10-K/A

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-K/A

(Amendment No.1)

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

For the fiscal year ended December 31, 2011

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 of incorporation)	(I.R.S. Employer Identification No.)

4600 Post Oak Place, Suite 100

Houston, Texas 77027

(Address of principal executive offices) (Zip Code)

Registrant’s telephone number, including area code: (713) 622-3311

Securities Registered Pursuant to Section 12 (b) of the Act:

Title of each class	Name of exchange on which registered
Common Stock, par value $.001 per share	NASDAQ Global Select Market

Securities Registered Pursuant to Section 12 (g) of the Act: None

Indicate by check mark if the Registrant is a well-known seasoned issuer as defined in Rule 405 of the Securities Act.     Yes  ¨    No  x

Indicate by check mark if the Registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.     Yes  ¨    No  x

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 website, if any, every interactive Data File required to be submitted electronically and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or such shorter period that Registrant was required to submit and post such files).    Yes  x    No  ¨

        Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of Registrant’s knowledge, in definitive proxy or information statements incorporated by Reference in Part III of this Form 10-K or any amendment to this Form 10-K.  ¨

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	¨	Accelerated filer	x
Non-accelerated filer	¨  (do not check if a smaller reporting company)	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 aggregate market value of the voting and non-voting common stock held by non-affiliates of the Registrant as of June 30, 2011 (the last business day of the Registrant’s most recently completed second fiscal quarter) was approximately $682.1 million. The number of shares of the Registrant’s common stock outstanding as of March 2, 2012 was 52,051,422.

DOCUMENTS INCORPORATED BY REFERENCE

Selected portions of ATP Oil & Gas Corporation’s definitive Proxy Statement, which will be filed with the Securities and Exchange Commission within 120 days after December 31, 2011, are incorporated by reference in Part III of this Form 10-K.

EXPLANATORY NOTE

ATP Oil & Gas Corporation (the “Company”) is filing this Amendment No. 1 on Form 10-K/A (“Amendment No. 1”) solely to include XBRL (eXtensible Business Reporting Language) information in Exhibit 101 that was excluded from our filed Annual Report on Form 10-K for the fiscal year ended December 31, 2011. This Amendment No. 1 makes no other changes to the Annual Report on Form 10-K as filed with the Securities and Exchange Commission on March 15, 2011.

Exhibit 101 provides the following items formatted in XBRL: (i) Balance Sheets at December 31, 2011 and December 31, 2010; (ii) Statements of Operations for the fiscal years ended December 31, 2011, December 31, 2010 and December 31, 2009; (iii) Statements of Comprehensive Income (Loss) for the fiscal years ended December 31, 2011, December 31, 2010 and December 31, 2009; (iv) Statements of Cash Flows for the fiscal years ended December 31, 2011, December 31, 2010 and December 31, 2009; (v) Statements of Temporary Equity for the fiscal years ended December 31, 2011, December 31, 2010 and December 31, 2009; (vi) Statements of Shareholders’ Equity for the fiscal years ended December 31, 2011, December 31, 2010 and December 31, 2009; (vii) Notes to Consolidated Financial Statements; (viii) Schedule I – Parent Company Financial Statements; and (ix) Schedule II – Valuation and Qualifying Accounts.

EXHIBITS

Exhibit Number	Exhibits Description
101.INS	XBRL Instance Document
101.SCH	XBRL Schema Document
101.CAL	XBRL Calculation Linkbase Document
101.DEF	XBRL Definition Linkbase Document
101.LAB	XBRL Label Linkbase Document
101.PRE	XBRL Presentation Linkbase Document

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this amendment to be signed on its behalf by the undersigned, thereunto duly authorized, on March 23, 2012.

ATP OIL & GAS CORPORATION
By:	/s/ Albert L. Reese Jr.
	Albert L. Reese Jr.
	Chief Financial Officer

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Supplemental Quarterly Financial Information

12 Months Ended

Dec. 31, 2011

Supplemental Quarterly Financial Information [Abstract]

Supplemental Quarterly Financial Information

Note 17 — Supplemental Quarterly Financial Information (Unaudited)

(In Thousands, Except Per Share Amounts)

	First Quarter			Second Quarter			Third Quarter			Fourth Quarter
2011
Revenues	$	166,500		$	172,883		$	170,135		$	177,690
Costs, expenses and other (1)		144,894			177,906			124,441			87,275
Income (loss) from operations		21,606			(5,023	)		45,694			90,415
Net loss attributable to common shareholders		(119,547	)		(56,852	)		(5,591	)		(28,492	)
Net loss per share attributable to common shareholders (2):
Basic		(2.34	)		(1.11	)		(0.11	)		(0.56	)
Diluted		(2.34	)		(1.11	)		(0.11	)		(0.56	)
2010
Revenues	$	93,029		$	101,099		$	102,121		$	141,748
Costs, expenses and other (1)		76,715			116,513			91,773			192,172
Income (loss) from operations		16,314			(15,414	)		10,348			(50,424	)
Net loss attributable to common shareholders (3)		(886	)		(82,919	)		(58,350	)		(206,642	)
Net loss per share attributable to common shareholders (2):
Basic		(0.02	)		(1.63	)		(1.15	)		(4.06	)
Diluted		(0.02	)		(1.63	)		(1.15	)		(4.06	)

(1) Included here is impairment of oil and gas properties the most significant amounts of which are in the second quarter of 2011 and fourth quarter of 2010 when impairment was $45.7 million and $48.2 million, respectively.

