance, beginning of period		$	—
Sale of Class A Limited Partner Interest, net of issuance costs			148,751
Net income attributable to the redeemable noncontrolling interest			6,266
Limited partner distributions			(15,408	)

Balance, end of period			139,609


Shareholders’ Equity:

Preferred Stock
Balance, beginning of period	—		—

Balance, end of period	—		—


Common Stock
Balance, beginning of period	35,903		36
Issuance of common stock	8,750		9
Issuance of restricted stock, net	130		–

Balance, end of period	44,783		45


Paid-in Capital
Balance, beginning of period			400,334
Issuance of common stock, net of issuance costs			68,195
Stock-based compensation			4,280

Balance, end of period			472,809


Retained Earnings
Balance, beginning of period			29,644
Net loss attributable to common shareholders			(2,730	)

Balance, end of period			26,914


Accumulated Other Comprehensive Loss
Balance, beginning of period			(112,754	)
Other comprehensive income			23,382

Balance, end of period			(89,372	)


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

Balance, end of period	76		(911	)


Total Shareholders’ Equity			409,485


Total Equity		$	549,094

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 June 30,						Six Months Ended June 30,
	2009			2008			2009			2008
Net income (loss)	$	(106	)	$	(11,780	)	$	3,536		$	35,065


Other comprehensive income (loss):
Reclassification adjustment for settled hedge contracts (net of taxes of $442, ($3,826), $295 and ($4,905), respectively)		(442	)		4,379			(295	)		5,851
Changes in fair value of outstanding hedge positions (net of taxes of ($619), $19,368, ($3,369) and $31,157, respectively)		619			(18,730	)		3,369			(32,994	)
Reclassification adjustment for dedesignated hedge contracts (net of taxes of $0, $(19,288), $0 and ($19,288), respectively)		—			21,258			—			21,258
Foreign currency translation adjustment		20,551			(324	)		20,308			364

Other comprehensive income (loss)		20,728			6,583			23,382			(5,521	)


Comprehensive income (loss)		20,622			(5,197	)		26,918			29,544
Less comprehensive income attributable to the redeemable noncontrolling interest		(4,260	)		—			(6,266	)		—

Comprehensive income (loss) attributable to common shareholders	$	16,362		$	(5,197	)	$	20,652		$	29,544

See accompanying notes to consolidated financial statements.

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 1 — Organization

ATP Oil & Gas Corporation (“ATP”) 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 new 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 2008 Annual Report on Form 10-K. The results of operations for the quarter and year-to-date periods ended June 30, 2009 are not necessarily indicative of results to be expected for the entire year. We have reclassified certain amounts applicable to prior periods to conform to the current classifications. During the second quarter, we also changed the description and classification of the noncontrolling interest as reflected in our first quarter balance sheet to a redeemable noncontrolling interest within total equity in order to reflect the contingent redemption priority that the Class A unit holders (see Note 6, “Formation of Limited Partnership”) would have in the event a change of control of ATP, as defined in our credit agreement, were to occur. These reclassifications did not affect net income, shareholders equity or total equity.

Statements of Cash Flows

During the fourth quarter of 2008, we discovered errors in each of our statements of cash flows included in our previously filed Forms 10-Q for the quarters ended March 31, June 30 and September 30, 2008. This was the result of not properly considering the application of wire transfer payments in the determination of accrued capital expenditures. The net change in accrued capital expenditures is excluded as a noncash operating and investing activity. This resulted in an understatement of operating cash inflows and an understatement of investing cash outflows in each of the year-to-date cash flow statements included in the respective 10-Q filings.

The information about cash inflows and (outflows) that follows is for only those consolidated statement of cash flows line items affected by the restatement (in thousands):


	Six Months Ended June 30, 2008
	As Reported			As Restated
Accounts payable and accruals	$	(137,089	)	$	(24,474	)
Net cash provided by operating activities		164,792			277,407

Additions to oil and gas properties		(349,008	)		(461,623	)
Net cash used in investing activities		(266,651	)		(379,266	)

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Fair Value of Financial Instruments

For cash and cash equivalents, receivables and payables, the carrying amounts approximate fair value because of the short maturity of these instruments. The interest rate on our long-term debt is variable and is based on London Interbank Offered Rates (“LIBOR”) subject to a minimum LIBOR of 3.25%. The fair value of the debt as of June 30, 2009 was approximately $1.17 billion.

Note 2 — Recent Accounting Pronouncements

During December 2008, the SEC issued the final rule, “Modernization of Oil and Gas Reporting” (“Final Rule.”) The Final Rule adopts revisions to the SEC’s oil and gas reporting disclosure requirements and is effective for annual reports on Forms 10-K for years ending on or after December 31, 2009. The revisions are intended to provide investors with a more meaningful and comprehensive understanding of oil and gas reserves to help investors evaluate their investments in oil and gas companies. The amendments are also designed to modernize the oil and gas disclosure requirements to align them with current practices and changes in technology. Revised requirements in the Final Rule include, but are not limited to:

•

Economic producibility of oil and gas reserves must be calculated using the unweighted arithmetic average of the first day of the month price for each month within the prior 12 month period, rather than year-end prices;

•

Companies will be allowed to report, on an optional basis, probable and possible reserves;

•

Nontraditional reserves, such as oil and gas extracted from coal and shales, will be included in the definition of “oil and gas producing activities;”

•

Companies will be permitted to use new technologies to determine proved reserves, as long as those technologies have been demonstrated empirically to lead to reliable conclusions with respect to reserve volumes;

•

Companies will be required to disclose, in narrative form, additional details on their proved undeveloped reserves (PUDs), including the total quantity of PUDs at year end, any material changes to PUDs that occurred during the year, investments and progress made to convert PUDs to developed oil and gas reserves and an explanation of the reasons why material concentrations of PUDs in individual fields or countries have remained undeveloped for five years or more after disclosure as PUDs; and

•

Companies will be required to report the qualifications and measures taken to assure the independence and objectivity of any business entity or employee primarily responsible for preparing or auditing the reserves estimates.

We are currently evaluating the potential impact of adopting the Final Rule.

In February 2009, the Financial Accounting Standards Board (“FASB”) issued Staff Position (“FSP”) FAS 141(R)-1, “Accounting for Assets Acquired and Liabilities Assumed in a Business Combination That Arise from Contingencies,” which will amend the provisions related to the initial recognition and measurement, subsequent measurement and disclosure of assets and liabilities arising from contingencies in a business combination under Statement of Financial Accounting Standards No. 141(R), “Business Combinations.” This standard has no impact on our financial statements at this time.

In May 2009, the FASB issued FAS No. 165 “Subsequent Events” to establish general standards of accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued or are available to be issued. We have adopted this standard with no current impact to our financial statements.

In June 2009, the FASB issued FAS No. 166, “Accounting for Transfer of Financial Assets, an amendment of FASB Statement No. 140,” which modifies and clarifies the requirements of FAS No. 140. The standard is effective for annual reporting periods beginning after November 15, 2009. Presently, we do not anticipate that adoption of this standard will have an impact on our financial statements.

In June 2009, the FASB issued FAS No. 167, “Amendments to FASB Interpretation No. 46(R),” which modifies the requirements of FASB Interpretation No. 46(R). The standard is effective for financial statements issued after November 15, 2009. Presently, we do not anticipate that adoption of this standard will have an impact on our financial statements.

