Atp Oil & Gas (ATPGQ) 10-Q 2009 Q3 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-Q

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

For the quarterly period ended September 30, 2009

OR

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

Commission file number: 001-32647

ATP OIL & GAS CORPORATION

(Exact name of registrant as specified in its charter)

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

4600 Post Oak Place, Suite 200

Houston, Texas 77027

(Address of principal executive offices)

(Zip Code)

(713) 622-3311

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  x    No  ¨

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

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

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

Indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes  ¨    No  x

The number of shares outstanding of the issuer’s common stock, par value $0.001, as of November 3, 2009, was 50,584,118.

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

TABLE OF CONTENTS

	Page
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements (Unaudited)
Consolidated Balance Sheets: September 30, 2009 and December 31, 2008	3
Consolidated Statements of Operations: For the three and nine months ended September 30, 2009 and 2008	4
Consolidated Statements of Cash Flows: For the nine months ended September 30, 2009 and 2008	5
Consolidated Statement of Shareholders’ Equity and Noncontrolling Interest: For the nine months ended September 30, 2009	6
Consolidated Statements of Comprehensive Income (Loss): For the three and nine months ended September  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	23
Item 3. Quantitative and Qualitative Disclosures about Market Risks	37
Item 4. Controls and Procedures	37
PART II. OTHER INFORMATION	38

2

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(In Thousands, Except Share and Per Share Amounts)

(Unaudited)

	September 30, 2009			December 31, 2008
Assets
Current assets:
Cash and cash equivalents	$	317,129		$	214,993
Restricted cash		7,534			—
Accounts receivable (net of allowance of $290 and $352, respectively)		50,804			93,915
Deferred tax asset		35,371			39,150
Derivative asset		2,755			15,366
Other current assets		24,571			11,954
Total current assets		438,164			375,378
Oil and gas properties (using the successful efforts method of accounting):
Proved properties		3,349,352			2,802,315
Unproved properties		15,061			14,705
		3,364,413			2,817,020
Less accumulated depletion, depreciation, impairment and amortization		(1,069,008	)		(944,817	)
Oil and gas properties, net		2,295,405			1,872,203
Furniture and fixtures (net of accumulated depreciation)		391			470
Deferred financing costs, net		14,517			13,493
Other assets, net		14,628			14,066
Total assets	$	2,763,105		$	2,275,610
Liabilities and Equity
Current liabilities:
Accounts payable and accruals	$	198,098		$	277,914
Current maturities of term loans		109,949			10,500
Asset retirement obligation		30,156			32,854
Derivative liability		5,648			8,114
Deferred tax liability		27			—
Other current liabilities		21,090			9,537
Total current liabilities		364,968			338,919
Term loans		1,203,265			1,356,130
Other long-term obligations		189,712			2,582
Asset retirement obligation		111,138			99,254
Deferred tax liability		99,219			101,953
Derivative liability		3,730			1,194
Deferred revenue		26,834			59,229
Total liabilities		1,998,866			1,959,261
Commitments and contingencies (Note 14)
Temporary equity – redeemable noncontrolling interest		139,598			—
Shareholders’ equity:
8% convertible perpetual preferred stock: $0.001 par value, 10,000,000 shares authorized; 1,400,000 issued and outstanding at September 30, 2009; none issued at December 31, 2008; at liquidation value		140,000			—
Common stock: $0.001 par value, 100,000,000 shares authorized; 50,159,510 issued and 50,083,670 outstanding at September 30, 2009; 35,979,170 issued and 35,903,330 outstanding at December 31, 2008		50			36
Additional paid-in capital		563,558			400,334
Retained earnings		17,855			29,644
Accumulated other comprehensive loss		(95,911	)		(112,754	)
Treasury stock, at cost		(911	)		(911	)
Total shareholders’ equity		624,641			316,349
Total liabilities and equity	$	2,763,105		$	2,275,610

See accompanying notes to consolidated financial statements.

3

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(In Thousands, Except Per Share Amounts)

(Unaudited)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2009			2008			2009			2008
Revenues:
Oil and gas production	$	75,010		$	118,347		$	224,163		$	536,193
Other		—			—			13,664			897
		75,010			118,347			237,827			537,090
Costs, operating expenses and other:
Lease operating		22,891			24,723			60,463			73,111
Exploration		—			48			267			48
General and administrative		6,945			9,212			25,153			27,279
Depreciation, depletion and amortization		37,460			52,825			120,433			222,097
Impairment of oil and gas properties		—			—			8,748			—
Accretion of asset retirement obligation		2,995			4,211			8,940			12,792
Loss on abandonment		1,936			896			2,949			2,309
Other, net		408			(149	)		696			(259	)
		72,635			91,766			227,649			337,377
Income from operations		2,375			26,581			10,178			199,713
Other income (expense):
Interest income		182			1,079			555			2,951
Interest expense, net		(9,000	)		(26,606	)		(31,797	)		(78,969	)
Derivative income (expense)		(3,458	)		40,963			14,999			(9,187	)
Loss on debt extinguishment		—			—			—			(24,220	)
		(12,276	)		15,436			(16,243	)		(109,425	)
Income (loss) before income taxes		(9,901	)		42,017			(6,065	)		90,288
Income tax (expense) benefit:
Current		(376	)		6,710			(22	)		(3,648	)
Deferred		4,770			(12,244	)		4,116			(15,092	)
		4,394			(5,534	)		4,094			(18,740	)
Net income (loss)		(5,507	)		36,483			(1,971	)		71,548
Less net income attributable to the redeemable noncontrolling interest		(3,552	)		—			(9,818	)		—
Net income (loss) attributable to shareholders		(9,059	)		36,483			(11,789	)		71,548
Less convertible preferred stock dividends		(62	)		—			(62	)		—
Net income (loss) attributable to common shareholders	$	(9,121	)	$	36,483		$	(11,851	)	$	71,548
Net income (loss) per share attributable to common shareholders:
Basic	$	(0.20	)	$	1.03		$	(0.30	)	$	2.02
Diluted	$	(0.20	)	$	1.02		$	(0.30	)	$	1.99
Weighted average number of common shares:
Basic		44,520			35,452			39,038			35,441
Diluted		44,520			35,815			39,038			35,871

See accompanying notes to consolidated financial statements.

4

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In Thousands)

(Unaudited)

	Nine Months Ended September 30,
	2009			2008
				(Restated)
Cash flows from operating activities
Net income (loss)	$	(1,971	)	$	71,548
Adjustments to reconcile net income (loss) to net cash provided by operating activities –
Depreciation, depletion and amortization		120,433			222,097
Impairment of oil and gas properties		8,748			—
Accretion of asset retirement obligation		8,940			12,792
Deferred income taxes		(4,116	)		15,092
Derivative expense		23,762			23,435
Loss on extinguishment of debt		—			15,370
Stock-based compensation		6,100			9,071
Amortization of deferred revenue		(32,395	)		(19,451	)
Noncash interest expense		11,233			12,751
Other noncash items, net		3,045			1,695
Changes in assets and liabilities –
Accounts receivable and other current assets		30,277			85,947
Accounts payable and accruals		(48,302	)		(49,644	)
Other liabilities		(522	)		—
Net cash provided by operating activities		125,232			400,703
Cash flows from investing activities
Additions to oil and gas properties		(464,983	)		(691,531	)
Decrease (increase) in restricted cash		(7,534	)		13,864
Proceeds from disposition of oil and gas properties		—			82,644
Additions to furniture and fixtures		(126	)		(129	)
Net cash used in investing activities		(472,643	)		(595,152	)
Cash flows from financing activities
Proceeds from term loans		—			1,608,750
Payments of term loans		(61,289	)		(1,404,278	)
Deferred financing costs		—			(15,523	)
Issuance of common stock, net of costs		161,592			—
Issuance of preferred stock, net of costs		135,549			—
Net profits interests payments		(1,211	)		(13,602	)
Sale of redeemable noncontrolling interest, net of formation costs		148,751			—
Limited partner distributions		(15,408	)		—
Proceeds from pipeline transaction		74,511			—
Exercise of stock options		3			33
Net cash provided by financing activities		442,498			175,380
Effect of exchange rate changes on cash and cash equivalents		7,049			(2,022	)
Increase (decrease) in cash and cash equivalents		102,136			(21,091	)
Cash and cash equivalents, beginning of period		214,993			199,449
Cash and cash equivalents, end of period	$	317,129		$	178,358
Noncash investing and financing activities
Increase (decrease) in noncash property additions	$	76,242		$	(6,866	)
Accrued distributions to noncontrolling interest		3,563			—

See accompanying notes to consolidated financial statements.