(2) The sum of the per share amounts per quarter does not equal the total for the year due to changes in the average number of common shares outstanding.

(3) In the second quarter of 2010, we refinanced our long-term debt and recognized a loss on debt extinguishment of $78.2 million. Also in the second quarter of 2010, we completed construction of the ATP Titan and therefore ceased capitalizing related interest costs.

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Organization And Basis Of Presentation

12 Months Ended

Dec. 31, 2011

Organization And Basis Of Presentation [Abstract]

Organization And Basis Of Presentation

Note 1 — Organization and Basis of Presentation

Organization

ATP Oil & Gas Corporation ("the Company") was incorporated in Texas in 1991. ATP Oil & Gas Corporation is engaged internationally in the acquisition, development and production of oil and natural gas properties. Our management team has extensive engineering, geological, geophysical, technical and operational expertise in developing and operating properties in both our current and planned areas of operation. In the Gulf of Mexico and in the U.K. sector of the North Sea (the "North Sea"), we seek to acquire and develop properties with proved undeveloped reserves ("PUD") that are economically attractive to us but are not strategic to major or large independent exploration-oriented 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. In the Gulf of Mexico and North Sea, we believe that our strategy provides assets for us to develop and produce with an attractive risk profile at a competitive cost.

During 2011, we acquired three licenses in the Mediterranean Sea covering potential natural gas resources in the deepwater off the coast of Israel. In the Mediterranean Sea our licenses relate to exploratory prospects where drilling has occurred nearby and hydrocarbons have been discovered by others. Our initial significant capital investment in the Mediterranean Sea is expected to be in the first half of 2012 when drilling exploration begins for one of these three licenses.

Basis of Presentation

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 Oil & Gas (UK) Limited, or "ATP (UK);" ATP Oil & Gas (Netherlands) B.V.; ATP Energy, Inc., ATP Titan LLC, four wholly owned limited liability companies created to own our interests in ATP-IP and ATP Titan LLC and four other wholly owned limited liability companies formed related to our operations in the Mediterranean Sea. All intercompany transactions are eliminated in consolidation. We have reclassified certain amounts applicable to prior periods to conform to current classifications. These reclassifications do not affect earnings.

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Consolidated Statements Of Shareholders' Equity And Temporary Equity (USD $) In Thousands, unless otherwise specified	Temporary Equity-Redeemable Noncontrolling Interest [Member]	Temporary Equity-Eight Percent Convertible Perpetual Preferred Stock, Series B [Member]	Eight Percent Convertible Perpetual Preferred Stock, Liquidation Value [Member]	Common Stock [Member]	Paid-In Capital [Member]	Retained Earnings (Accumulated Deficit) [Member]	Accumulated Other Comprehensive Loss [Member]	Treasury Stock At Cost [Member]	Total
Balance, beginning of year at Dec. 31, 2008				$ 36	$ 400,334	$ 29,644	$ (112,754)	$ (911)
Balance, beginning of year, shares at Dec. 31, 2008				35,903				76
Sale of Class A Limited Partner Interest, net of formation costs	148,751
Income attributable to the redeemable noncontrolling interest	13,380					(13,380)			13,380
Limited partner distributions	(22,533)
Issuance of preferred stock			140,000	15	179,750
Issuance of preferred stock, shares			1,400	14,565
Issuances of common stock
Secondary offerings			140,000	15	179,750
Secondary offerings, shares			1,400	14,565
Costs of issuances					(13,588)
Exercise of stock options/warrants					4
Restricted stock, net of forfeitures, shares				211
Stock-based compensation					7,951
Preferred stock dividends					(2,856)
Net loss						(35,581)			(35,581)
Other comprehensive income (loss)							17,267		17,267
Balance, end of year at Dec. 31, 2009			140,000	51	571,595	(19,317)	(95,487)	(911)	595,931
Balance, end of year at Dec. 31, 2009
Balance, end of year at Dec. 31, 2009	139,598
Balance, end of year, shares at Dec. 31, 2009			1,400	50,679				76
Income attributable to the redeemable noncontrolling interest	15,503					(15,503)			15,503
Limited partner distributions	(14,250)
Issuances of common stock
Exercise of stock options/warrants					3,567
Exercise of stock options/warrants, shares				418
Restricted stock, net of forfeitures, shares				171
Stock-based compensation					6,825
Preferred stock dividends					(11,248)
Net loss						(322,046)			(322,046)
Other comprehensive income (loss)							(5,540)		(5,540)
Balance, end of year at Dec. 31, 2010			140,000	51	570,739	(356,866)	(101,027)	(911)	251,986
Balance, end of year at Dec. 31, 2010	140,851								140,851
Balance, end of year, shares at Dec. 31, 2010			1,400	51,268				76
Balance, beginning of year at Dec. 31, 2010
Income attributable to the redeemable noncontrolling interest	26,622					(26,622)			26,622
Limited partner distributions	(51,653)
Issuance of preferred stock		70,667	84,583
Issuance of preferred stock, shares		785	940
Transfer from shareholders equity		1,902
Transfer from shareholders equity, shares		22
Transfer to temporary equity			(1,902)
Transfer to temporary equity, shares			(22)
Issuances of common stock
Secondary offerings		70,667	84,583
Secondary offerings, shares		785	940
Issuance costs		(2,514)
Costs of issuances					(2,875)
Exercise of stock options/warrants					205
Exercise of stock options/warrants, shares				39
Restricted stock, net of forfeitures				1
Restricted stock, net of forfeitures, shares				652
Stock-based compensation					6,683
Purchase of capped-call options					(26,500)				(26,500)
Preferred stock dividends					(18,583)
Net loss						(165,277)			(165,277)
Other comprehensive income (loss)							(5,365)		(5,365)
Balance, end of year at Dec. 31, 2011			222,681	52	529,669	(548,765)	(106,392)	(911)	96,334
Balance, end of year at Dec. 31, 2011		70,055							70,055
Balance, end of year at Dec. 31, 2011	$ 115,820								$ 115,820
Balance, end of year, shares at Dec. 31, 2011		807	2,318	51,959				76