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

In June 2009, the FASB issued FAS No. 168, “The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles, a replacement of FASB Statement No. 162,” which codifies existing GAAP and recognizes only two levels of GAAP, authoritative and nonauthoritative. The standard is effective for financial statements issued after September 15, 2009 and we do not anticipate that it will have a material effect on our financial statements.

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 there can be no assurance that oil and gas prices will not be subject to wide fluctuations in the future. Prices for oil and gas have recently declined materially. Any continued and 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 obligations required under our June 2008 senior secured term loan facility (“Term Loans”).

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 decisions and 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. Approximately 84% of our total proved reserves are undeveloped. 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 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 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 if we were to experience operational problems, uninsured events, or a continuation of adverse commodity prices resulting in the curtailment of production in any of these wells, our current and future production levels would be adversely affected, which may materially affect our financial condition, results of operations and cash flows.

Our Term Loans impose restrictions on us that increase our vulnerability in the current adverse economic and industry climate, and may limit our ability to obtain financing. We are currently in negotiations to execute transactions that will provide additional funds to us to support our capital expenditure program and reduce our outstanding indebtedness. Given current market conditions, our ability to access the capital markets, consummate planned asset sales and close any of the transactions currently in negotiation or planned may be restricted at a time when we would like or need to raise additional capital. Our inability to satisfy the covenants or other contractual requirements contained in our Term Loans would constitute an event of default. A default could result in our outstanding debt becoming immediately due and payable. If this were to occur, we might not be able to obtain waivers or secure alternative financing to satisfy our obligations either of which would have a material adverse impact on our business. Further, the current economic conditions could also impact our lenders, customers and hedging counterparties and may cause them to fail to meet their obligations to us with little or no warning.

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Although we believe that we will have adequate liquidity to meet our future capital requirements and to remain compliant with the covenants under our Term Loans, the factors described above create uncertainty. We intend to fund our near-term development projects utilizing cash on hand, planned asset sales and cash flows from operations. We have also recently conveyed to certain vendors limited-term net profits interests in our Telemark Hub and Clipper (defined below) oil and gas properties in exchange for development services and equipment to be provided. 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. To the extent we are successful in selling selected assets, we may use the proceeds in excess of our required debt repayments to fund additional development opportunities, to further reduce our debt or for added liquidity. 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 concept and its 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 allows us to match our capital commitments to our available capital resources.

Note 4 — Income Taxes

Income tax expense during interim periods is based on the estimated annual effective income tax rate. These rates deviate from statutory rates due to the impact of permanent and other rate-driving differences relative to pretax income (loss) in the jurisdiction in which it is generated. We employ an asset and liability approach that results in the recognition of deferred tax liabilities and assets for the expected future tax consequences of temporary differences between the financial basis and the tax basis of those assets and liabilities. We recognized income tax expense of $1.2 million and benefit of $11.9 million for the three months ended June 30, 2009 and 2008, respectively. We recognized income tax expense of $0.3 million and $13.2 million for the six months ended June 30, 2009 and 2008, respectively. The worldwide effective tax expense (benefit) rates for the three months ended June 30, 2009 and 2008 were 110% and (50%), respectively. The worldwide effective tax rates for the first six months of 2009 and 2008 were 8% and 27%, respectively.

Note 5 — Oil and Gas Properties

Acquisitions

During the first half of 2009, we paid $0.2 million to acquire a 55.3% working interest in Green Canyon Block 344, a lease with unproved reserves south of our Green Canyon Blocks 299 and 300 properties in the Gulf of Mexico. Also in the first half of 2009, we were awarded a 50% equity interest in the U.K. North Sea Block 9/21a.

During the first half of 2008, we acquired a 100% working interest in MC Block 304 and a 55% working interest in the proven reserves at Green Canyon Blocks 299 and 300 (collectively “Clipper”). Also during this period, we were awarded leases for 100% of the working interests in the unproved reserves at Viosca Knoll Block 863 and De Soto Canyon Block 355 by the MMS. The total cash paid for these acquisitions was $1.2 million.

Impairment of Oil and Gas Properties

During the second quarter and first six months of 2009, we recorded impairment expense of $0.7 million and $8.7 million, respectively, related to Gulf of Mexico shelf properties. The impairment was primarily due to relinquishment of a lease related to poor operating performance. All of the carrying costs related to this property have been written off to impairment expense. We also recorded a $1.0 million loss on abandonment related to this property.

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 6 — Formation of Limited Partnership

On March 6, 2009, along with GE Energy Financial Services (“GE”), we formed ATP-IP to own theATP Innovator, the floating production facility that currently serves our Mississippi Canyon Block 711 Gomez Hub properties. We contributed theATP Innovatorin exchange for a 49% subordinated limited partner interest and a 2% general partner interest. GE paid $150.0 million to ATP-IP for a 49% Class A limited partner interest. We remain the operator and continue to hold a 100% working interest in the Gomez field and its oil and gas reserves. The transaction was effective June 1, 2008 and allows us exclusive use of theATP Innovatorduring the term of the Platform Use Agreement (“PUA”), which is expected to be the economic life of the Gomez Hub reserves.

From an operational standpoint, during the term of the PUA, we are obligated to pay to ATP-IP a per unit fee for all hydrocarbons processed by theATP Innovator, subject to a minimum throughput fee of $53,000 per day. Such minimum fees, if applicable, can be recovered by the company in future periods whenever fees owed during a month exceed the minimum due. We may also be subject to a minimum fee of $53,000 per day for up to 180 days in the event a loss event occurs, or if we do not meet the minimum notification period before the Gomez field ceases production. We made no other performance guarantees to GE and the ultimate fees earned by ATP-IP beyond the minimum fees will be determined by the volumes of hydrocarbons processed through the facility. During the term of the PUA, we are responsible for all of the operating costs and periodic maintenance of theATP Innovator. ATP-IP will pay us a monthly fee for certain administrative services we will provide to the partnership. Additionally, we will share in partnership net income and regular minimum quarterly cash distributions in accordance with the provisions of the ATP-IP partnership agreement.

For financial reporting purposes, because we are the general partner of the partnership we consolidate ATP-IP, along with three wholly owned limited liability companies (the “LLCs”) we created to own our interests in ATP-IP. The contribution of the ATP Innovator was accounted for as a transfer of assets between entities under common control. Accordingly, ATP-IP recorded theATP Innovator at its carryover cost basis and no accounting gain or loss was recognized. We have historically subjected theATP Innovator costs to units-of-production depletion over the proved reserves attributable to our Gomez Hub. ATP-IP owns no reserves and, therefore, now recognizes depreciation expense for theATP Innovator on a straight-line basis over an estimated useful life of 25 years, given the partnership’s ability to enter into subsequent throughput agreements and to relocate theATP Innovator to a new producing location at the end of the existing PUA. We incurred costs associated with the formation of the partnership of approximately $3.4 million which were charged to general and administrative expense. All items of intercompany revenue and expense, investment and capital are eliminated in consolidation. Additionally, because the partnership agreement provides certain redemption rights to the Class A limited partner interests in the event a change of control occurs at ATP, the Class A interests are reflected as redeemable noncontrolling interest within equity on our consolidated balance sheet, and we segregate net income and comprehensive income attributable to such interests (also see Note 14, “Commitments and Contingencies”).

Under U.S. federal income tax laws, ATP-IP is not a taxable entity and all distributable items of income and deductible expenses flow through to the partners in accordance with the agreements. Additionally, the new LLCs we formed are all wholly owned, and as such are disregarded entities for U.S. federal income tax purposes.