5

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF

SHAREHOLDERS’ EQUITY AND NONCONTROLLING INTEREST

(In Thousands)

(Unaudited)

	Nine Months Ended September 30, 2009
	Shares	Amount
Temporary Equity – Redeemable Noncontrolling Interest
Balance, beginning of period		$	—
Sale of Class A Limited Partner Interest, net of formation costs			148,751
Net income attributable to the redeemable noncontrolling interest			9,818
Limited partner distributions			(18,971	)
Balance, end of period		$	139,598
Shareholders’ Equity:
Preferred Stock
Balance, beginning of period	—	$	—
Issuance of preferred stock	1,400		140,000
Balance, end of period	1,400		140,000
Common Stock
Balance, beginning of period	35,903		36
Issuance of common stock	14,050		14
Issuance of restricted stock, net of forfeitures	130		—
Balance, end of period	50,083		50
Paid-in Capital
Balance, beginning of period			400,334
Issuance of common and preferred stock, net of issuance costs			157,124
Stock-based compensation			6,100
Balance, end of period			563,558
Retained Earnings
Balance, beginning of period			29,644
Net loss			(1,971	)
Less net income attributable to the redeemable noncontrolling interest			(9,818	)
Balance, end of period			17,855
Accumulated Other Comprehensive Loss
Balance, beginning of period			(112,754	)
Other comprehensive income			16,843
Balance, end of period			(95,911	)
Treasury Stock, at Cost
Balance, beginning of period	76		(911	)
Balance, end of period	76		(911	)
Total Shareholders’ Equity		$	624,641

See accompanying notes to consolidated financial statements.

6

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(In Thousands)

(Unaudited)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2009			2008			2009			2008
Net income (loss)	$	(5,507	)	$	36,483		$	(1,971	)	$	71,548
Other comprehensive income (loss):
Reclassification adjustment for settled hedge contracts (net of taxes of $453, ($82), $748 and ($4,987), respectively)		(453	)		151			(748	)		6,002
Changes in fair value of outstanding hedge positions (net of taxes of $(273), ($8,446), $(3,642) and $22,711, respectively)		273			9,855			3,642			(23,139	)
Reclassification adjustment for dedesignated hedge contracts (net of taxes of $0, $0, $0 and ($19,288), respectively)		—			—			—			21,258
Foreign currency translation adjustment		(6,359	)		(47,227	)		13,949			(46,863	)
Other comprehensive income (loss)		(6,539	)		(37,221	)		16,843			(42,742	)
Comprehensive income (loss)		(12,046	)		(738	)		14,872			28,806
Less comprehensive income attributable to the redeemable noncontrolling interest		(3,552	)		—			(9,818	)		—
Comprehensive income (loss) attributable to shareholders		(15,598	)		(738	)		5,054			28,806
Less convertible preferred stock dividends		(62	)		—			(62	)		—
Comprehensive income (loss) attributable to common shareholders	$	(15,660	)	$	(738	)	$	4,992		$	28,806

See accompanying notes to consolidated financial statements.

7

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 September 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. 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):

	Nine Months Ended September 30, 2008
	As Reported			As Restated
Accounts payable and accruals	$	(196,999	)	$	(49,644	)
Net cash provided by operating activities		253,348			400,703
Additions to oil and gas properties		(544,176	)		(691,531	)
Net cash used in investing activities		(447,797	)		(595,152	)

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 term loans 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 September 30, 2009 was approximately $1.23 billion.

8

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

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 continue to evaluate the potential impact of adopting the Final Rule, but have determined that our disclosures under the Final Rule will be limited to proved reserves. We anticipate that the new requirements will not materially affect our financial position or results of operations.

In February 2009, the Financial Accounting Standards Board (“FASB”) issued a standard entitled “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 the standard entitled, “Business Combinations.” This standard has no impact on our financial statements at this time.

In May 2009, the FASB issued a standard entitled “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 a standard entitled, “Accounting for Transfer of Financial Assets, an amendment of FASB Statement No. 140,” which modifies and clarifies the requirements of the previously

9

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

issued standard. 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 a standard entitled, “Amendments to FASB Interpretation No. 46(R),” which modifies the requirements of the previously issued standard. 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.

In June 2009, the FASB issued a standard entitled, “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 was effective for financial statements issued after September 15, 2009 and it has not had a material effect on our financial statements.

The FASB has provided additional guidance on measuring the fair value of liabilities. The new guidance addresses the impact of transfer restrictions on the fair value of a liability and the ability to use the fair value of a liability that is traded as an asset as an input to the valuation of the underlying liability. The standard also clarifies the application of certain valuation techniques. We do not anticipate that adoption of this standard will have a material impact 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 we expect such price volatility to continue. Prices for oil and gas declined materially in early 2009 compared to 2008. Any extended decline in oil or gas prices could have a material adverse effect on our financial position, results of operations, cash flows, the quantities of oil and gas reserves that we can economically produce, and may restrict our ability to obtain additional financing or to meet the contractual obligations required under our June 2008 senior secured term loan facility, as amended (“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. As of September 30, 2009, 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 2008 and 2009, a significant amount of time and money has been spent by us on our Telemark Hub development. Our 2010 results of operations, financial position and cash flows will be significantly impacted by the timing and success at this development. 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 prolonged 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.

10

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

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. Even though we have recently obtained an amendment to our credit facility, as discussed in Note 7, to provide us more latitude in our covenants for the period from October 1, 2009 until December 31, 2010, our ability to meet these covenants is primarily dependent on the adequacy of cash flows from operations, oil and natural gas reserve levels and cash inflows from other financing transactions. Our inability to satisfy the covenants or other contractual requirements contained in our Term Loans would constitute an event of default. An uncured 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. 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 or consummate asset monetizations or other financings may be restricted at a time when we need to raise additional capital. Further, the current economic conditions could also impact our lenders, customers and hedging counterparties and cause them to fail to meet their obligations to us with little or no warning.

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 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. We intend to fund our near-term development projects utilizing cash on hand, cash flows from operations and other asset financings. To the extent we are also successful in monetizing 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 plans and their timing. Within certain constraints, we can conserve capital by delaying or eliminating capital expenditures. While postponing or eliminating capital projects will delay or reduce future cash flows from scheduled new production, this control and flexibility 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 applying the estimated worldwide annual effective income tax rate on interim period operations and included the effect of items discrete to the interim period. The effective income tax rate during interim periods may vary from the statutory rate due to the impact of permanent items relative to our net income, as well as the impact from the net income attributable to the redeemable noncontrolling interest. 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 benefit of $4.4 million and income tax expense of $5.5 million for the three months ended September 30, 2009 and 2008, respectively. We recognized income tax benefit of $4.1 million and income tax expense of $18.7 million for the nine months ended September 30, 2009 and 2008, respectively. The worldwide effective tax expense (benefit) rates for the three months ended September 30, 2009 and 2008 were (44%) and 13%, respectively. The worldwide effective tax rates for the first nine months of 2009 and 2008 were (68%) and 21%, respectively.

11

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

Note 5 — Oil and Gas Properties

Acquisitions

During the first nine months 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 (collectively “Clipper”). Also, in exchange for assumption of property abandonment obligation and their payment to us of $4.8 million, we acquired a partner’s working interests in certain properties in the Gulf of Mexico. In the U.K. North Sea, we were awarded a 50% equity interest in the U.K. North Sea Block 9/21, a property known as “Skipper” for no upfront investment.

Impairment of Oil and Gas Properties

During the first nine 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 that was performing poorly. 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.

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 us 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 under certain circumstances, including if we fail to provide 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 pays us a monthly fee for certain administrative services we 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. Partnership cash in excess of monthly distributions and operating needs is transferred to an escrow account which is classified as restricted cash on the consolidated balance sheet.

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 theATP 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 a redeemable noncontrolling interest within temporary 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”).

12

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

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 — Term Loans

Term Loans consisted of the following (in thousands):

	September 30, 2009			December 31, 2008
Term Loans – tranche B-1	$	1,036,875		$	1,044,749
Term Loans – Asset Sale Facility		273,300			326,714
Term Loans – revolving credit facility		31,000			31,000
Unamortized discount		(27,961	)		(35,833	)
Total debt		1,313,214			1,366,630
Less current maturities		(109,949	)		(10,500	)
Total Term Loans	$	1,203,265		$	1,356,130

The Term Loans include a tranche of initially, $1.05 billion (“Tranche B-1”), a tranche of, initially, $600.0 million (the “Asset Sale Facility”) and a Revolving Credit Facility for up to $50.0 million. The Term Loans were issued with an original issue discount of 2.5% and, except for the Asset Sale Facility, bear interest at LIBOR plus 5.25% (with a LIBOR floor of 3.25%). The Asset Sale Facility bears interest at LIBOR plus 5.7% (with a LIBOR floor of 3.25%). The rate increased 0.5% on July 1, 2009 to a minimum of 9.0%. Tranche B-1 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 in January 2011 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 combined effective annual interest rate under the Term Loans at September 30, 2009 and December 31, 2008 was approximately 9.96% and 9.86%, respectively.

During the first nine months of 2009, we repaid a total of $53.4 million of the Asset Sale Facility in accordance with our Term Loans with amounts received from the sale of the redeemable noncontrolling interest discussed above and the second quarter common stock issuance discussed below. During September 2009, we consummated the monetization of our Gomez Hub oil and natural gas pipelines discussed below and issued common stock and convertible preferred stock discussed below. Subsequent to September 30, 2009, we used a portion of the net proceeds from these transactions to repay an additional $99.4 million of the Asset Sale Facility and this is reflected in current maturities of Term Loans on the Balance Sheet.