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Consolidated Balance Sheets (USD $) In Thousands, unless otherwise specified	Dec. 31, 2011	Dec. 31, 2010
Assets
Cash and cash equivalents	$ 65,678	$ 154,695
Restricted cash	20,113	30,270
Accounts receivable (net of allowance of $225 and $225, respectively)	70,628	92,737
Deferred tax asset	480	8,191
Derivative asset	2,194	1,688
Other current assets	28,050	26,408
Total current assets	187,143	313,989
Oil and gas properties (using the successful efforts method of accounting):
Proved properties	4,875,232	4,291,440
Unproved properties	22,945	20,402
Total oil and gas	4,898,177	4,311,842
Less accumulated depletion, depreciation, impairment and amortization	(1,760,756)	(1,407,206)
Oil and gas properties, net	3,137,421	2,904,636
Restricted cash	10,000	10,000
Deferred financing costs, net	40,873	48,353
Other assets, net	13,337	13,124
Total assets	3,388,774	3,290,102
Liabilities and Equity
Accounts payable and accruals	265,620	230,703
Current maturities of long-term debt	33,848	21,625
Asset retirement obligation	52,536	43,386
Deferred tax liability	138
Derivative liability	68,816	37,893
Current maturities of other long-term obligations	113,657	86,521
Total current liabilities	534,615	420,128
Long-term debt	1,976,157	1,857,784
Other long-term obligations	451,797	472,500
Asset retirement obligation	115,981	123,472
Deferred tax liability	27,493	16,956
Derivative liability	522	6,425
Total liabilities	3,106,565	2,897,265
Commitments and contingencies (Note 12)
Temporary equity:
Redeemable noncontrolling interest	115,820	140,851
8% convertible perpetual preferred stock: $0.001 par value; 806,847 issued and outstanding at December 31, 2011; None issued at December 31, 2010; Liquidation value of $80.7 million	70,055
Shareholders' equity:
8% convertible perpetual preferred stock: $0.001 par value, 10,000,000 shares authorized; 2,318,153 issued and outstanding at December 31, 2011; 1,400,000 issued and outstanding at December 31, 2010. Liquidation value of $231.8 million and $140.0 million at December 31, 2011 and 2010, respectively.	222,681	140,000
Common stock: $0.001 par value, 100,000,000 shares authorized; 52,034,547 issued and 51,958,707 outstanding at December 31, 2011; 51,347,163 issued and 51,271,323 outstanding at December 31, 2010	52	51
Additional paid-in capital	529,669	570,739
Accumulated deficit	(548,765)	(356,866)
Accumulated other comprehensive loss	(106,392)	(101,027)
Treasury stock, at cost	(911)	(911)
Total shareholders' equity	96,334	251,986
Total liabilities and equity	$ 3,388,774	$ 3,290,102

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Consolidated Statements Of Comprehensive Income (Loss) (Parenthetical) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Consolidated Statements Of Comprehensive Income (Loss) [Abstract]
Reclassification adjustment for settled hedge contracts, tax	$ 0	$ 0	$ 859
Change in fair value of outstanding hedge positions, tax	$ 0	$ 0	$ 3,736

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Segment Information

12 Months Ended

Dec. 31, 2011

Segment Information [Abstract]

Segment Information

Note 14 — Segment Information

The Company's operations are focused in the Gulf of Mexico and in the North Sea. Management reviews and evaluates separately the operations of its Gulf of Mexico segment and its North Sea segment. The operations of both segments include natural gas and liquid hydrocarbon production and sales. The accounting policies of the reportable segments are the same as those described in Note 2 to the Consolidated Financial Statements. Segment activity for the years ended December 31, is as follows (in thousands):

	Gulf of Mexico			North Sea			Total
2011
Revenues	$	668,184		$	19,024		$	687,208
Depreciation, depletion and amortization		285,966			12,608			298,574
Impairment of oil and gas properties		56,401			1,238			57,639
Gain on disposal of properties		27,000			—			27,000
Drilling interruption costs		19,691			—			19,691
Income (loss) from operations		159,317			(6,625	)		152,692
Interest income		223			—			223
Interest expense, net		326,411			—			326,411
Derivative income		23,373			1,818			25,191
Gain on debt extinguishment		1,095			—			1,095
Income tax expense		—			(18,068	)		(18,068	)
Additions to oil and gas properties		332,873			211,042			543,915
Total assets		2,830,027			558,747			3,388,774
2010
Revenues	$	416,836		$	21,161		$	437,997
Depreciation, depletion and amortization		200,457			20,200			220,657
Impairment of oil and gas properties		48,392			14,875			63,267
Gain on exchange/disposal of properties		26,720			—			26,720
Drilling interruption costs		23,647			—			23,647
Loss from operations		16,071			23,105			39,176
Interest income		243			453			696
Interest expense, net		222,104			—			222,104
Derivative expense		(16,253	)		(6,166	)		(22,419	)
Loss on debt extinguishment		(75,316	)		—			(75,316	)
Income tax benefit		24,023			12,250			36,273
Additions to oil and gas properties		570,393			139,890			710,283
Total assets		2,896,486			393,616			3,290,102