Note 7 — Conveyances of Net Profits Interests

During the second quarter of 2009, we granted limited-term 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 three of our vendors in exchange for oil and gas property development services to be provided. The interests earned by the vendors will be paid solely from the net profits, as defined, of the subject properties. At June 30, 2009, we accrued the present value of the NPIs of $43.3 million as a non-current liability on our consolidated balance sheet with an offsetting increase recorded as additions to oil and gas properties. As the NPI is earned in future periods, we will also accrete the liability over the estimated term in which the NPI is expected to be settled. 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.

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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,
	2009			2008
Asset retirement obligation, beginning of period	$	132,108		$	186,771
Liabilities incurred		461			4,258
Liabilities settled		(2,365	)		(10,546	)
Property dispositions		(292	)		(1,127	)
Changes in estimates		2,470			550
Accretion expense		5,945			8,581

Total asset retirement obligation		138,327			188,487
Less current portion		(35,923	)		(19,007	)

Total long-term asset retirement obligation, end of period	$	102,404		$	169,480

Note 9 — Long-Term Debt

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


	June 30, 2009			December 31, 2008
Term Loans – tranche B-1	$	1,039,500		$	1,044,749
Term Loans – Asset Sale Facility		273,300			326,714
Term Loans – revolving credit facility		31,000			31,000
Unamortized discount		(30,606	)		(35,833	)

Total debt		1,313,194			1,366,630
Less current maturities		(10,500	)		(10,500	)

Total long-term debt	$	1,302,694		$	1,356,130

The Term Loans include a tranche B-1 Loan of, initially, $1.05 billion, maturing July 2014, and a tranche B-2 Loan of, initially, $600.0 million (the “Asset Sale Facility”), maturing January 2011. The Term Loans were issued with an original issue discount of 2.5% and bear interest at LIBOR plus 5.25% (with a LIBOR floor of 3.25%). The $1.05 billion tranche requires a $2.63 million principal repayment per calendar quarter until September 2013, and four quarterly repayments of $249.4 million thereafter. The Asset Sale Facility is due in full at maturity and allows for prepayment at any time at par. The Term Loans are secured by substantially all of our oil and gas assets in the Gulf of Mexico and a pledge of 65% of the common stock of our wholly owned subsidiaries, ATP Oil & Gas (UK) Limited and ATP Oil and Gas (Netherlands) B.V. The revolving credit facility has a final maturity of July 2013. During the first six months of 2009, we repaid a total of $53.4 million of the Asset Sale Facility in accordance with our Term Loans related to amounts received from the sale of the redeemable noncontrolling interest discussed above and to the common stock issuance discussed below.

The combined effective annual interest rate under the Term Loans at June 30, 2009 and December 31, 2008 was approximately 9.98% and 9.86%, respectively.

Note 10 — Common Stock

During the second quarter of 2009, we issued 8.75 million shares of common stock and received net proceeds of $68.2 million ($8.25 per share before underwriters discounts and commissions and offering expenses). In accordance with our Term Loans, we used $17.0 million of net proceeds from the issuance to reduce the Asset Sale Facility. The underwriters had an overallotment option to purchase another 1,312,500 shares at $8.25 per share that expired unexercised in July 2009.

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 11 — Stock–Based Compensation

We recognized stock option compensation expense of $0.8 million and $0.7 million during the three months ended June 30, 2009 and 2008, respectively, and $1.6 million and $1.4 million during the six months ended June 30, 2009 and 2008, respectively. We recognized restricted stock compensation expense of $1.3 million and $2.2 million during the three months ended June 30, 2009 and 2008, respectively, and $2.7 million and $4.4 million during the six months ended June 30, 2009 and 2008, respectively.

The fair values of options granted during the six months ended June 30, 2009 were estimated at the date of grant using a Black-Scholes option-pricing model assuming no dividends and with the following weighted average assumptions:


Weighted average volatility		71.3	%
Expected term (in years)		3.8
Risk-free rate		1.7	%
Weighted average fair value of options – grant date	$	3.63

The following table sets forth a summary of option transactions for the six months ended June 30, 2009:


	Number of Options		Weighted Average Grant Price		Aggregate Intrinsic Value (1) ($000)		Weighted Average Remaining Contractual Life
							(in years)
Outstanding at beginning of period	1,405,355		$	26.18
Granted	400			7.68
Forfeited	(4,000	)		32.56
Expired	(3,500	)		6.28

Outstanding at end of period	1,398,255			26.21	$	528.8	3.0

Vested and expected to vest	1,271,352			26.19	$	477.8	2.9

Options exercisable at end of period	407,251			30.45	$	—	1.6

(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, 2009, unrecognized compensation expense related to nonvested stock option grants totaled $3.2 million. Such unrecognized expense will be recognized as vesting occurs over a weighted average period of 3.0 years.

At June 30, 2009, unrecognized compensation expense related to restricted stock totaled $4.7 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 six months ended June 30, 2009:


	Number of Shares		Weighted Average Grant-date Fair Value		Aggregate Intrinsic Value (1) ($000)
Nonvested at beginning of period	345,705		$	43.44
Granted	131,732			6.25
Forfeited	(1,642	)		45.64
Vested	(84,625	)		47.53

Nonvested at end of period	391,170			30.02	$	2,722.5

(1)

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

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 12 — 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 shares of common stock (other than nonvested restricted stock) outstanding during the period. Weighted average shares outstanding for diluted EPS also includes a hypothetical number of shares assuming all in-the-money options and warrants would have been exercised and vesting of restricted stock. Potential common shares are excluded from the computation of weighted average common shares outstanding when their effect is antidilutive. In the table below, stock-based awards for 1,144,000 and 869,834 average shares of common stock for the three months ended June 30, 2009 and 2008, respectively, were excluded from the diluted EPS calculation because their inclusion would have been antidilutive. Stock-based awards for 1,546,000 and 316,323 average shares of common stock for the six months ended June 30, 2009 and 2008, respectively, were excluded from the diluted EPS calculation because their inclusion would have been antidilutive.

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


	Three Months Ended June 30,						Six Months Ended June 30,
	2009			2008			2009			2008
Net income (loss) attributable to common shareholders	$	(4,366	)	$	(11,780	)	$	(2,730	)	$	35,065


Shares outstanding:
Weighted average shares outstanding - basic		36,878			35,440			36,251			35,631
Effect of potentially dilutive securities - stock options and warrants		—			—			—			303
Nonvested restricted stock		—			—			—			138

Weighted average shares outstanding - diluted		36,878			35,440			36,251			36,072


Net income (loss) per share attributable to common shareholders:
Basic	$	(0.12	)	$	(0.33	)	$	(0.08	)	$	0.98

Diluted	$	(0.12	)	$	(0.33	)	$	(0.08	)	$	0.97

Note 13 — Derivative Instruments and Risk Management Activities

We periodically enter into commodity 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 under FAS 133 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 under FAS 133 are recorded instead to accumulated other comprehensive income until the period in which the forecasted hedged transactions occur, at which time the

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

gains and losses are reclassified from accumulated other comprehensive income to the consolidated statement of operations as components of the revenue or expense items to which they relate. Hedge ineffectiveness is recorded directly to the consolidated statement of operations. Settlements of commodity derivative instruments are included in cash flows from operating activities in our consolidated statement of cash flows.