On November 2, 2009, we entered into an amendment (the “Amendment”) to the Term Loans to provide additional flexibility during the period from October 1, 2009 through December 31, 2010 (the “Amendment Period”). Among other provisions, the Amendment loosens the Net Debt to EBITDAX ratio from 3.0 to 4.0, the EBITDAX to Interest ratio from 2.5 times to 2.0 times and the current ratio from 1.0 to 0.8 for the duration of the Amendment Period. The interest rate on the Tranche B-1 balance will increase to a minimum 11.25% during the Amendment Period, at the end of which it will decrease to a minimum 9.5% for the remainder of the term. Beginning this past July 1, 2009, the minimum rate on the Asset Sale Facility increased by 0.5% and such increases will continue each January 1 and July 1 until it is repaid in full. This Amendment will further increase the rate on the Asset Sale Facility balance outstanding as of October 1, 2009 by 2.75% to a minimum 11.75%. Effective January 1, 2011, the minimum rate on any balance that remains outstanding at that date will decrease by 1.25% to 11.5%.

We paid an initial fee of 0.5% to each of the lender group and the administrative agent of the outstanding balance of the Term Loans at closing plus related expenses for a total of $12.6 million for the Amendment. Additionally, a fee of up to 1.0% may be due on the aggregate unpaid balance outstanding at June 30, 2010; specifically, 0.5% of the aggregate unpaid balance outstanding will be due if any portion of the Asset Sale Facility remains unpaid at that date and an additional 0.5% will be due if the Tranche B-1 balance outstanding exceeds $800 million.

13

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

Note 8 — Other Long-term Obligations

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

	September 30, 2009			December 31, 2008
Net profits interests	$	110,090		$	9,537
Gomez pipeline obligation		74,510			—
Vendor deferrals – Gulf of Mexico		6,820			—
Vendor deferrals - North Sea		16,800			—
Other		2,582			2,582
Total		210,802			12,119
Less current portion (included in other current liabilities)		(21,090	)		(9,537	)
Other long-term obligations	$	189,712		$	2,582

Net Profits Interests

During the nine months ended September 30, 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 certain of our vendors in exchange for oil and gas property development services. The interests earned by the vendors will be paid solely from the net profits, as defined, of the subject properties. At September 30, 2009, we accrued the present value of the NPIs as a 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 using the effective interest method with related interest reflected in interest expense net of amounts capitalized on the Consolidated Statement of Operations. The term of the NPIs will be dependent on the value of the services contributed by these vendors coupled with the estimated timing of production and future economic conditions, including commodity prices and operating costs. A portion of the NPI balance relates to financing of property acquisitions prior to 2009.

Gomez Pipeline Transaction

In the third quarter of 2009, we executed an asset purchase and sale agreement for net proceeds of $74.5 million with a third party for both the oil and natural gas pipelines that service the Gomez Hub at Mississippi Canyon Block 711. In conjunction with the sale, we entered into agreements with the third party to transport oil and natural gas production for the remaining production life of the fields serviced by theATPInnovator for a per-unit fee that is subject to a minimum monthly payment through December 31, 2016. Such minimum fees, if applicable, can be recovered by the company in future periods within the same calendar year whenever fees owed during a month exceed the minimum due. We remain the operator of the pipeline and are responsible for all of the related operating costs. As a result of the retained asset retirement obligation and the purchaser's option to convey the pipeline back to us at the end of the life of the fields in the Gomez Hub, the transaction has been accounted for as a financing obligation equal to the net proceeds received. This obligation will be amortized based on the estimated proved reserve life of the Gomez properties using the effective interest method with related interest reflected in interest expense net of amounts capitalized on the Consolidated Statement of Operations. All payments made in excess of the minimum fee in future periods will be reflected as interest expense of the financing obligation. Subsequent to September 30, 2009, we repaid $42.2 million of Asset Sale Facility with the net proceeds in accordance with our Term Loans.

14

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

Vendor Deferrals

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

In the U.K. North Sea, development of our interest in the Cheviot field continues and we have arranged with the fabricator of the floating production and drilling facility to defer $99 million of payments until construction is complete, which is expected to be in the first quarter of 2011. Consequently, we have terminated the related letter of credit and unencumbered, through the date of this report, the $19.0 million balance of our revolving credit facility which secured it. As work is completed, we record obligations and related interest expense net of amounts capitalized on the Consolidated Statement of Operations.

Note 9 — Asset Retirement Obligation

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

	Nine Months Ended September 30,
	2009			2008
Asset retirement obligation, beginning of period	$	132,108		$	186,771
Liabilities incurred		7,424			6,291
Liabilities settled		(9,501	)		(14,785	)
Property dispositions		(292	)		(1,104	)
Changes in estimates		2,615			(3,112	)
Accretion expense		8,940			12,792
Total asset retirement obligation		141,294			186,853
Less current portion		(30,156	)		(19,075	)
Total long-term asset retirement obligation, end of period	$	111,138		$	167,778

During the three months and nine months ended September 30, 2009, we recognized loss on abandonment of $1.9 million and $2.9 million, respectively. During the three months and nine months ended September 30, 2008, we recognized loss on abandonment of $0.9 million and $2.3 million, respectively. These amounts are primarily the result of actual abandonment operations requiring more work than originally estimated.

Note 10 –– Shareholders’ Equity

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). During the third quarter of 2009, we issued 5.3 million shares of common stock and received net proceeds of $93.4 million ($18.50 per share before underwriters’ discounts and commissions and offering expenses). At September 30, 2009, the underwriters had an overallotment option to purchase another 795,000 shares which they subsequently exercised to the extent of 515,000 shares at the same price per share as the original issuance (net proceeds of $9.1 million). The balance of the overallotment option expired unexercised. During 2009, we have repaid an aggregate $42.6 million of Asset Sale Facility using net proceeds from the issuances of common stock; of that amount, $17.0 million was repaid prior to September 30, 2009.

Preferred Stock

During the third quarter of 2009, we issued 1.4 million shares of convertible preferred stock and received net proceeds of $135.5 million ($100 per share before underwriters’ discounts and commissions and offering expenses). Each share of convertible preferred stock is perpetual, has no voting rights, has a liquidation preference of $100, pays cumulative dividends at a rate of 8% per annum and is convertible at any time, at the option of the holder, into 4.5045 shares of common stock. After September 30, 2014, we have the option to force conversion to common stock provided that the prevailing common stock market price exceeds the

15

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

conversion price by 150% on average for a stipulated period of time. In the event of certain fundamental changes of the Company, each share of convertible preferred stock is subject to adjustment to prevent antidilution and would receive a conversion benefit as defined in the related statement of resolutions that established the convertible preferred stock. At September 30, 2009, the underwriters had an overallotment option to purchase another 200,000 shares at the same price per share as the original issuance. This option subsequently expired unexercised. Subsequent to September 30, 2009, we used $33.9 million of net proceeds from the issuance to reduce the Asset Sale Facility.

Note 11 — Stock–Based Compensation

We recognized compensation expense related to common stock options of $0.6 million and $0.9 million during the three months ended September 30, 2009 and 2008, respectively, and $2.2 million and $2.2 million during the nine months ended September 30, 2009 and 2008, respectively. We recognized compensation expense related to restricted stock of $1.2 million and $2.4 million during the three months ended September 30, 2009 and 2008, respectively, and $3.9 million and $6.8 million during the nine months ended September 30, 2009 and 2008, respectively.

The weighted average grant-date fair value of options granted during the three months ended September 30, 2009 and 2008 was $9.84 and $9.72, respectively. The weighted average grant-date fair value of options granted during the nine months ended September 30, 2009 and 2008 was $6.79 and $9.96, respectively. Grant-date fair values were estimated at the date of grant using a Black-Scholes option-pricing model assuming no dividends and with the following weighted average assumptions:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2009		2008		2009		2008
Weighted average volatility	75.6	%	41.3	%	73.5	%	41.2	%
Expected term (in years)	3.8		3.8		3.8		3.8
Risk-free rate	1.9	%	3.2	%	1.8	%	3.1	%

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

	Number of Options		Weighted Average Exercise Price		Aggregate Intrinsic Value (1) ($000)		Weighted Average Remaining Contractual Life
							(in years)
Outstanding at beginning of period	1,405,355		$	26.18
Granted	800			12.53
Forfeited	(4,000	)		32.56
Expired	(3,500	)		6.28
Exercised	(250	)		12.17	$	1.9
Outstanding at end of period	1,398,405			26.21	$	4,139.5	2.7
Vested and expected to vest	1,271,483			26.19	$	3,744.0	2.7
Options exercisable at end of period	586,751			28.32	$	166.3	1.5

(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.

The aggregate fair value of options that vested during the nine months ended September 30, 2009 was $2.0 million. At September 30, 2009, unrecognized compensation expense related to nonvested stock option grants totaled $2.6 million. Such unrecognized expense will be recognized as vesting occurs over a weighted average period of 2.7 years.