	Gulf of Mexico			North Sea			Total
2009
Revenues	$	295,124		$	17,030		$	312,154
Depreciation, depletion and amortization		128,777			24,003			152,780
Impairment of oil and gas properties		45,799			—			45,799
Gain (loss) on disposal of properties		13,177			(744	)		12,433
Income (loss) from operations		3,825			(21,054	)		(17,229	)
Interest income		537			173			710
Interest expense, net		40,884			—			40,884
Derivative income (expense)		(9,834	)		9,122			(712	)
Income tax benefit		18,885			3,649			22,534
Additions to oil and gas properties		721,793			96,386			818,179
Total assets		2,545,876			257,271			2,803,147

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Subsequent Events

12 Months Ended

Dec. 31, 2011

Subsequent Events [Abstract]

Subsequent Events

Note 16 — Subsequent Events

Our evaluation has identified the following matters which require disclosure as events subsequent to December 31, 2011:

During 2012 through March 9, we sold for $65 million certain Overrides in our Gomez Hub. Similar to previous Overrides sold by us, the purchasers receive a designated portion of the revenues produced at the Gomez Hub until they have obtained the amount of their investment plus a designated return. Once payout of the Overrides has been achieved, the interests revert back to us. In March 2012, we entered into certain commodity price derivatives contracts which have provided us with net cash advances of $19.4 million and obligate us to pay market prices at the time of settlement. See also the discussion in Note 7, Other Long-term Obligations of changes to deferred payments related to our Cheviot field in the North Sea.

On March 9, 2012, we entered into Amendment and Restatement and Incremental Loan Assumption Agreement to the Credit Facility ("The Amendment"). The Amendment provides for an increase to the principal amount of the Credit Facility from $210 million to the lesser of $365.0 million or 10% of the Company's Adjusted Consolidated Net Tangible Assets, as defined. The amendment also reduces the interest rate of the Credit Facility from 9% fixed to a floating rate of 8.75% calculated based on a Libor floor of 1.50% plus 7.25%. The other terms of the Credit Facility are essentially unchanged by the Amendment.

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Consolidated Statements Of Cash Flows (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Cash flows from operating activities
Net loss	$ (165,277)	$ (322,046)	$ (35,581)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities -
Depreciation, depletion and amortization	298,574	220,657	152,780
Impairment of oil and gas properties	57,639	63,267	45,799
Gain on exchange/disposal of properties	(27,000)	(26,720)	(12,433)
Accretion of asset retirement obligation	15,000	13,827	11,676
Deferred income tax expense (benefit)	19,395	(35,414)	(23,079)
Derivative (income) expense	(38,188)	20,090	39,648
(Gain) loss on debt extinguishment	(1,095)	18,973
Stock-based compensation	6,683	6,825	7,951
Amortization of deferred revenue		(19,336)	(39,893)
Noncash interest expense	35,320	28,078	13,262
Other noncash items, net	(694)	3,245	2,443
Changes in assets and liabilities -
Accounts receivable and other current assets	59,061	(31,979)	50,402
Accounts payable and accruals	(29,491)	23,213	(53,168)
Other assets and liabilities	(32,836)	40	20
Net cash provided by (used in) operating activities	197,091	(37,280)	159,827
Cash flows from investing activities
Additions to oil and gas properties	(436,910)	(598,108)	(635,447)
Proceeds from disposition of properties	27,000	17,053	13,000
Decrease (increase) in restricted cash	10,157	(29,766)	(10,504)
Net cash used in investing activities	(399,753)	(610,821)	(632,951)
Cash flows from financing activities
Proceeds from senior second lien notes		1,492,965
Proceeds from first lien term loans	59,400	147,000
Proceeds from term loan facility-ATP Titan assets	91,000	238,750
Proceeds from term loans		46,000	19,000
Payments of term loans	(25,375)	(1,263,727)	(176,512)
Deferred financing costs	(4,561)	(62,937)	(6,490)
Proceeds from common stock issuances, net of costs			170,629
Proceeds from preferred stock issuances, net of costs	149,866		135,549
Purchase of capped-call options on ATP common stock	(26,500)
Proceeds from other long-term obligations	85,326	231,888	89,011
Payments of other long-term obligations	(180,848)	(102,818)	(2,298)
Sale of redeemable noncontrolling interest, net of costs			148,751
Distributions to noncontrolling interest	(45,961)	(14,250)	(18,970)
Preferred stock dividends	(15,098)	(11,276)
Derivative contracts, net	67,129
Other financings, net	(42,534)	(11,180)
Exercise of stock options/warrants	205	3,609	3
Net cash provided by financing activities	112,049	694,024	358,673
Effect of exchange rate changes on cash and cash equivalents	1,596	(189)	8,419
Increase (decrease) in cash and cash equivalents	(89,017)	45,734	(106,032)
Cash and cash equivalents, beginning of year	154,695	108,961	214,993
Cash and cash equivalents, end of year	$ 65,678	$ 154,695	$ 108,961