At June 30, 2009, we had derivative contracts for the following natural gas and oil volumes:


					Net Fair Value Asset (Liability) (2)
Period	Type	Volumes	Price		Current			Noncurrent
			$/Unit (1)		($000)			($000)
Oil (Bbl) –Gulf of Mexico
Remainder of 2009	Puts	920,000	$	29.75	$	9		$	—
2010	Puts	365,000		24.70		4			10

Natural Gas (MMBtu)
North Sea
Remainder of 2009	Swaps (2)	759,000		6.51		(104	)		—

2010	Collars	1,825,000		6.28-9.44		(244	)		(275	)
2011	Collars	270,000		6.28-9.44		—			(509	)

Gulf of Mexico
Remainder of 2009	Fixed-price physicals	3,824,000		4.81		1,573			—
2010	Fixed-price physicals	900,000		5.02		(694	)		—

Remainder of 2009	Collars	920,000		4.00-7.00		212			—
2010	Collars	4,575,000		4.68-7.86		3			(560	)
2011	Collars	1,350,000		4.75-7.95		—			(928	)

Total					$	759		$	(2,262	)


Derivative asset					$	1,404		$	—
Derivative liability						(645	)		(2,262	)

Total					$	759		$	(2,262	)

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

(2)	None of the derivatives outstanding as of June 30, 2009 are designated as hedges under SFAS No. 133 for accounting purposes, except for the North Sea natural gas swap contracts.

During the first half of 2009, we received net cash settlements of $36.4 million from our price hedge derivatives, which includes $17.7 million from early termination of certain contracts. The following table shows where gains and losses (net of taxes) on cash flow hedge derivatives have been reported for the six months ended June 30, 2009 (in thousands). Within the 12-month period ended June 30, 2010, the entire June 30, 2009 accumulated other comprehensive income (loss) (“AOCI”) balance is estimated to be reclassified to earnings based on forecasted gas production:


	Three Months Ended June 30, 2009			Six Months Ended June 30, 2009
AOCI for cash flow hedges – beginning of period	$	20		$	(2,877	)
Derivative gains		619			3,369
Gains 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

(Unaudited)

Our derivative income (expense) for the three and six months ended June 30, 2009 is based entirely on nondedesignated derivatives and consists of the following (in thousands):


	Three Months Ended June 30, 2009			Six Months Ended June 30, 2009
Realized gains from:
Settlements of contracts	$	5,087		$	18,714
Early terminations of natural gas contracts		14,923			17,657
Unrealized loss on open contracts		(17,798	)		(17,914	)

	$	2,212		$	18,457

Note 14 — Commitments and Contingencies

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

During the term of our PUA, 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 are also contingently obligated to pay $53,000 per day for a maximum of 180 days in the event a loss event occurs, or if we do not meet the minimum notification period before the Gomez field to which the PUA is related 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 a change of control of ATP, as determined by reference to our Credit Agreement, 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 in control was deemed to be probable. We do not currently believe a change of control is probable.

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, 2009 the aggregate amount of such contingent commitments was $10.9 million.

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. 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 us.

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

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 15 — Segment Information

The Company’s operations are focused in the Gulf of Mexico and in the North Sea. Management reviews and evaluates separately the operations of its Gulf of Mexico segment and its North Sea segment. The operations of both segments include natural gas and liquid hydrocarbon production and sales. Segment activity for the three months and six months ended June 30, 2009 and 2008 is as follows (in thousands):


For the Three Months Ended –	Gulf of Mexico		North Sea			Total
June 30, 2009:
Revenues	$	75,871	$	5,026		$	80,897
Depreciation, depletion and amortization		35,605		7,970			43,575
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

June 30, 2008:
Revenues	$	166,138	$	25,671		$	191,809
Depreciation, depletion and amortization		49,873		30,000			79,873
Income (loss) from operations		86,460		(12,178	)		74,282
Interest income		165		479			644
Interest expense, net		24,236		—			24,236
Derivative expense		16,212		33,978			50,190
Income tax expense (benefit)		9,994		(21,934	)		(11,940	)
Additions to oil and gas properties		193,259		32,265			225,524

For the Six Months Ended –	Gulf of Mexico		North Sea			Total
June 30, 2009:
Revenues	$	154,592	$	8,225		$	162,817
Depreciation, depletion and amortization		69,668		13,305			82,973
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

June 30, 2008:
Revenues	$	345,928	$	72,815		$	418,743
Depreciation, depletion and amortization		106,048		63,224			169,272
Income (loss) from operations		179,733		(6,601	)		173,132
Interest income		760		1,112			1,872
Interest expense, net		52,298		65			52,363
Derivative expense		16,172		33,978			50,150
Income tax expense (benefit)		33,569		(20,363	)		13,206
Additions to oil and gas properties		372,262		43,307			415,569
Total assets		1,939,850		636,714			2,576,564

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 16 — Fair Value Measurements

The fair value of our derivative contracts is based on significant unobservable 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 first six months of 2009 (in thousands):


	Gas Fixed- Price Physical U.S.			Gas Price Collar U.S.			Oil Put U.S.			Financial Gas Swap U.K.			Gas Price Collar U.K.			Total
Balance at beginning of period	$	15,366		$	—		$	—		$	(8,361	)	$	—		$	7,005
Purchase of contracts		—			—			1,740			—			—			1,740
Total gain included in other comprehensive income		—			—			—			6,739			—			6,739
Derivative income (expense)		15,821			(1,043	)		(1,717	)		6,368			(1,028	)		18,401
Settlements and terminations		(30,308	)		(230	)		—			(4,850	)		—			(35,388	)


Balance at end of period	$	879		$	(1,273	)	$	23		$	(104	)	$	(1,028	)	$	(1,503	)


Changes in unrealized loss included in derivative income relating to derivatives still held at June 30, 2009	$	(1,740	)	$	(1,273	)	$	(1,262	)	$	—		$	(1,028	)	$	(5,303	)

Note 17 — Subsequent Events

Our evaluation has identified no matters which require disclosure as a subsequent event through August 10, 2009, the issuance date of these consolidated financial statements.

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

Item 2.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

Executive Overview

General

ATP Oil & Gas Corporation is engaged in the acquisition, development and production of oil and natural gas properties in the Gulf of Mexico and the North Sea. We seek to acquire and develop properties with proved undeveloped (“PUD”) reserves that are economically attractive to us but are not strategic to major or large exploration-oriented independent oil and gas companies. Occasionally we will acquire properties that are already producing or where previous drilling has encountered reservoirs that appear to contain commercially productive quantities of oil and gas even though the reservoirs do not meet the SEC definition of proved reserves. We believe that our strategy provides assets for us to develop and produce without the risk, cost or time of traditional exploration.

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

•

significant undeveloped reserves and reservoirs;

•

close proximity to developed markets for oil and natural gas;

•

existing infrastructure of oil and natural gas pipelines and production/processing platforms; 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 which they believe offer greater reserve potential. Some projects may provide lower economic returns to a company due to its cost structure within that company. Also, due to timing or budget constraints, a company may be unwilling or unable to develop a property before the expiration of the lease. With our cost structure and acquisition strategy, it is not unusual for us to have a total acquisition cost for a property that is less than the total costs of the previous owner. This strategy coupled with our expertise in our areas of focus and our ability to develop projects may make the acquired oil and gas properties more financially attractive to us than to the seller. Given our strategy of acquiring properties that contain proved reserves, or where previous drilling 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 already defined targeted reservoirs, which eliminates 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, allows us to efficiently complete the development project and commence production. To enhance the economics and return on investment of a project, we sometimes develop the project to a value creation point and either sell an interest or bring in partners on a promoted basis during the high capital development phase.