16

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

The aggregate fair value of restricted stock that vested during the nine months ended September 30, 2009 was $4.6 million. At September 30, 2009, unrecognized compensation expense related to restricted stock totaled $3.5 million. Such unrecognized expense will be recognized as vesting occurs over a weighted average period of 1.6 years. The following table sets forth the changes in nonvested restricted stock for the nine months ended September 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	(104,500	)		43.83
Nonvested at end of period	371,295			30.12	$	6,643

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

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 additional shares (“Common Stock Equivalents”) calculated assuming the exercise or conversion of all in-the-money options, warrants and convertible preferred stock and full vesting of restricted stock awards. Common Stock Equivalents are excluded from the computation of weighted average common shares outstanding when the per share effect is antidilutive. The impact of assumed conversion of preferred stock on net income is excluded from the computation of EPS when its impact is antidilutive. For the three months ended September 30, 2009 and 2008, respectively, 1.5 million and 0.7 million Common Stock Equivalents were excluded from the diluted EPS calculation in the table below because their inclusion would have been antidilutive. For the nine months ended September 30, 2009 and 2008, respectively, 1.3 million and 0.5 million Common Stock Equivalents were excluded from the diluted EPS calculation in the table below because their inclusion would have been antidilutive. For the three and nine months ended September 30, 2009, preferred stock dividends of $0.1 million were excluded from the computation because their inclusion would have been antidilutive.

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

	Three Months Ended September 30,					Nine Months Ended September 30,
	2009			2008		2009			2008
Net income (loss) attributable to common shareholders	$	(9,121	)	$	36,483	$	(11,851	)	$	71,548
Add impact of assumed preferred stock conversions (if-converted method)		—			—		—			—
Net income (loss) attributable to common shareholders and impact of assumed conversions	$	(9,121	)	$	36,483	$	(11,851	)	$	71,548
Shares outstanding:
Weighted average shares outstanding - basic		44,520			35,452		39,038			35,441
Effect of potentially dilutive securities:
Stock options and warrants		—			251		—			289
Nonvested restricted stock		—			112		—			141
Preferred stock		—			—		—			—
Weighted average shares outstanding - diluted		44,520			35,815		39,038			35,871
Net income (loss) per share attributable to common shareholders:
Basic	$	(0.20	)	$	1.03	$	(0.30	)	$	2.02
Diluted	$	(0.20	)	$	1.02	$	(0.30	)	$	1.99

17

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

Note 13 — Derivative Instruments and Risk Management Activities

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

Gains and losses for derivatives which have not been designated as hedges are recorded as components of derivative income (expense) in our consolidated statement of operations. Gains and losses for derivatives which have been designated as hedges are recorded instead to accumulated other comprehensive income (“AOCI”) until the period in which the forecasted hedged transactions occur, at which time the 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 September 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		460,000	$	29.75	$	—		$	—
2010	Puts		365,000		24.70		26
Remainder of 2009	Swaps	(3)	460,000		67.60		(1,385	)		—
2010	Swaps	(3)	1,273,000		68.29		(2,802	)		(497	)
2011	Swaps	(3)	181,000		72.00		—			(192	)
Total						$	(4,161	)	$	(689	)
Natural Gas (MMBtu)
North Sea
Remainder of 2009	Swaps	(2)	759,000		6.27	$	1,012		$	—
2010	Collars		1,825,000		6.05-9.08		936			(134	)
2011	Collars		270,000		6.05-9.08		—			(292	)
2010	Fixed-price physicals		1,095,000		7.01		792			(183	)
Gulf of Mexico
Remainder of 2009	Fixed-price physicals		1,912,000		4.93		343			—
2010	Fixed-price physicals		4,525,000		5.58		(1,591	)		(821	)
Remainder of 2009	Collars		460,000		4.00-7.00		41			—
2010	Collars		4,575,000		4.68-7.86		(265	)		(610	)
2011	Collars		1,350,000		4.75-7.95		—			(1,001	)
Total						$	1,268		$	(3,041	)
Derivative asset						$	2,755		$	—
Derivative liability							(5,648	)		(3,730	)
Total						$	(2,893	)	$	(3,730	)

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

(2) None of the derivatives outstanding as of September 30, 2009 are designated as hedges for accounting purposes, except for the North Sea natural gas swap contracts.

(3) These swaps have been matched with call options to allow us to reparticipate in per barrel price increases above $95.00, $99.34 and $115.00 in remainder of 2009, 2010 and 2011, respectively.

18

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

During the first nine months of 2009, we received net cash settlements of $36.7 million from our price hedge derivatives, which include $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 nine months ended September 30, 2009 (in thousands). Within the 12-month period ending September 30, 2010, the entire AOCI balance as of September 30, 2009 is estimated to be reclassified to earnings based on forecasted gas production:

	Three Months Ended September 30, 2009			Nine Months Ended September 30, 2009
AOCI for cash flow hedges - beginning of period	$	197		$	(2,877	)
Derivative gains		273			3,642
Gains reclassified from AOCI to oil and gas revenues		(453	)		(748	)
AOCI for cash flow hedges – end of period	$	17		$	17

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

	Three Months Ended September 30, 2009			Nine Months Ended September 30, 2009
Realized gains (losses) from:
Settlements of contracts	$	1,476		$	20,190
Early terminations of natural gas contracts		—			17,657
Unrealized loss on open contracts		(4,934	)		(22,848	)
	$	(3,458	)	$	14,999

19

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

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 (see Note 6, “Formation of Limited Partnership”), we are obligated to pay to ATP-IP, our consolidated partnership, a per unit fee for all hydrocarbons processed by theATP Innovator, subject to a minimum throughput fee of $53,000 per day. We may also be subject to a minimum fee of $53,000 per day for up to 180 days under certain circumstances, including if we fail to provide the minimum notification period before the Gomez field 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 defined in 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 third quarter of 2009, we executed an asset purchase and sale agreement for net proceeds of $74.5 million with a third party for both the oil and natural gas pipelines that service the Gomez Hub at Mississippi Canyon Block 711. In conjunction with the sale, we entered into agreements with the third party to transport oil and gas production for the remaining production life of the fields serviced by theATP Innovator for a per-unit fee that is subject to a minimum monthly payment through December 31, 2016. Such minimum fees, if applicable, can be recovered by the company in future periods within the same calendar year whenever fees owed during a month exceed the minimum due.

In the normal course of business we occasionally purchase oil and gas properties for little or no up-front costs and instead commit to pay consideration contingent upon the successful development and operation of the properties. The contingent consideration generally includes amounts to be paid upon achieving specified operational milestones, such as first commercial production and again upon achieving designated cumulative sales volumes. At September 30, 2009 the aggregate amount of such contingent commitments related to unmet operational milestones was $10.5 million. This type of financial arrangement as well as the others discussed above provide us currently with resources in exchange for reduced cash flows from future production.

As discussed more fully in Note 8 above, during the nine months ended September 30, 2009, we granted limited-term overriding royalty interests in the form of NPIs in certain of our oil and gas properties in and around the Telemark Hub and Clipper to certain of our vendors in exchange for oil and gas property development services. The interests earned by the vendors will be paid solely from the net profits, as defined, of the subject properties. This type of financial arrangement preserves our current cash in exchange for reduced future cash flows from production.

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 our operations.

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

Note 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

20

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

operations of both segments include natural gas and liquid hydrocarbon production and sales. Segment activity for the three months and nine months ended September 30, 2009 and 2008 is as follows (in thousands):

For the Three Months Ended –	Gulf of Mexico			North Sea			Total
September 30, 2009:
Revenues	$	70,668		$	4,342		$	75,010
Depreciation, depletion and amortization		32,202			5,258			37,460
Income (loss) from operations		6,057			(3,682	)		2,375
Interest income		16			166			182
Interest expense, net		8,996			4			9,000
Derivative income (expense)		(5,569	)		2,111			(3,458	)
Income tax (expense) benefit		4,537			(143	)		4,394
Additions to oil and gas properties		185,472			15,452			200,924
September 30, 2008:
Revenues	$	99,996		$	18,351		$	118,347
Depreciation, depletion and amortization		30,518			22,307			52,825
Income (loss) from operations		38,072			(11,491	)		26,581
Interest income		578			501			1,079
Interest expense, net		26,606			—			26,606
Derivative income		27,309			13,654			40,963
Income tax (expense) benefit		(16,729	)		11,195			(5,534	)
Additions to oil and gas properties		221,809			(25,512	)		196,297
For the Nine months Ended –	Gulf of Mexico			North Sea			Total
September 30, 2009:
Revenues	$	225,260		$	12,567		$	237,827
Depreciation, depletion and amortization		101,870			18,563			120,433
Income (loss) from operations		25,507			(15,329	)		10,178
Interest income		389			166			555
Interest expense, net		31,793			4			31,797
Derivative income		7,629			7,370			14,999
Income tax (expense) benefit		4,237			(143	)		4,094
Additions to oil and gas properties		467,999			91,552			559,551
Total assets		2,497,987			265,118			2,763,105
September 30, 2008:
Revenues	$	445,924		$	91,166		$	537,090
Depreciation, depletion and amortization		136,567			85,530			222,097
Income (loss) from operations		217,805			(18,092	)		199,713
Interest income		1,337			1,614			2,951
Interest expense, net		78,904			65			78,969
Derivative income (expense)		11,137			(20,324	)		(9,187	)
Income tax (expense) benefit		(50,298	)		31,558			(18,740	)
Additions to oil and gas properties		594,071			17,795			611,866
Total assets		1,963,935			607,856			2,571,791