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Consolidated Balance Sheets (Parenthetical) (USD $)	Dec. 31, 2011	Dec. 31, 2010
Consolidated Balance Sheets [Abstract]
Accounts receivable, allowance	$ 225,000	$ 225,000
Temporary equity, convertible perpetual preferred stock, par value	$ 0.001	$ 0.001
Temporary equity, convertible perpetual preferred stock, shares issued	806,847	0
Temporary equity, convertible perpetual preferred stock, shares outstanding	806,847	0
Temporary equity, convertible perpetual preferred stock, liquidation value	80,700,000	80,700,000
8% convertible perpetual preferred stock, par value	$ 0.001	$ 0.001
8% convertible perpetual preferred stock, shares authorized	10,000,000	10,000,000
8% convertible perpetual preferred stock, issued	2,318,153	1,400,000
8% convertible perpetual preferred stock, outstanding	2,318,153	1,400,000
8% convertible perpetual preferred stock, liquidation value, discount	$ 231,800,000	$ 140,000,000
Common stock, par value	$ 0.001	$ 0.001
Common stock, shares authorized	100,000,000	100,000,000
Common stock, issued	52,034,547	51,347,163
Common stock, outstanding	51,958,707	51,271,323

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Stock-Based And Other Compensation Plans

12 Months Ended

Dec. 31, 2011

Stock-Based And Other Compensation Plans [Abstract]

Stock-Based And Other Compensation Plans

Note 9 — Stock-Based and Other Compensation Plans

In January 2001, the Board of Directors approved the 2000 Stock Plan (the "2000 Plan") and in June 2010 the Shareholders approved the 2010 Stock Plan (the "2010 Plan") to provide increased incentive for the Company's employees and directors. The 2000 Plan authorized the granting of options and restricted stock awards for up to 4,000,000 shares of common stock, and expired in February 2011. The 2010 Plan authorizes the granting of options, restricted stock awards, restricted stock bonus awards and performance share bonus awards for up to an aggregate 6,000,000 shares of common stock. Generally, options are granted at prices equal to at least 100% of the fair value of the stock at the date of grant, expire not later than five years from the date of grant and vest ratably over a four-year period following the date of grant. From time to time, as approved by the Board of Directors, options with differing terms have also been granted. We recognized stock option compensation expense of $2.6 million, $2.5 million and $3.0 million for the years ended December 31, 2011, 2010 and 2009, respectively.

The fair values of options granted during the years ended December 31, 2011, 2010 and 2009 were estimated at the date of grant using a Black-Scholes option-pricing model assuming no dividends and with the following weighted average assumptions for grants during the periods indicated:

	Year Ended December 31,
	2011			2010			2009
Weighted average volatility		87	%		84	%		76	%
Expected term (in years)		3.8			3.8			3.8
Risk-free rate		1.1	%		1.0	%		1.7	%
Weighted average fair value of options – grant date	$	7.94		$	5.53		$	8.81

Volatilities are based on the historical volatility of our closing common stock price. Expected term of options granted represents the period of time that options granted are expected to be outstanding. The expected term of the options granted in 2011, 2010 and 2009 is estimated using the simplified method because the option terms are homogeneous and the Company has insufficient option exercise history to refine its expectations. The risk-free rate for periods within the contractual life of the options is based on the comparable U.S. Treasury rates in effect at the time of each grant. The aggregate intrinsic values of options exercised during the years ended December 31, 2011, 2010 and 2009 were $0.4 million, $0.4 million and $0, respectively. The following table sets forth a summary of option transactions for the year ended December 31, 2011:

	Number of Options			Weighted Average Grant Price		Aggregate Intrinsic Value (1) ($000)		Weighted Average Remaining Contractual Life
								(in years)
Outstanding at beginning of year		1,521,291		$	23.31
Granted		476,510			13.15
Exercised		(34,927	)		6.15
Canceled		(110,950	)		20.78
Expired		(173,687	)		38.27
Outstanding at end of year		1,678,237			19.40	$	577		2.8
Vested and expected to vest		1,465,761			20.12	$	489		2.7
Options exercisable at end of year		680,967			29.17	$	201		1.6

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

A summary of the status of ATP's nonvested stock options as of December 31, 2011 and changes during the year is presented below:

	Number of Options			Weighted Average Grant-date Fair Value
Nonvested at beginning of year		933,972		$	6.98
Granted		476,510			7.94
Vested		(331,307	)		8.21
Forfeited		(81,905	)		7.79
Nonvested at end of year		997,270			6.97

At December 31, 2011, unrecognized compensation expense related to nonvested stock option grants totaled $3.3 million. Such unrecognized expense will be recognized as vesting occurs over a weighted average period of 2.6 years.

Restricted stock grants vest over a three-year period, are subject to forfeiture, and cannot be sold, transferred or disposed of during the restriction period. The holders of the shares have voting and dividend rights with respect to such shares. During the years ended December 31, 2011, 2010 and 2009, we recognized aggregate compensation expense of $4.1 million, $4.3 million and $4.9 million, respectively, related to outstanding restricted stock grants.