Second Quarter 2009 Highlights

•

Achieved initial production from two wells, one at South Marsh Island 190 in the Gulf of Mexico and one at Wenlock in the North Sea;

•

Completed a $68.2 million common stock issuance, net of fees and expenses;

•

Reduced long-term debt by $24.9 million in the second quarter and $58.7 million in the first six months of 2009.

Additional discussion of our expectations for 2009 can be found in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our 2008 Annual Report on Form 10-K.

Risks and Uncertainties

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 limits 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 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 if we were to experience operational problems, uninsured events, or a continuation of adverse commodity prices resulting in the curtailment of production in any of these wells, our current and future production levels would be adversely affected, which may materially affect our financial condition, results of operations and cash flows.

Results of Operations

Three Months Ended June 30, 2009 Compared to Three Months Ended June 30, 2008

For the three months ended June 30, 2009 and 2008 we reported net loss attributable to common shareholders of $4.4 million and $11.8 million, or net loss of $0.12 and $0.33 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 includes oil and gas production revenues from amortization of deferred revenue related to the second quarter 2008 sale of the limited-term overriding royalty interest. We do not reflect any production associated with those revenues.


	Three Months Ended June 30,					% Change from 2008 to 2009
	2009		2008			% Change from 2008 to 2009
Production:
Natural gas (MMcf)		3,950		9,969		(60	)%
Oil and condensate (MBbl)		898		1,414		(36	)%
Total (MMcfe)		9,339		18,455		(49	)%

Gulf of Mexico (MMcfe)		8,357		13,891		(40	)%

North Sea (MMcfe)		982		4,564		(78	)%

Revenues from production (in thousands):
Natural gas	$	15,934	$	86,281		(82	)%
Effects of cash flow hedges		885		(7,217	)
Amortization of deferred revenue		2,300		1,409

Total	$	19,119	$	80,473		(76	)%


Oil and condensate	$	52,763	$	106,017		(50	)%
Effects of cash flow hedges		—		(128	)
Amortization of deferred revenue		9,015		5,447

Total	$	61,778	$	111,336		(45	)%


Natural gas, oil and condensate	$	68,697	$	192,298		(64	)%
Effects of cash flow hedges		885		(7,345	)
Amortization of deferred revenue		11,315		6,856

Total	$	80,897	$	191,809		(58	)%


Average realized sales price:
Natural gas (per Mcf)	$	4.02	$	8.65		(53	)%
Effects of cash flow hedges (per Mcf)		0.22		(0.72	)

Average realized price (per Mcf)	$	4.24	$	7.93		(46	)%


Oil and condensate (per Bbl)	$	58.76	$	74.98		(22	)%
Effects of cash flow hedges (per Bbl)		—		(0.09	)

Average realized price (per Bbl)	$	58.76	$	74.89		(22	)%


Natural gas, oil and condensate (per Mcfe)	$	7.35	$	10.42		(29	)%
Effects of cash flow hedges (per Mcfe)		0.09		(0.40	)

Average realized price (per Mcfe)	$	7.44	$	10.02		(26	)%

Revenues from production decreased in second quarter 2009 compared to second quarter 2008 due to a 49% decrease in overall production and a 26% decrease in average realized sales price (37% price decrease in Gulf of Mexico and 9% price decrease in North Sea). The lower production in the Gulf of Mexico is primarily the result of the June 2008 sale of a 15% limited-term overriding royalty interest in production and natural declines at the Gomez Hub. The lower production in the North Sea is primarily due to the sale of 80% of our working interest in Tors and Wenlock in the fourth quarter of 2008. The lower average realized sales price is due to decreased commodity market prices partially offset by lower royalties associated with certain cost recoveries of $1.0 million.

Lease Operating

Lease operating expenses include costs incurred to operate and maintain wells and related equipment and facilities. These costs include, among others, workover expenses, operator fees, processing fees, insurance and transportation. Lease operating expense was as follows:


	Three Months Ended June 30,				% Change from 2008 to 2009
	2009		2008		% Change from 2008 to 2009
Lease operating (in thousands)	$	17,358	$	23,770	(27	)%
Per Mcfe		1.86		1.29	44	%
Gulf of Mexico		1.75		1.29	36	%
North Sea		2.78		1.27	119	%

Lease operating expense for second quarter 2009 decreased compared to second quarter 2008 primarily due to the sale of 80% of our working interest in Tors and Wenlock in fourth quarter 2008 and due to reduced fuel and chemicals costs in the Gulf of Mexico partially offset by increases related to a well workover at Wenlock in the North Sea. The per unit cost has increased primarily due to this well workover and due to the effect of fixed costs on lower production volumes.

General and Administrative

General and administrative expenses are overhead-related expenses, including employee compensation, legal and accounting fees, insurance, and investor relations expenses. General and administrative expense for the quarters ended June 30, 2009 and 2008 was as follows:


	Three Months Ended June 30,				% Change from 2008 to 2009
	2009		2008		% Change from 2008 to 2009
General and administrative (in thousands)	$	7,105	$	8,831	(20	)%
Per Mcfe		0.76		0.48	58	%

The general and administrative expense decreased for second quarter 2009 compared to the second quarter 2008 as a result of the reversal during the second quarter 2009 of approximately $1.0 million of accrued compensation associated with a terminated employee bonus plan.

Depreciation, Depletion and Amortization

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


	Three Months Ended June 30,				% Change from 2008 to 2009
	2009		2008		% Change from 2008 to 2009
DD&A (in thousands)	$	43,575	$	79,873	(45	)%
Per Mcfe		4.67		4.33	8	%

DD&A expense for the second quarter 2009 decreased compared to second quarter 2008 primarily due to decreased production and the sale of 80% of our working interest in Tors and Wenlock in the fourth quarter 2008. The per unit increase is primarily a result of higher costs incurred on our new developments relative to some of our older properties. The increased rate was partially offset by expense decreases of approximately $3.7 million related to the change from unit of production depletion to straight-line depreciation for the ATP Innovator upon contribution to ATP-IP.

Impairment of Oil and Gas Properties

During second quarter 2009, we recorded impairment expense of $0.7 million related to a Gulf of Mexico shelf property. The impairment was related to unproved properties in the Gulf of Mexico.

Accretion of Asset Retirement Obligation

Accretion expense in second quarter 2009 decreased to $3.0 million compared to $4.3 million in second quarter 2008 primarily due to the North Sea property sale noted above and changes in estimates of future abandonment obligations.

Interest Expense

Interest expense decreased to $10.2 million for second quarter 2009 compared to $24.2 million for second quarter 2008 primarily due to 2009 capitalized interest of $22.9 million ($21.3 million related to the construction of the Telemark Hub development in the Gulf of Mexico and $1.6 million related to Cheviot in the U.K.) compared to capitalized interest of $7.2 million in second quarter 2008. Capitalized interest is increasing due to higher average construction work in progress balances in 2009.

Derivative Income (Expense)

Derivative income in second quarter 2009 was $2.2 million (gains of $1.0 million and $1.2 million in the Gulf of Mexico and North Sea, respectively). The income in 2009 is primarily related to net gains associated with certain gas price contracts.

Derivatives expense in the second quarter of 2008 was $50.2 million (Gulf of Mexico $16.2 million and North Sea $34.0 million). As a result of the limited-term overriding royalty interest and changes in forecasts of production, we determined that it was no longer probable that forecasted production would be sufficient to satisfy amounts designated under certain of our cash flow commodity-price hedges. Consequently, we dedesignated some of these instruments as hedges and recognized expense of $40.5 million. The balance of the derivatives expense was related primarily to changes in fair value of derivatives no longer designated as cash flow hedges.