21

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(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 nine months of 2009 (in thousands):

	Gas Fixed- Price Physical			Gas Price Collar			Oil Swap(1)			Oil Puts			Subtotal U.S.
U.S.
Balance at beginning of period	$	15,366		$	—		$	—		$	—		$	15,366
Purchase of contracts		—			—			—			1,740			1,740
Derivative income (expense)		15,383			(1,313	)		(5,705	)		(1,714	)		6,651
Settlements and terminations		(32,818	)		(522	)		829			—			(32,511	)
Balance at end of period	$	(2,069	)	$	(1,835	)	$	(4,876	)	$	26		$	(8,754	)
Changes in unrealized loss included in derivative income (expense) relating to derivatives still held at September 30, 2009	$	(3,336	)	$	(1,835	)	$	(4,876	)	$	(799	)	$	(10,846	)
	Gas Fixed- Price Physical			Gas Price Collar			Financial Gas Swap			Subtotal U.K.			Grand Total
U.K.
Balance at beginning of period	$	(947	)	$	—		$	(8,361	)	$	(9,308	)	$	6,058
Purchase of contracts		—			—			—			—			1,740
Total gain included in other comprehensive income		—			—			7,282			7,282			7,282
Derivative income		665			510			7,173			8,348			14,999
Settlements and terminations		891			—			(5,082	)		(4,191	)		(36,702	)
Balance at end of period	$	609		$	510		$	1,012		$	2,131		$	(6,623	)
Changes in unrealized income (loss) included in derivative income (expense) relating to derivatives still held at September 30, 2009	$	609		$	510		$	978		$	2,097		$	(8,749	)

(1) These swaps have been matched with call options to allow us to reparticipate in price increases above certain levels.

Note 17 — Subsequent Events

Our evaluation has identified the matters noted below which require disclosure as events subsequent to September 30, 2009 through November 9, 2009, the issuance date of these consolidated financial statements:

• we amended our Term Loans (see Note 7, “Term Loans”);

• we repaid a portion of the Asset Sale Facility (see Note 8, “Other Long-term Obligations” and Note 10, “Shareholders’ Equity”).

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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.

Third quarter 2009 Highlights

• We discovered additional pay sands at the Telemark Hub;

• On November 1, 2009, our new deepwater drilling and production facility, theATP Titan, sailed out of dry dock and should arrive on location at the Telemark Hub shortly.

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• We executed an agreement with our contractor to defer $99 million of Octabuoy hull construction costs without delaying the construction schedule;

• We realized $74.5 million, net of fees and expenses, from monetizing both the oil and natural gas pipelines that service our Gomez Hub;

• We raised, net of fees and expenses, $93.4 million by selling common stock and $135.5 million by selling perpetual convertible preferred stock;

• We amended our Term Loans to improve financial flexibility;

• We have reduced outstanding Term Loans by $112.6 million since June 30, 2009.

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. In accordance with our Term Loans, we used $36.4 million of net proceeds from this transaction to reduce the Asset Sale Facility. 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. One director and three officers of ATP also serve as three managers (the equivalent of directors) and the President of the General Partner, ATP IP-GP, LLC. Under certain circumstances there may be conflicts of interest between the general partner and ATP.

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 us 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 under certain circumstances, including if we fail to provide 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. Partnership cash in excess of monthly distributions and operating needs is transferred to an escrow account which is classified as restricted cash on the consolidated balance sheet.

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 a 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” to Financial Statements in Item 1).

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During June 2009, we issued 8.75 million shares of common stock ($8.25 per share before underwriters’ discounts and commissions and offering expenses). During September and October of 2009, we issued 5.8 million shares of common stock ($18.50 per share before underwriters’ discounts and commissions and offering expenses). During September 2009, we issued 1.4 million shares of convertible preferred stock with a per share liquidation preference of $100 and a cumulative dividend rate of 8%. We received total net proceeds of $305.8 million for these transactions. In accordance with our Term Loans, $76.5 million of the Asset Sale Facility was repaid. Of that amount, $17.0 million was repaid prior to September 30, 2009.

In the third quarter of 2009, we executed an asset purchase and sale agreement for net proceeds of $74.5 million with a third party for both the oil and natural gas pipelines that service the Gomez Hub at Mississippi Canyon Block 711. In conjunction with the sale, we entered into agreements with the third party to transport oil and gas production for the remaining production life of the fields serviced by theATP Innovator for a per unit fee that is subject to a minimum monthly payment through December 31, 2016. Such minimum fees, if applicable, can be recovered by us in future periods within the same calendar year whenever fees owed during a month exceed the minimum due. As a result of the retained asset retirement obligation and the purchaser’s option to convey the pipeline back to ATP at the end of the life of the fields in the Gomez Hub, the transaction has been accounted for as a financing obligation equal to the net proceeds received. We remain the operator of the pipeline and are responsible for all of the related operating costs. In accordance with our Term Loans, we used $42.2 million of net proceeds to reduce the Asset Sale Facility.

During this period we also financed significant portions of our development program with transactions entered into with our vendors and their affiliates. We have conveyed to certain vendors net profits interests in our Telemark Hub and Clipper oil and gas properties in exchange for development services. We have also negotiated with certain other vendors involved in the development of the Telemark Hub and Clipper to partially defer payments until after production has begun. Development of our interest in the Cheviot field in the U.K. North Sea continues and we have arranged with the fabricator of the floating production and drilling facility to defer $99 million of payments until construction is complete. Consequently, we have terminated the related letter of credit and unencumbered the $19.0 million balance of our revolving credit facility which secured it.

On November 2, 2009, we entered into an amendment (the “Amendment”) to the Term Loans to provide additional flexibility during the period from October 1, 2009 through December 31, 2010 (the “Amendment Period”). Among other provisions, the Amendment loosens the Net Debt to EBITDAX ratio from 3.0 to 4.0, the EBITDAX to Interest ratio from 2.5 times to 2.0 times and the current ratio from 1.0 to 0.8 for the duration of the Amendment Period. The interest rate on the Tranche B-1 balance will increase to a minimum 11.25% during the Amendment Period, at the end of which it will decrease to a minimum 9.5% for the remainder of the term. Beginning this past July 1, 2009, the minimum rate on the Asset Sale Facility increased by 0.5% and such increases will continue each January 1 and July 1 until it is repaid in full. This Amendment will further increase the rate on the Asset Sale Facility balance outstanding as of October 1, 2009 by 2.75% to a minimum 11.75%. Effective January 1, 2011, the minimum rate on any balance that remains outstanding at that date will decrease by 1.25% to 11.5%.

We paid an initial fee of 0.5% to each of the lender group and the administrative agent of the outstanding balance of the Term Loans at closing plus related expenses for a total of $12.6 million for the Amendment. Additionally, a one-time fee of up to 1.0% may be due on the aggregate unpaid balance outstanding at June 30, 2010; specifically, 0.5% of the aggregate unpaid balance outstanding will be due if any portion of the Asset Sale Facility remains unpaid at that date and an additional 0.5% will be due if the Tranche B-1 balance outstanding exceeds $800 million.

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

As an independent oil and gas producer, our revenue, profitability, cash flows, and future rate of growth are substantially dependent on prevailing prices for oil and natural gas. Historically, the energy markets have been very volatile, and we expect such price volatility to continue. Prices for oil and gas declined materially in early 2009 compared to 2008. Any extended decline in oil or gas prices could have a material adverse effect on our financial position, results of operations, cash flows, the quantities of oil and gas reserves that we can economically produce, and may restrict our ability to obtain additional financing or to meet the contractual obligations required under our June 2008 senior secured term loan facility, as amended (“Term Loans”).

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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. As of September 30, 2009, 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 2008 and 2009, a significant amount of time and money has been spent by us on our Telemark Hub development. Our 2010 results of operations, financial position and cash flows will be significantly impacted by the timing and success at this development. 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 prolonged 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. Even though we have recently obtained an amendment to our credit facility, as discussed above, to provide us more latitude in our covenants for the period from October 1, 2009 until December 31, 2010, our ability to meet these covenants is primarily dependent on the adequacy of cash flows from operations, oil and natural gas reserve levels and cash inflows from other financing transactions. Our inability to satisfy the covenants or other contractual requirements contained in our Term Loans would constitute an event of default. An uncured 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. 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 or consummate asset monetizations or other financings may be restricted at a time when we need to raise additional capital. Further, the current economic conditions could also impact our lenders, customers and hedging counterparties and cause them to fail to meet their obligations to us with little or no warning.