The following table sets forth the changes in nonvested restricted stock for the year ended December 31, 2011:

	Number of Shares			Weighted Average Grant-date Fair Value		Aggregate Intrinsic Value (1) ($000)
Nonvested at beginning of year		422,637		$	19.76
Granted		658,611			11.40
Forfeited		(6,154	)		16.25
Vested		(243,065	)		24.65
Nonvested at end of year		832,029			11.74	$	6,124

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

At December 31, 2011, unrecognized compensation expense related to restricted stock totaled $5.2 million. Such unrecognized expense will be recognized as vesting occurs over a weighted average period of 2.3 years.

We have a 401(k) Savings Plan which covers all domestic employees. At our discretion, we may match a certain percentage of the employees' contributions to the plan. The matching percentage is currently 100% of the first 3% and 50% of the next 2% of each participant's compensation. Our matching contributions to the plan were approximately $302,000, $299,000 and $289,000 for the years ended December 31, 2011, 2010 and 2009, respectively.

We also have a defined contribution plan for our U.K. employees. We currently contribute 4% to the plan and such contributions are subject to the Pensions Act 1999 (U.K.) and to U.K. rules on taxation. For the years ended December 31, 2011, 2010 and 2009, we contributed approximately $34,000, $29,000 and $33,000, respectively.

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Document And Entity Information (USD $)
In Millions, except Share data, unless otherwise specified

12 Months Ended

Dec. 31, 2011

Mar. 02, 2012

Jun. 30, 2011

Document And Entity Information [Abstract]

Document Type

10-K

Amendment Flag

true

Document Period End Date

Dec. 31, 2011

Document Fiscal Year Focus

2011

Document Fiscal Period Focus

FY

Entity Registrant Name

ATP OIL & GAS CORP

Entity Central Index Key

0001123647

Current Fiscal Year End Date

--12-31

Entity Filer Category

Accelerated Filer

Entity Common Stock, Shares Outstanding

52,051,422

Entity Well-known Seasoned Issuer

No

Entity Public Float

$ 682.1

Entity Current Reporting Status

Yes

Entity Voluntary Filers

No

Amendment Description

ATP Oil & Gas Corporation (the "Company") is filing this Amendment No. 1 on Form 10-K/A ("Amendment No. 1") solely to include XBRL (Extensible Business Reporting Language) information in Exhibit 101 that was excluded from our filed Annual Report on Form 10-K for the fiscal year ended December 31, 2011. This Amendment No. 1 makes no other changes to the Annual Report on Form 10-K as filed with the Securities and Exchange Commission on March 15, 2011.

Exhibit 101 provides the following items formatted in eXtensible Business Reporting Language (XBRL): (i) Balance Sheets at December 31, 2011 and December 31, 2010; (ii) Statements of Operations for the fiscal years ended December 31, 2011, December 31, 2010 and December 31, 2009; (iii) Statements of Comprehensive Income (Loss) for the fiscal years ended December 31, 2011, December 31, 2010 and December 31, 2009; (iv) Statements of Cash Flows for the fiscal years ended December 31, 2011, December 31, 2010 and December 31, 2009; (v) Statements of Temporary Equity for the fiscal years ended December 31, 2011, December 31, 2010 and December 31, 2009; (vi) Statements of Shareholders' Equity for the fiscal years ended December 31, 2011, December 31, 2010 and December 31, 2009; (vii) Notes to Consolidated Financial Statements; (viii) Schedule I – Parent Company Financial Statements; and (ix) Schedule II – Valuation and Qualifying Accounts.

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Earnings Per Share

12 Months Ended

Dec. 31, 2011

Earnings Per Share [Abstract]

Earnings Per Share

Note 10 — Earnings Per Share

Basic earnings per share ("EPS") is computed by dividing net income or loss attributable to common shareholders by the weighted average number of common shares (other than nonvested restricted stock) outstanding during the period. Weighted average shares outstanding for diluted EPS also includes a hypothetical number of additional shares ("Common Stock Equivalents") calculated assuming the exercise or conversion of all in-the-money options, warrants and convertible preferred stock and full vesting of restricted stock awards. Common Stock Equivalents are excluded from the computation of weighted average common shares outstanding when the per share effect is antidilutive. The impact of assumed conversion of preferred stock on net income attributable to common shareholders is excluded from the computation of EPS when its impact is antidilutive.

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

	Year Ended December 31,
	2011			2010			2009
Net loss attributable to common shareholders:
Net loss attributable to common shareholders	$	(210,482	)	$	(348,797	)	$	(51,817	)
Add impact of assumed preferred stock conversions (if-converted method)		—			—			—
Net loss attributable to common shareholders and impact of assumed conversions	$	(210,482	)	$	(348,797	)	$	(51,817	)
Weighted average shares outstanding:
Weighted average number of shares outstanding – basic		51,077			50,715			41,853
Effect of potentially dilutive securities:
Stock options and warrants		—			—			—
Nonvested restricted stock		—			—			—
Preferred stock		—			—			—
Weighted average number of shares outstanding – diluted		51,077			50,715			41,853
Net loss per share attributable to common shareholders:
Basic	$	(4.12	)	$	(6.88	)	$	(1.24	)
Diluted	$	(4.12	)	$	(6.88	)	$	(1.24	)

The following were excluded from diluted EPS because their inclusion would have been antidilutive (in thousands):