Income Taxes

We recorded income tax expense of $1.2 million during second quarter 2009 resulting in an overall effective tax rate of 110%. 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 2008 we recorded tax benefit of $11.9 million resulting in an overall effective tax rate of (50%). These rates deviate from statutory rates due to the impact of permanent and other rate-driving differences relative to pretax income (loss) in the jurisdiction in which it is generated.

Net Income Attributable to the Redeemable Noncontrolling Interest

Net income attributable to the redeemable noncontrolling interest of $4.3 million in the second quarter of 2009 represents the 49% Class A limited partner interest in the earnings of ATP-IP.

Six Months Ended June 30, 2009 Compared to Six Months Ended June 30, 2008

For the six months ended June 30, 2009 and 2008 we reported net income (loss) attributable to common shareholders of ($2.7) million and $35.1 million, or net income (loss) of ($0.08) and $0.97 per diluted share, respectively.

Oil and Gas Production Revenues

Revenues presented in the table and the discussion below represent revenues from sales of oil and natural gas production volumes. Production sold under fixed-price delivery contracts which have been designated for the normal purchase and sale exception under Statement of Financial Accounting Standards (“SFAS”) No. 133 are also included in these amounts for the six months ended June 30, 2008. For that period, deliveries under the fixed-price contracts are approximately 78% of our oil production and 83% of our natural gas production. At December 31, 2008, we began accounting for our open fixed-price physical forward contracts as derivatives because we could no longer assert that our remaining contracts would result in physical delivery. Consequently, changes in fair value during the period are reflected as derivative income instead of oil and gas revenues in our consolidated statement of operations.

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


	Six Months Ended June 30,					% Change from 2008 to 2009
	2009		2008			% Change from 2008 to 2009
Production:
Natural gas (MMcf)		8,424		21,813		(61	)%
Oil and condensate (MBbl)		1,813		3,036		(40	)%
Total (MMcfe)		19,302		40,029		(52	)%

Gulf of Mexico (MMcfe)		17,727		30,014		(41	)%
North Sea (MMcfe)		1,575		10,015		(84	)%

Revenues from production (in thousands):
Natural gas	$	37,463	$	193,621		(81	)%
Effects of cash flow hedges		589		(8,459	)
Amortization of deferred revenue		4,256		1,409

Total	$	42,308	$	186,571		(77	)%


Oil and condensate	$	88,426	$	227,265		(61	)%
Effects of cash flow hedges		—		(1,437	)
Amortization of deferred revenue		18,419		5,447

Total	$	106,845	$	231,275		(54	)%


Natural gas, oil and condensate	$	125,889	$	420,886		(70	)%
Effects of cash flow hedges		589		(9,896	)
Amortization of deferred revenue		22,675		6,856

Total	$	149,153	$	417,846		(64	)%


Average realized sales price:
Natural gas (per Mcf)	$	4.44	$	8.88		(50	)%
Effects of cash flow hedges (per Mcf)		0.07		(0.39	)

Average realized price (per Mcf)	$	4.51	$	8.49		(47	)%


Oil and condensate (per Bbl)	$	48.77	$	74.86		(35	)%
Effects of cash flow hedges (per Bbl)		—		(0.47	)

Average realized price (per Bbl)	$	48.77	$	74.39		(34	)%


Natural gas, oil and condensate (per Mcfe)	$	6.52	$	10.51		(38	)%
Effects of cash flow hedges (per Mcfe)		0.03		(0.25	)

Average realized price (per Mcfe)	$	6.55	$	10.26		(36	)%

Revenues from production decreased in the first six months of 2009 compared to the first six months of 2008 due to a 52% decrease in overall production and a 36% decrease in average realized sales price (43% price decrease in Gulf of Mexico and 28% price decrease in North Sea). The lower production in the Gulf of Mexico is primarily the result of June 2008 sale of a 15% limited-term overriding royalty interest in production, the continuing effects of the 2008 hurricanes and natural declines at the Gomez Hub. The lower production in the North Sea is primarily due to the sale of 80% of our working interest in Tors and Wenlock in the fourth quarter of 2008. The lower average realized sales price is due to decreased commodity market prices partially offset by lower royalties associated with certain cost recoveries of $3.9 million.

Other Revenues

Other revenues for the first six months of 2009 are comprised of amounts realized under our loss of production income insurance policy due to disruptions caused by Hurricane Ike.

Lease Operating


	Six Months Ended June 30,				% Change from 2008 to 2009
	2009		2008		% Change from 2008 to 2009
Lease operating (in thousands)	$	35,572	$	48,388	(26	)%
Per Mcfe		1.95		1.21	61	%
Gulf of Mexico		1.85		1.19	55	%
North Sea		2.99		1.28	134	%

Lease operating expense for first six months of 2009 decreased compared to first six months 2008 primarily due to the sale of 80% of our working interest in Tors and Wenlock in fourth quarter 2008 and due to reduced fuel and chemicals costs in the Gulf of Mexico partially offset by increases related to a well workover at Wenlock in the North Sea. The per unit cost has increased primarily due to this well workover and due to the effect of fixed costs on lower production volumes

General and Administrative

General and administrative expenses are overhead-related expenses, including employee compensation, legal and accounting fees, insurance, and investor relations expenses. General and administrative expense for the six months ended June 30, 2009 and 2008 was as follows:


	Six Months Ended June 30,				% Change from 2008 to 2009
	2009		2008		% Change from 2008 to 2009
General and administrative (in thousands)	$	18,208	$	18,067	1	%
Per Mcfe		0.94		0.45	109	%

The general and administrative expense increase for first six months 2009 compared to first six months 2008 is about $1.2 million which is primarily attributable to costs associated with formation of ATP-IP discussed above, partially offset by the reversal during the second quarter 2009 of approximately $1.0 million of accrued compensation associated with a terminated employee bonus plan.

Depreciation, Depletion and Amortization

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


	Six Months Ended June 30,				% Change from 2008 to 2009
	2009		2008		% Change from 2008 to 2009
DD&A (in thousands)	$	82,973	$	169,272	(51	)%
Per Mcfe		4.30		4.23	2	%

DD&A expense for the first six months of 2009 decreased compared to the first six months of 2008 primarily due to decreased production and the sale of our working interest in Tors and Wenlock in the fourth quarter 2008. The per unit increase is primarily a result of higher costs incurred on our new developments relative to some of our older properties. The increased rate was partially offset by expense decreases related to the change from unit of production depletion to straight-line depreciation for the ATP Innovator upon contribution to ATP-IP.

Impairment of Oil and Gas Properties

During the first six months of 2009, we recorded impairment expense of $8.7 million related to Gulf of Mexico shelf properties. The impairment was primarily due to relinquishment of a lease related to poor operating performance. All of the carrying costs related to this property have been written off to impairment expense.

Accretion of Asset Retirement Obligation

Accretion expense in the first six months of 2009 decreased to $5.9 million compared to $8.6 million in the first six months of 2008 primarily due to the North Sea property sale noted above and changes in estimates of future abandonment obligations.

Interest Income

Interest income varies directly with the amount of temporary cash investments. The decrease in interest income from period to period is the result of a decrease in average cash on hand balances and a decrease in interest rates.

Interest Expense

Interest expense decreased to $22.8 million for the first six months of 2009 compared to $52.4 million for the first six months of 2008 primarily due to 2009 capitalized interest of $43.8 million ($41.0 million related to the construction of the Telemark Hub development in the Gulf of Mexico and $2.8 million related to Cheviot in the U.K.) compared to capitalized interest of $13.1 million in the first six months of 2008. Capitalized interest is increasing due to higher average construction work in progress balances in 2009.