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 have also recently conveyed to certain vendors limited-term net profits interests in our Telemark Hub and Clipper 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. We intend to fund our near-term development projects utilizing cash on hand, cash flows from operations and other asset financings. To the extent we are also successful in monetizing 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 plans and their timing. Within certain constraints, we can conserve capital by delaying or

26

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.

Results of Operations

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

For the three months ended September 30, 2009 and 2008 we reported net income (loss) attributable to common shareholders of ($9.1) million and $36.5 million, or ($0.20) and $1.02 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 natural gas production revenues from amortization of deferred revenue related to the second quarter 2008 sale of the limited-term overriding royalty interest. We do not reflect any production associated with those revenues.

	Three Months Ended September 30,					% Change from 2008 to 2009
	2009		2008
Production:
Natural gas (MMcf)		3,689		7,267		(49	)%
Oil and condensate (MBbl)		792		821		(4	)%
Total (MMcfe)		8,438		12,190		(31	)%
Gulf of Mexico (MMcfe)		7,672		8,693		(12	)%
North Sea (MMcfe)		766		3,497		(78	)%
Revenues from production (in thousands):
Natural gas	$	13,479	$	53,429		(75	)%
Effects of cash flow hedges		904		(230	)
Amortization of deferred revenue		1,789		2,434
Total	$	16,172	$	55,633		(71	)%
Oil and condensate	$	50,907	$	53,510		(5	)%
Effects of cash flow hedges		—		(957	)
Amortization of deferred revenue		7,931		10,161
Total	$	58,838	$	62,714		(6	)%
Natural gas, oil and condensate	$	64,386	$	106,939		(40	)%
Effects of cash flow hedges		904		(1,187	)
Amortization of deferred revenue		9,720		12,595
Total	$	75,010	$	118,347		(37	)%
Average realized sales price:
Natural gas (per Mcf)	$	3.67	$	7.35		(50	)%
Effects of cash flow hedges (per Mcf)		0.25		(0.03)
Average realized price (per Mcf)	$	3.92	$	7.32		(46	)%
Oil and condensate (per Bbl)	$	64.28	$	65.18		(1	)%
Effects of cash flow hedges (per Bbl)		—		(1.17)
Average realized price (per Bbl)	$	64.28	$	64.01		—	%
Natural gas, oil and condensate (per Mcfe)	$	7.64	$	8.77		(13	)%
Effects of cash flow hedges (per Mcfe)		0.11		(0.10)
Average realized price (per Mcfe)	$	7.75	$	8.67		(11	)%

27

Revenues from production decreased in third quarter 2009 compared to third quarter 2008 due to a 31% decrease in overall production and an 11% decrease in average realized sales price (21% price decrease in Gulf of Mexico partially offset by a 8% price increase in North Sea). The lower production in the Gulf of Mexico is primarily the result of natural production 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 and due to voluntary production curtailment as a result of low natural gas prices. The lower average realized sales price is due to decreased commodity market prices.

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 September 30,				% Change from 2008 to 2009
	2009		2008
Lease operating (in thousands)	$	22,891	$	24,723	(7	%)
Per Mcfe		2.71		2.03	33	%
Gulf of Mexico		2.80		2.20	27	%
North Sea		1.85		1.61	15	%

Lease operating expense for third quarter 2009 decreased compared to third 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 platform workover at our Gomez Hub. The per unit cost has increased primarily due to this platform 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 was as follows:

	Three Months Ended September 30,				% Change from 2008 to 2009
	2009		2008
General and administrative (in thousands)	$	6,945	$	9,212	(25	%)
Per Mcfe		0.82		0.76	8	%

The general and administrative expense decreased for third quarter 2009 compared to the third quarter 2008 primarily as a result of decreased stock-based compensation costs.

Depreciation, Depletion and Amortization

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

	Three Months Ended September 30,				% Change from 2008 to 2009
	2009		2008
DD&A (in thousands)	$	37,460	$	52,825	(29	%)
Per Mcfe		4.44		4.33	3	%

DD&A expense for the third quarter 2009 decreased compared to third quarter 2008 primarily due to decreased production described above. 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 units-of-production depletion to straight-line depreciation for theATP Innovator upon contribution to ATP-IP.

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Accretion of Asset Retirement Obligation

Accretion expense in third quarter 2009 decreased to $3.0 million compared to $4.2 million in third quarter 2008 primarily due to the North Sea property sale noted above and changes in estimates of future abandonment obligations.

Loss on Abandonment

Loss on abandonment was $1.9 million and $0.9 million in third quarter 2009 and 2008, respectively. These amounts are primarily the result of actual abandonment operations requiring more work than originally estimated.

Interest Expense

Interest expense decreased to $9.0 million for third quarter 2009 compared to $26.6 million for third quarter 2008 primarily due to 2009 capitalized interest of $27.7 million ($25.7 million related to the construction of the Telemark Hub development in the Gulf of Mexico and $2.0 million related to Cheviot in the U.K.) compared to capitalized interest of $12.5 million in third quarter 2008. Capitalized interest is increasing due to higher average construction work-in-progress balances in 2009.

Derivative Income (Expense)

Derivative expense in third quarter 2009 was $3.5 million (losses of $5.6 million and gains of $2.1 million in the Gulf of Mexico and North Sea, respectively). The expense in 2009 is primarily related to net losses associated with certain oil price contracts.

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

Income Taxes

We recorded an income tax benefit of $4.4 million during third quarter 2009 resulting in an overall effective tax benefit rate of 44%. Income tax expense during interim periods is based on applying the estimated worldwide annual effective income tax rate on interim period operations and included the effect of items discrete to the interim period. The effective income tax rate during interim periods may vary from the statutory rate due to the impact of permanent items relative to our net income, as well as the impact from the net income attributable to the redeemable noncontrolling interest. In the comparable quarter of 2008 we recorded tax expense of $5.5 million resulting in an overall effective tax rate of 13%.

Net Income Attributable to the Redeemable Noncontrolling Interest

Net income attributable to the redeemable noncontrolling interest of $3.6 million in the third quarter of 2009 represents the 49% Class A limited partner interest in the earnings of ATP-IP.

Nine Months Ended September 30, 2009 Compared to Nine Months Ended September 30, 2008

For the nine months ended September 30, 2009 and 2008 we reported net income (loss) attributable to common shareholders of ($11.9) million and $71.5 million, or ($0.30) and $1.99 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. For the nine months ended September 30, 2008, production sold under fixed-price delivery contracts which had been designated for the normal purchase and sale exception under the accounting standards are also included in these amounts. For that period, deliveries under the fixed-price contracts are approximately 100% of our oil production and 92% 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 their fair value during the period are reflected as derivative income instead of oil and gas revenues in our consolidated statement of operations.

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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.

	Nine Months Ended September 30,					% Change from 2008 to 2009
	2009		2008
Production:
Natural gas (MMcf)		12,113		29,080		(58	%)
Oil and condensate (MBbl)		2,605		3,857		(32	%)
Total (MMcfe)		27,740		52,219		(47	%)
Gulf of Mexico (MMcfe)		25,399		38,707		(34	%)
North Sea (MMcfe)		2,341		13,512		(83	%)
Revenues from production (in thousands):
Natural gas	$	50,942	$	247,050		(79	%)
Effects of cash flow hedges		1,493		(8,689	)
Amortization of deferred revenue		6,045		3,843
Total	$	58,480	$	242,204		(76	%)
Oil and condensate	$	139,333	$	280,775		(50	%)
Effects of cash flow hedges		—		(2,394	)
Amortization of deferred revenue		26,350		15,608
Total	$	165,683	$	293,989		(44	%)
Natural gas, oil and condensate	$	190,275	$	527,825		(64	%)
Effects of cash flow hedges		1,493		(11,083	)
Amortization of deferred revenue		32,395		19,451
Total	$	224,163	$	536,193		(58	%)
Average realized sales price:
Natural gas (per Mcf)	$	4.21	$	8.50		(50	%)
Effects of cash flow hedges (per Mcf)		0.12		(0.30	)
Average realized price (per Mcf)	$	4.33	$	8.20		(47	%)
Oil and condensate (per Bbl)	$	53.49	$	72.80		(27	%)
Effects of cash flow hedges (per Bbl)		—		(0.62	)
Average realized price (per Bbl)	$	53.49	$	72.18		(26	%)
Natural gas, oil and condensate (per Mcfe)	$	6.86	$	10.11		(32	%)
Effects of cash flow hedges (per Mcfe)		0.05		(0.21	)
Average realized price (per Mcfe)	$	6.91	$	9.90		(30	%)

Revenues from production decreased in the first nine months of 2009 compared to the first nine months of 2008 due to a 47% decrease in overall production and a 30% decrease in average realized sales price (36% price decrease in Gulf of Mexico and 20% price decrease in North Sea). The lower production in the Gulf of Mexico is primarily the result of the September 2008 sale of a 15% limited-term overriding royalty interest in production, the continuing effects in 2009 of the 2008 hurricanes and natural production 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 and due to voluntary production curtailment as a result of low natural gas prices. 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 nine months of 2009 are comprised of amounts realized under our loss of production income insurance policy due to disruptions caused by Hurricane Ike.