	Year Ended December 31,
	2011		2010		2009
Net loss attributable to common shareholders:
Preferred stock dividends	$	18,583	$	11,248	$	2,856
Weighted average shares outstanding:
Common stock equivalents		427		500		300
Assumed conversion of preferred stock		10,458		6,300		1,600
Out-of-the-money stock options		1,018		1,100		1,100

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Consolidated Statements Of Operations (USD $) In Thousands, except Per Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Revenues:
Oil and gas production	$ 687,208	$ 437,997	$ 298,490
Other			13,664
Total revenue	687,208	437,997	312,154
Costs, operating expenses and other:
Lease operating	122,202	132,544	84,956
Exploration	1,251	1,174	264
General and administrative	43,242	43,948	43,469
Depreciation, depletion and amortization	298,574	220,657	152,780
Impairment of oil and gas properties	57,639	63,267	45,799
Accretion of asset retirement obligation	15,000	13,827	11,676
Drilling interruption costs	19,691	23,647
Loss on abandonment	3,916	4,829	2,872
Gain on exchange/disposal of properties	(27,000)	(26,720)	(12,433)
Total operating expenses	534,515	477,173	329,383
Income (loss) from operations	152,693	(39,176)	(17,229)
Other income (expense):
Interest income	223	696	710
Interest expense, net	(326,411)	(222,104)	(40,884)
Derivative income (expense)	25,191	(22,419)	(712)
Gain (loss) on debt extinguishment	1,095	(75,316)
Total other non operating income (expenses)	(299,902)	(319,143)	(40,886)
Loss before income taxes	(147,209)	(358,319)	(58,115)
Income tax (expense) benefit:
Current	1,327	859	(545)
Deferred	(19,395)	35,414	23,079
Total	(18,068)	36,273	22,534
Net loss	(165,277)	(322,046)	(35,581)
Less income attributable to the redeemable noncontrolling interest	(26,622)	(15,503)	(13,380)
Less convertible preferred stock dividends	(18,583)	(11,248)	(2,856)
Net loss attributable to common shareholders	$ (210,482)	$ (348,797)	$ (51,817)
Net loss per share attributable to common shareholders:
Basic	$ (4.12)	$ (6.88)	$ (1.24)
Diluted	$ (4.12)	$ (6.88)	$ (1.24)
Weighted average number of common shares:
Basic	51,077	50,715	41,853
Diluted	51,077	50,715	41,853

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Supplemental Disclosures Of Cash Flow Information

12 Months Ended

Dec. 31, 2011

Supplemental Disclosures Of Cash Flow Information [Abstract]

Supplemental Disclosures Of Cash Flow Information

Note 4 — Supplemental Disclosures of Cash Flow Information

Supplemental disclosures of cash flow information (in thousands):

	Year Ended December 31,
	2011		2010			2009
Cash paid during the year for interest, net of amounts capitalized	$	288,214	$	192,697		$	16,536
Cash received during the year for income taxes		—		—			13,581
Noncash investing and financing activities:
Increase in noncash property additions		64,469		86,491			187,880
Accrued distributions to noncontrolling interest		5,692		—			3,563
Accrued preferred stock dividends		3,485		(28	)		2,856

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Risks And Uncertainties

12 Months Ended

Dec. 31, 2011

Risks And Uncertainties [Abstract]

Risks And Uncertainties

Note 3 — Risks and Uncertainties

Since May 2010 when the federal government imposed the first of a series of moratoriums on drilling in the Gulf of Mexico, we have faced unparalleled difficulties in obtaining permits to continue our development programs. Prior to the moratoriums, we anticipated developing and bringing to production three additional wells at our Telemark Hub and two additional wells at our Gomez Hub by the end of 2010. It has taken until the first quarter of 2012 for us to bring to production all of the three additional wells at the Telemark Hub and, during the third quarter of 2011, the two wells planned for the Gomez Hub were postponed to late 2012/early 2013.

The new wells that have been placed on production have taken longer to complete and bring to production than originally planned and one of them has not produced at rates that were previously projected. In addition, we have incurred capital and operating costs higher than we expected primarily due to additional regulations imposed since the Deepwater Horizon incident and the requirement to perform sidetracks on two of the wells. The new wells helped us achieve production growth in 2011, and we forecast production and operating cash flow growth in 2012 as development activity continues. While cash flows were lower than previously projected due to lower than expected production rates, delays in bringing on new production and higher capital costs, we continued our development operations by supplementing our cash flows from operating activities with funds raised through various transactions (see the Consolidated Statement of Cash Flows.) Our planned operations for 2012 reflect our expectations for production based on actual production history, new production expected to be brought online, the development delays at Telemark and Gomez Hubs discussed above, the deferral of certain capital expenditures, the continuation of commodity prices near current levels, the higher anticipated costs associated with maintaining existing production and bringing new production online, and the higher cost of servicing our additional financing and other obligations.

As of December 31, 2011, we had a working capital deficit of $347.5 million. To preserve our development momentum in the negative working capital environment that we experienced throughout 2011, we have increased our term loans, issued convertible perpetual preferred stock, granted net profits interests (NPI's) to certain of our vendors, sold NPI's and dollar-denominated overriding royalty interests (Overrides) in our properties to investors, and we have entered into prepaid swaps against our future production that provided cash proceeds to us at closing. We have negotiated with the constructor of the hull of the Octabuoy in China to defer the majority of our payments until the hull is ready to be moved to the North Sea, currently scheduled to be during 2013. A similar arrangement is in place for the Octabuoy topside equipment, which is being constructed by the same company in China.