Derivative Income (Expense)

Derivative income in the first six months of 2009 was $18.5 million (gains of $13.2 million and $5.3 million in the Gulf of Mexico and North Sea, respectively). The income in 2009 is primarily related to net gains associated with certain gas price contracts.

Income Taxes

We recorded income tax expense of $0.3 million during the first half of 2009 resulting in an overall effective tax rate of 8%. 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 in 2008 we recorded tax expense of $13.2 million resulting in an overall effective tax rate of 27%. These rates deviate from statutory rates due to the impact of permanent and other rate-driving differences relative to pretax income (loss) in the jurisdiction in which it is generated.

Net Income Attributable to the Redeemable Noncontrolling Interest

Net income attributable to the redeemable noncontrolling interest of $6.3 million represents the 49% Class A limited partner interest in the earnings of ATP-IP for the period from inception of the partnership (March 6, 2009) through June 30, 2009.

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 and the sale or conveyance of interests in selected properties. The disarray in the credit markets in 2008 has continued into 2009. 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, during the first six months of 2009, we raised $148.8 million of capital from the formation of a ATP-IP and $68.4 million from issuance of common stock as discussed above. During this period we also conveyed to certain vendors net profits interests in our Telemark Hub oil and gas properties in exchange for development services and equipment provided. We also negotiated with certain other vendors involved in the development of the Telemark Hub to partially defer payments until after production has begun.

We intend to fund our near-term development projects utilizing cash on hand, planned asset sales and cash flows from operations. We currently estimate accrual basis capital expenditures exclusive of capitalized interest and services contributed by vendors in conjunction with the net profits interests discussed above to be between $350 million and $400 million in 2009. As operator of most of our projects under development, we have the ability to significantly 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.

While we do not expect to rely on the credit markets to meet our goals in 2009, we desire to sell selected assets during 2009, 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. Still, we believe that we will be able to sell selected assets in 2009, allowing us to meet our debt reduction goals and providing us with additional capital for general corporate purposes and additional development, as appropriate. Our revenues, profitability and cash flows are highly dependent upon many factors, particularly our production results and the price of oil and natural gas. To mitigate future price volatility, we may hedge the sales price 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 see a significant change in this focus over the next several years. We believe this flexibility coupled with our hedging program and our ability to sell or convey assets, provides us the financial resources needed to fully fund our future development programs.

Cash Flows


	Six Months Ended June 30,
	2009			2008
Cash provided by (used in) (in thousands):
Operating activities	$	95,065		$	277,407
Investing activities		(361,094	)		(379,266	)
Financing activities		145,731			180,863

As of June 30, 2009, we had a working capital deficit of approximately $11.5 million, a decrease of approximately $47.9 million from December 31, 2008. Our credit agreement covenants specify a minimum liquidity ratio whereby we include the availability under the Revolver, and exclude current maturities of long-term debt, the current portion of assets and liabilities from derivatives and the current portion of asset retirement obligations. We were in compliance with all of our credit agreement covenants at June 30, 2009.

Cash provided by operating activities during the first six months 2009 and 2008 was $95.1 million and $277.4 million, respectively. Cash flow from operations decreased primarily due to lower net income and from changes in working capital in the first six months 2009 compared to the first six months 2008. Net income in the first six months 2009 decreased primarily due to lower production and lower commodity prices discussed above.

Cash used in investing activities was $361.1 million and $379.3 million during the first six months 2009 and 2008, respectively. 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 2009. Cash expended in the Gulf of Mexico and North Sea for additions to oil and gas properties was approximately $357.8 million and $103.8 million, respectively, in the first six months 2008. Also, during the second quarter of 2008, we completed the sale of 5.76 Bcfe of proved reserves in the form of a 15% limited-term overriding royalty interest for $82.0 million.

Cash provided by financing activities was $145.7 million and $180.9 million during the first six months 2009 and 2008, respectively. The amount in the first six months 2009 is from the sale of a redeemable noncontrolling interest in our limited partnership and issuance of common stock partially offset by $58.7 million of debt repayments and $11.8 million of distributions to limited partners in ATP-I.P. In the first half of 2008, payments of long-term debt are comprised of $1,202.2 million of repayment of borrowings under our former credit agreement and of $199.5 million related to our former subordinated notes. Proceeds from long-term debt are comprised of $1,593.4 million (net of issuance costs) of proceeds from the Term Loans.

Long-term Loans

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


	June 30, 2009			December 31, 2008
Term Loans and revolving credit facility - net of unamortized discount of $30,606 and $35,833, respectively	$	1,313,194		$	1,366,630
Less current maturities		(10,500	)		(10,500	)

Total long-term debt	$	1,302,694		$	1,356,130

Our Term Loans contain certain financial covenants, the most restrictive of which include the following (Also see Note 7, “Long-Term Debt.”):


Covenant		Requirement (4)
1. Minimum Current Ratio (1)		Greater than 1.0 to 1.0

2. Ratio of Net Debt to EBITDAX (2)		Less than 3.0 to 1.0

3. Ratio of EBITDAX to Interest Expense		Greater than 2.5 to 1.0

4. Ratio of PV-10 of Total Proved Developed Producing Reserves based on future prices to Net Debt (3)		Greater than 0.5 to 1.0

5. Ratio of PV-10 of Total Proved Reserves plus 50% of Pre-tax Probable Reserves based on future prices to Net Debt		Greater than 2.5 to 1.0

(1)	The minimum current ratio excludes current maturities of long-term debt, the current portion of assets and liabilities from derivatives and the current portion of asset retirement obligations.

(2)	EBITDAX is net income excluding interest, taxes, depletion, impairment, certain exploration costs and other noncash items and is determined based on a trailing twelve month average.

(3)	Net Debt is total debt less cash on hand.

(4)	Covenants 1-3 are tested at the end of each calendar quarter. Covenants 4 and 5 are tested at year end and at June 30.

An event of default would occur under the Term Loans if there are one or more judgments rendered against us of at least $25 million or that provide for injunctive relief reasonably expected to result in a material adverse effect (“MAE”). A MAE includes (a) a material adverse effect on the business, assets, operations, condition (financial or otherwise) or prospects of us and our subsidiaries, taken as a whole, (b) a material impairment of our ability to perform our obligations under the Term Loans, or (c) a material impairment of the rights of or benefits available to the lenders under the Term Loans. If such a judgment resulting in an MAE were to occur, we would be in default under the Term Loans, which could cause all of our existing indebtedness to become immediately due and payable.

Upon closing the transactions to form ATP-IP and to issue common stock discussed above, we repaid an aggregate of $53.4 million of our Asset Sale Facility in accordance with our Term Loan agreement leaving a balance of $273.3 million at June 30, 2009. If we complete other Asset Sales, as defined by the Term Loans, we will continue to apply 75% of the Net Cash Proceeds as defined in our Term Loans of the Asset Sale toward the repayment of the Asset Sale Facility as long as there is a balance outstanding. Any Asset Sale Facility balance still outstanding is due in its entirety in January 2011.

We also have a $50.0 million revolving credit facility which has the same interest obligations as the Term Loans and has a final maturity of July 2013. Borrowings under the Revolver at June 30, 2009 were $31.0 million, and the balance of the borrowing capacity was reserved by $19.0 million of outstanding letters of credit secured by the facility.