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Lease Operating

Lease operating expense includes 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:

	Nine Months Ended September 30,				% Change from 2008 to 2009
	2009		2008
Lease operating (in thousands)	$	60,463	$	73,111	(17	%)
Per Mcfe		2.18		1.40	56	%
Gulf of Mexico		2.14		1.41	52	%
North Sea		2.62		1.36	92	%

Lease operating expense for the first nine months of 2009 decreased compared to the first nine months 2008 primarily due to the sale of 80% of our working interest in Tors and Wenlock in the fourth quarter 2008 and due to reduced fuel and chemical costs in the Gulf of Mexico. These cost decreases were partially offset by increases related to non-recurring workover activities at various Gulf of Mexico and North Sea properties. The per unit cost has increased primarily due to these workover activities 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 was as follows:

	Nine Months Ended September 30,				% Change from 2008 to 2009
	2009		2008
General and administrative (in thousands)	$	25,153	$	27,279	(8	%)
Per Mcfe		0.91		0.52	75	%

The general and administrative expense decreased for first nine months 2009 compared to first nine months 2008 due primarily to decreased stock-based compensation costs and the reversal of an accrual for a terminated employee bonus plan. These were partially offset by an increase in costs associated with the formation of ATP-IP as discussed above.

Depreciation, Depletion and Amortization

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

	Nine Months Ended September 30,				% Change from 2008 to 2009
	2009		2008
DD&A (in thousands)	$	120,432	$	222,097	(46	%)
Per Mcfe		4.34		4.25	2	%

DD&A expense for the first nine months of 2009 decreased compared to the first nine months of 2008 primarily due to decreased production discussed above. 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 theATP Innovator upon contribution to ATP-IP.

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Impairment of Oil and Gas Properties

During the first nine 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 nine months of 2009 decreased to $8.9 million compared to $12.8 million in the first nine months of 2008 primarily due to the North Sea property sale noted above and changes in estimates of future abandonment obligations.

Loss on Abandonment

Loss on abandonment was $2.9 million and $2.3 million in the first nine months of 2009 and 2008, respectively. These amounts are primarily the result of actual abandonment operations requiring more work than originally estimated.

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 $31.8 million for the first nine months of 2009 compared to $79.0 million for the first nine months of 2008 primarily due to 2009 capitalized interest of $71.5 million ($66.7 million related to the construction of the Telemark Hub development in the Gulf of Mexico and $4.8 million related to Cheviot in the U.K.) compared to capitalized interest of $25.5 million in the first nine 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 nine months of 2009 was $15.0 million (gains of $7.6 million and $7.4 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 first nine months of 2008 was $9.2 million (Gulf of Mexico, $11.1 million gain and North Sea, $20.3 million loss). As a result of the limited-term overriding royalty interest and changes in forecasts of production, 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. Also, at the beginning of the third quarter 2008, we entered into oil collar derivatives as price hedges of future-year production. However, at the end of the quarter, we elected to terminate these instruments and realized a gain of $20.0 million in derivatives income. The balance of the derivatives expense is primarily related to changes in fair value of derivatives no longer designated as cash flow hedges.

Loss on Extinguishment of Debt

Loss on debt extinguishment in the first nine months of 2008 is $24.2 million. During the second quarter of 2008, we refinanced the term loans and subordinated notes and recorded as an expense the remaining unamortized deferred financing costs, debt discount related to the retired debt and repayment premiums associated with the subordinated notes.

Income Taxes

We recorded an income tax benefit of $4.1 million during the first nine months of 2009 resulting in an overall effective tax benefit rate of 68%. Income tax expense during interim periods is based on applying the estimated worldwide annual effective income tax rate on interim period operations and included the effect of items discrete to the interim period. The effective income tax rate during interim periods may vary from the statutory rate due to the impact of permanent items relative to our net income, as well as the impact from the net income attributable to the redeemable noncontrolling interest. In the comparable period in 2008 we recorded tax expense of $18.7 million resulting in an overall effective tax rate of 21%.

Net Income Attributable to the Redeemable Noncontrolling Interest

Net income attributable to the redeemable noncontrolling interest of $9.8 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 September 30, 2009.

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Liquidity and Capital Resources

Historically, we have funded our acquisition and development activities through a combination of bank borrowings, proceeds from equity offerings, cash from operations, the sale or conveyance of interests in selected properties and vendor financings. The disarray in the credit markets 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 nine months of 2009, we raised $148.8 million of capital from the formation of ATP-IP and $305.8 million from issuance of common stock and preferred stock.

During this period we also financed significant portions of our development program with transactions entered into with our vendors and their affiliates and $74.5 million from the Gomez Pipeline Transaction, which are discussed above. We have conveyed to certain vendors net profits interests in our Telemark Hub and Clipper oil and gas properties in exchange for development services. We have also negotiated with certain other vendors involved in the development of the Telemark Hub and Clipper to partially defer payments until after production has begun. Development of our interest in the Cheviot field in the U.K. North Sea continues and we have arranged with the fabricator of the floating production and drilling facility to defer $99 million of payments until construction is complete. Consequently, we have terminated the related letter of credit and unencumbered, through the date of this report, the $19.0 million balance of our revolving credit facility which secured it.

We intend to fund our near-term development projects utilizing cash on hand, planned asset monetizations, cash flows from operations and other financing transactions described above. 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 $400 million and $450 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 the remainder of 2009 and 2010, we desire to monetize selected assets during these periods, 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 monetize more selected assets in these periods, providing us with additional capital to further reduce debt. 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 continue to 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 provides us the financial resources needed to fully fund our future development programs.

Cash Flows

	Nine Months Ended September 30,
	2009			2008
Cash provided by (used in) (in thousands):
Operating activities	$	125,232		$	400,703
Investing activities		(472,643	)		(595,152	)
Financing activities		442,498			175,380

As of September 30, 2009, we had working capital of approximately $73.2 million, an increase of approximately $36.7 million from December 31, 2008. We were in compliance with all of the covenants under our Term Loans at September 30, 2009.

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Cash provided by operating activities during the first nine months 2009 and 2008 was $125.2 million and $400.7 million, respectively. Cash flow from operations decreased primarily due to lower net income and from changes in working capital in the first nine months 2009 compared to the first nine months 2008. Net income in the first nine months 2009 decreased primarily due to lower production and lower commodity prices discussed above.

Cash used in investing activities was $472.6 million and $595.2 million during the first nine months 2009 and 2008, respectively. Cash expended in the Gulf of Mexico and North Sea for additions to oil and gas properties was approximately $390.8 million and $74.1 million, respectively, in the first nine months 2009. Cash expended in the Gulf of Mexico and North Sea for additions to oil and gas properties was approximately $406.0 million and $138.1 million, respectively, in the first nine 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 $442.5 million and $175.4 million during the first nine months 2009 and 2008, respectively. The amount in the first nine months of 2009 is from the sale of a redeemable noncontrolling interest in ATP-IP for $148.8 million, the issuance of common and preferred stock for $297.1 million and the monetization of the Gomez hub pipeline for $74.5 million partially offset by $61.3 million of debt repayments and $15.4 million of distributions to the limited partners in ATP-IP. The amount in the first nine months 2008 is primarily related to Term Loans. Payments of Term Loans in 2008 are primarily comprised of $1,202.2 million of repayment of borrowings under our former credit agreement and of $199.5 million related to our former subordinated notes. Proceeds from Term Loans are comprised of $1,593.4 million (net of issuance costs) of proceeds from the Term Loans.

Term Loans

Term Loans consisted of the following (in thousands):

	September 30, 2009			December 31, 2008
Term Loans and revolving credit facility - net of unamortized discount of $27,961 and $35,833, respectively	$	1,313,214		$	1,366,630
Less current maturities		(109,949	)		(10,500	)
Total Term Loans	$	1,203,265		$	1,356,130

On November 2, 2009, we entered into the Amendment to the Term Loans to provide additional flexibility during the Amendment Period. Among other provisions, the Amendment loosens the Net Debt to EBITDAX ratio from 3.0 to 4.0, the EBITDAX to Interest ratio from 2.5 times to 2.0 times and the current ratio from 1.0 to 0.8 for the duration of the Amendment Period. The interest rate on the Tranche B-1 balance will increase to a minimum 11.25% during the Amendment Period, at the end of which it will decrease to a minimum 9.5% for the remainder of the term. Beginning this past July 1, 2009, the minimum rate on the Asset Sale Facility increased by 0.5% and such increases will continue each January 1 and July 1 until it is repaid in full. This Amendment will further increase the rate on the Asset Sale Facility balance outstanding as of October 1, 2009 by 2.75% to a minimum 11.75%. Effective January 1, 2011, the minimum rate on any balance that remains outstanding at that date will decrease by 1.25% to 11.5%.