As of June 30, 2009, we were in compliance with the covenants of the Term Loans and we believe we will remain in compliance with all financial covenants throughout 2009. Significant adverse changes in our expected production levels, commodity prices and reserves or material delays or cost overruns could have a material adverse affect on our financial condition and results of operations and our ability to maintain future compliance with these covenants. An event of noncompliance with any of the required covenants could result in a mandatory repayment under the Term Loans.

Commitments and Contingencies

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

Although it is difficult to predict the ultimate outcome of these matters, management is not aware of any amounts that need to be recorded and believes that the recorded amounts, if any, are reasonable. See Note 14 to the consolidated financial statements for additional discussion of commitments and contingencies.

Accounting Pronouncements

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

Critical Accounting Policies

Our discussion and analysis of our financial condition and results of operations are based on consolidated financial statements which have been prepared in accordance with generally accepted accounting principles in the United States. The preparation of these financial statements requires us to make estimates and judgments that affect the reported amounts or assets, liabilities, revenues and expenses. We believe that certain accounting policies affect our more significant judgments and estimates used in the preparation of our consolidated financial statements. Our 2008 Annual Report on Form 10-K includes a discussion of our critical accounting policies.

Item 3.

Quantitative and Qualitative Disclosures about Market Risks

Interest Rate Risk

We are exposed to changes in interest rates on our Term Loans as described in Management’s Discussion and Analysis of Financial Condition and Results of Operations: Liquidity and Capital Resources, and on the earnings from cash and cash equivalents. See the presentation of our Term Loans in Note 9 to the consolidated financial statements.

Foreign Currency Risk

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

Commodity Price Risk

Our revenues, profitability and future growth depend substantially on prevailing prices for oil and natural gas. Prices also affect the amount of cash flow available for capital expenditures and our ability to borrow and raise additional capital. Lower prices may also reduce the amount of oil and natural gas that we can economically produce. We currently sell a portion of our oil and natural gas production under market price contracts. We periodically use derivative instruments to hedge our commodity price risk. We hedge a portion of our projected oil and natural gas production through a variety of financial and physical arrangements intended to support oil and natural gas prices at targeted levels and to manage our exposure to price fluctuations. We may use futures contracts, swaps, put options, price collars and fixed-price physical forward contracts to hedge our commodity prices. See Note 13, “Derivative Instruments and Risk Management Activities” to the Consolidated Financial Statements.

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

Item 4.

Controls and Procedures

Evaluation of Disclosure Controls and Procedures

Our chief executive officer and chief financial officer have reviewed and evaluated the effectiveness of our disclosure controls and procedures, as defined in Exchange Act Rules 13a-15(e) and 15d-15(e), as of June 30, 2009 (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 effective as of the Evaluation Date to

ensure that information that is required to be disclosed by ATP in the reports it files or submits under the Exchange Act is (i) recorded, processed, summarized and reported, within the time periods specified in the Securities and Exchange Commission’s rules and forms and (ii) accumulated and communicated to ATP’s management, including our chief executive officer and chief financial officer, as appropriate to allow timely decisions regarding required disclosure.

Changes in Internal Control Over Financial Reporting

During the three months ended June 30, 2009, we have made no change to our internal controls over financial reporting that has materially affected, or is reasonably likely to materially affect, our internal controls over financial reporting.

Forward-Looking Statements and Associated Risks

This Quarterly Report contains projections and other forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934. These projections and statements reflect the Company’s current views with respect to future events and financial performance. No assurances can be given, however, that these events will occur or that these projections will be achieved and actual results could differ materially from those projected as a result of certain factors. A discussion of these factors is included in the Company’s 2008 Annual Report on Form 10-K.

PART II. OTHER INFORMATION

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

Item 4.

Submission of Matters to a Vote of Security Holders

The following items were presented for approval to stockholders of record on April 9, 2009 at the Company’s annual meeting of stockholders which was held on June 5, 2009 in Houston, Texas:


	For	Against	Withheld or Abstained	Broker Non-Votes
(i) Election of Directors:
Burt A. Adams	32,119,166	1,357,642	—	—
Arthur H. Dilly	32,218,596	1,258,212	—	—
Lady Barbara Judge	33,138,917	328,567	—	—

(ii) Ratification of PricewaterhouseCoopers LLP as independent registered public accounting firm of the Company for the fiscal year ending December 31, 2009	32,063,636	1,336,349	76,823	—

(iii) Approval of the 2009 Stock Plan	14,424,898	7,399,376	75,319	11,577,215

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		Amended and Restated Bylaws of ATP, incorporated by reference to Exhibit 3.1 of ATP’s Current Report on Form 8-K filed February 29, 2008.

4.1		Warrant Shares Registration Rights Agreement dated as of March 29, 2004 between ATP and each of the Holders set forth on the execution pages thereof, incorporated by reference to Exhibit 4.5 of ATP’s Form 10-K for the year ended December 31, 2003.

4.2		Warrant Agreement dated as of March 29, 2004 by and among ATP and the Holders from time to time of the warrants issued hereunder, incorporated by reference to Exhibit 4.6 of ATP’s Form 10-K for the year ended December 31, 2003.

4.3		Rights Agreement dated October 11, 2005 between ATP and American Stock Transfer & Trust Company, as Rights Agent, specifying the terms of the Rights, which includes the form of Statement of Designations of Junior Participating Preferred Stock as Exhibit A, the form of Right Certificate as Exhibit B and the form of the Summary of Rights to Purchase Preferred Shares as Exhibit C, incorporated by reference to Exhibit 1 to the Company’s Registration Statement on Form 8-A filed with the Securities and Exchange Commission on October 14, 2005.

†10.1		ATP Oil & Gas Corporation 2000 Stock Plan, incorporated by reference to Exhibit 10.11 of ATP’s Form 10-K for the year ended December 31, 2000.

10.2		Credit Agreement, dated as of June 27, 2008, among ATP, the lenders named therein, and Credit Cuisse, as Administrative Agent and Collateral Agent, incorporated by reference to Exhibit 99.1 to ATP’s Form 8-K dated June 27, 2008.

10.3		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.

†10.4		Employment Agreement between ATP and Pauline H. van der Sman-Archer, dated December 29, 2005, incorporated by reference to Exhibit 10.1 to ATP’s Form 8-K dated December 30, 2005.


†10.5		Employment Agreement between ATP and John E. Tschirhart, dated December 29, 2005, incorporated by reference to Exhibit 10.2 to ATP’s Form 8-K dated December 30, 2005.

†10.6		Employment Agreement between ATP and Leland E. Tate, dated December 29, 2005, incorporated by reference to Exhibit 10.3 to ATP’s Form 8-K dated December 30, 2005.

†10.7		Employment Agreement between ATP and Robert M. Shivers, III, dated December 29, 2005, incorporated by reference to Exhibit 10.4 to ATP’s Form 8-K dated December 30, 2005.

†10.8		Employment Agreement between ATP and Mickey W. Shaw, dated December 29, 2005, incorporated by reference to Exhibit 10.5 to ATP’s Form 8-K dated December 30, 2005.

†10.9		Employment Agreement between ATP and 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.

†10.10		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.

†10.11		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.

†10.12		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.

†10.13		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.

†10.14		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.

†10.15		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.

†10.16		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.

†10.17		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.

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 10, 2009	By:	/s/ Albert L. Reese Jr.
			Albert L. Reese Jr.
			Chief Financial Officer

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

Large accelerated filer

Accelerated filer

Non-accelerated filer

Smaller reporting company