We paid an initial fee of 0.5% to each of the lender group and the administrative agent of the outstanding balance of the Term Loans at closing plus related expenses for a total of $12.6 million for the Amendment. Additionally, a one-time fee of up to 1.0% may be due on the aggregate unpaid balance outstanding at June 30, 2010; specifically, 0.5% of the aggregate unpaid balance outstanding will be due if any portion of the Asset Sale Facility remains unpaid at that date and an additional 0.5% will be due if the Tranche B-1 balance outstanding exceeds $800 million.

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Certain of our financial covenants are presented below (also see Note 7, “Term Loans” to Financial Statements in Item 1):

Covenant		Requirement during the Amendment Period (4)
1.	Minimum Current Ratio (1)(5)	Greater than 0.8 to 1.0
2.	Ratio of Net Debt to EBITDAX (2)(5)	Less than 4.0 to 1.0
3.	Ratio of EBITDAX to Interest Expense (5)	Greater than 2.0 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 Term Loans, 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. Covenants 1, 2 and 3 revert to 1.0, 3.0 and 2.5 to 1.0, respectively after the Amendment Period.

(5) Revised by the Amendment.

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.

As of the date of this report, the Asset Sale Facility balance is $160.7 million, a $112.6 million decrease from the $273.3 million balance at September 30, 2009. The decrease is primarily due to repayments in accordance with our Term Loan agreement associated with the third quarter transactions and stock issuances discussed above. Related amounts are included in current maturities of Term Loans on the Consolidated Balance Sheet in Item 1. 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.

As of September 30, 2009, we were in compliance with the covenants of the Term Loans; however, we entered into the Amendment above as the Telemark Hub project is nearing completion, to protect the Company’s interests from unforeseen economic hazards, such as project delays, cost overruns, adverse changes to operating conditions or erosion of commodity prices. With the Amendment described above, we believe that we will remain in compliance throughout 2010 and beyond. However, 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.

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Contractual Obligations

The following table summarizes certain contractual obligations at September 30, 2009 (in thousands):

Contractual Obligations	Total		Less than 1 year		1 – 3 years		3 – 5 years		More than 5 years
Term Loans	$	1,341,175	$	109,949	$	194,851	$	1,036,375	$	—
Interest on Term Loans (1)		410,992		107,696		183,299		119,997		—
Other trade commitments		172,063		11,798		160,265		—		—
Minimum transportation and processing commitments		82,873		19,540		20,000		20,000		23,333
Noncancelable operating leases		1,942		847		1,095		—		—
Total contractual obligations	$	2,009,045	$	249,830	$	559,510	$	1,176,372	$	23,333

(1) Interest is based on rates and principal repayments in effect at September 30, 2009.

Our liabilities include asset retirement obligations (“ARO”) ($30.2 million current and $111.1 million long term) that represent the amount at September 30, 2009 of our obligations with respect to the retirement/plugging and abandonment of our oil and gas properties. The ultimate settlement amounts and the timing of the settlements of such obligations are uncertain because they are subject to, among other things, federal, state and local regulation, economic and operational factors. Consequently, ARO is not reflected in the table above.

Our liabilities also include other long term obligations ($9.5 million current and $100.6 million long-term) as of September 30, 2009 that is payable only from production from specified properties. The ultimate amount and timing of the payments will depend on production from the properties and future commodity prices and operating costs. Consequently, these obligations are not reflected in the table above.

Commitments and Contingencies

Management is periodically faced with uncertainties, the outcomes of which are not within its control and will not be known for a long time. We are involved in actions from time to time, which if determined adversely, could have a material negative impact on our financial position, results of operations and cash flows. Management, with the assistance of counsel makes estimates, if determinable, of our probable liabilities and records such amounts in the consolidated financial statements. Such estimates may be the minimum amount of a range of probable loss when no single best estimate is determinable. Disclosure is made, when determinable, of any additional possible amount of loss on these claims, or if such estimate cannot be made, that fact is disclosed. Along with our counsel, we monitor developments related to these legal matters and, when appropriate, we make adjustments to recorded liabilities to reflect current facts and circumstances. Although it is difficult to predict the ultimate outcome of these matters, management is not aware of any amounts that need to be recorded and believes that the recorded amounts, if any, are reasonable. See Note 14, “Commitments and Contingencies” to Financials Statements in Item 1 for additional discussion.

Accounting Pronouncements

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

Critical Accounting Policies

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

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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 7, “Term Loans” to Financial Statements in Item 1.

Foreign Currency Risk

The net assets, net earnings and cash flows from our wholly owned subsidiaries in the U.K. and the Netherlands are based on the U.S. dollar equivalent of such amounts measured in the applicable functional currency. These foreign operations have the potential to impact our financial position 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 Financial Statements in Item 1.

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

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PART II. OTHER INFORMATION

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

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.
3.3	Statement of Resolutions Establishing the 8.00% Convertible Perpetual Preferred Stock of ATP Oil & Gas Corporation, incorporated by reference to Exhibit 4.4 of Registration Statement No. 333-162574 on Form S-3 of ATP filed October 19, 2009.
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.
4.4	Form of Stock Certificate for 8.00% Convertible Perpetual Preferred Stock, incorporated by reference to Exhibit 4.1 of ATP’s Form 8-K dated September 29, 2009.
†10.1	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	First Amendment, dated as of November 2, 2009, to the Credit Agreement, dated as of June 27, 2008, among ATP Oil & Gas Corporation, the lenders party thereto, and Credit Suisse, Cayman Islands Branch, as Administrative Agent and Collateral Agent, incorporated by reference to Exhibit 99.1 to ATP’s Form 8-K dated November 2, 2009.
10.4	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.
†10.5	Employment Agreement between ATP and Pauline H. van der Sman-Archer, dated December 29, 2005, incorporated by reference to Exhibit 10.1 to ATP’s Form 8-K dated December 30, 2005.
†10.6	Employment Agreement between ATP and John E. Tschirhart, dated December 29, 2005, incorporated by reference to Exhibit 10.2 to ATP’s Form 8-K dated December 30, 2005.
†10.7	Employment Agreement between ATP and Leland E. Tate, dated December 29, 2005, incorporated by reference to Exhibit 10.3 to ATP’s Form 8-K dated December 30, 2005.
†10.8	Employment Agreement between ATP and Robert M. Shivers, III, dated December 29, 2005, incorporated by reference to Exhibit 10.4 to ATP’s Form 8-K dated December 30, 2005.
†10.9	Employment Agreement between ATP and Mickey W. Shaw, dated December 29, 2005, incorporated by reference to Exhibit 10.5 to ATP’s Form 8-K dated December 30, 2005.

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†10.10	Employment Agreement between ATP and Albert L. Reese, Jr., dated December 29, 2005, incorporated by reference to Exhibit 10.7 to ATP’s Form 8-K dated December 30, 2005.
†10.11	Employment Agreement between ATP and Isabel M. Plume, dated December 29, 2005, incorporated by reference to Exhibit 10.8 to ATP’s Form 8-K dated December 30, 2005.
†10.12	Employment Agreement between ATP and Scott D. Heflin, dated December 29, 2005, incorporated by reference to Exhibit 10.9 to ATP’s Form 8-K dated December 30, 2005.
†10.13	Employment Agreement between ATP and Keith R. Godwin, dated December 29, 2005, incorporated by reference to Exhibit 10.10 to ATP’s Form 8-K dated December 30, 2005.
†10.14	Employment Agreement between ATP and George Ross Frazer, dated December 29, 2005, incorporated by reference to Exhibit 10.11 to ATP’s Form 8-K dated December 30, 2005.
†10.15	Employment Agreement between ATP and T. Paul Bulmahn, dated December 29, 2005, incorporated by reference to Exhibit 10.12 to ATP’s Form 8-K dated December 30, 2005.
†10.16	Employment Agreement between ATP and George R. Morris, dated May 27, 2008, incorporated by reference to Exhibit 99.1 to ATP’s Form 8-K dated May 21, 2008.
†10.17	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.
†10.18	Discretionary Bonus Policy, incorporated by reference to exhibit 10.17 to ATP’s Annual Report on Form 10-K for the year ended December 31, 2008.
†10.19	Purchase Agreement dated September 23, 2009 among the Company, J.P. Morgan Securities Inc. and Credit Suisse Securities (USA) LLC, as representatives of the several Initial Purchasers named therein, incorporated by reference to Exhibit 10.1 of ATP’s Form 8-K dated September 29, 2009.
21.1	Subsidiaries of ATP, incorporated by reference to Exhibit 21.1 to ATP’s Report on Form 10-Q for the quarter ended March 31, 2009.
*31.1	Certification of Principal Executive Officer pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934, the “Act.”
*31.2	Certification of Principal Financial Officer pursuant to Rule 13a-14(a) of the Act
*32.1	Certification of Principal Executive Officer pursuant to 18 U.S.C. Section 1350
*32.2	Certification of Principal Financial Officer pursuant to 18 U.S.C. Section 1350

† Management contract or compensatory plan or arrangement

* Filed herewith

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SIGNATURES

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

	ATP Oil & Gas Corporation
Date: November 9, 2009	By:	/S/    ALBERT L. REESE JR.
		Albert L. Reese Jr. Chief Financial Officer

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