As operator of all of our projects that require cash commitments within the next twelve months and beyond, we retain significant control over the development concept and its timing. We consider the control and flexibility afforded by operating our properties under development to be instrumental to our business plan and strategy. To manage our liquidity, we have delayed certain capital commitments, and within certain constraints, we can continue to conserve capital by further delaying or eliminating future capital commitments. While postponing or eliminating capital projects will delay or reduce future cash flows from scheduled new production, this control and flexibility is one method by which we can match, on a temporary basis, our capital commitments to our available capital resources.

Our cash flow projections are highly dependent upon numerous assumptions including the timing and rates of production from our new wells, the sales prices we realize for our oil and natural gas, the cost to develop and produce our reserves, our ability to monetize our properties and future production through asset sales and financial derivatives, and a number of other factors, some of which are beyond our control. Our inability to increase near-term production levels and generate sufficient liquidity through the actions noted above could result in our inability to meet our obligations as they come due which would have a material adverse affect on us. In the event we do not achieve the projected production and cash flow increases, we will attempt to fund any short-term liquidity needs through other financing sources; however, there is no assurance that we will be able to do so in the future if required to meet any short-term liquidity needs. We believe we can continue to meet our obligations for at least the next twelve months through a combination of cash flow from operations, continuing to sell or assign interests in our properties and selling forward our production through the financial derivatives markets, and if necessary, further delaying certain development activities.

Despite our anticipated production growth, we remain highly leveraged. Servicing our debt and other long-term obligations will continue to place significant constraints on us and makes us vulnerable to adverse economic and industry conditions. Specifically, certain of our financing and derivative transactions require us to make payments in future periods from the proceeds (or net profits) from the sale of production. While these financing transactions have enabled us to continue the development of our properties and meet current operating needs, they will significantly burden the future net cash flows from our production until these obligations are satisfied. (See Note 7, "Other Long-term Obligations," and Note 13, "Derivative Instruments and Risk Management Activities" for further details.)

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. The estimation process requires significant assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir. Therefore, these estimates are inherently imprecise and the quality and reliability of this data can vary. Estimates of our oil and natural gas reserves and the costs and timing associated with developing these reserves are subject to change, and may differ materially from our actual results. A substantial portion of our total proved reserves are undeveloped and recognition of such reserves requires us to expect that capital will be available to fund their development. The size of our operations and our capital expenditures budget limit the number of properties that we can develop in any given year and we intend to continue to develop these reserves, but there is no assurance we will be successful. Development of these reserves may not yield the expected results, or the development may be delayed or the costs may exceed our estimates, any of which may materially affect our financial position, results of operations, cash flows, the quantity of proved reserves that we report, and our ability to meet the requirements of our financing obligations.

A substantial portion of our current production is concentrated among relatively few wells located offshore in the Gulf of Mexico and in the North Sea, which are characterized by production declines more rapid than those of conventional onshore properties. As a result, we are particularly vulnerable to a near-term severe impact resulting from unanticipated complications in the development of, or production from, any single material well or infrastructure installation, including lack of sufficient capital, delays in receiving necessary drilling and operating permits, increased regulation, reduced access to equipment and services, mechanical or operational failures, and bad weather. Any unanticipated significant disruption to, or decline in, our current production levels or prolonged negative changes in commodity prices or operating cost levels could have a materially adverse effect on our financial position, results of operations, cash flows, the quantity of proved reserves that we report, and our ability to meet our commitments as they come due.

Oil and natural gas development and production in the Gulf of Mexico are regulated by the Bureau of Ocean Energy Management ("BOEM") and the Bureau of Safety and Environmental Enforcement ("BSEE") of the Department of the Interior, collectively, formerly known as the Bureau of Ocean Energy Management, Regulation and Enforcement. Our near-term operating and development plans in the Gulf of Mexico, as well as our longer-term business plan, are dependent upon receiving regulatory approvals for deepwater drilling and other permits required by the BSEE. Delays in the permitting process directly impact the timing of our development and production activities, and can materially affect our financial position, results of operations, cash flows, and the quantity of proved reserves that we report.

We cannot predict future changes in laws and regulations governing oil and gas operations in the Gulf of Mexico. New regulations issued since the Deepwater Horizon incident in 2010 have changed the way we conduct our business and increased our costs of developing and commissioning new assets. We incurred additional costs in 2010 from the deepwater drilling moratoriums, subsequent drilling permit delays and additional inspection and commissioning costs. Some of these additional costs continued into 2011 and are projected to continue into 2012. Should there be additional significant future regulations or additional statutory limitations, they could require further changes in the way we conduct our business, further increase our costs of doing business or ultimately prohibit us from drilling for or producing hydrocarbons in the Gulf of Mexico. Additionally, we cannot influence or predict if or how the governments of other countries in which we operate may modify their regulatory regimes from time to time.

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

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Fair Value Measurements

12 Months Ended

Dec. 31, 2011

Fair Value Measurements [Abstract]

Fair Value Measurements

Note 15 — Fair Value Measurements

The accounting standards for fair value measurement and disclosure applies to all financial assets and financial liabilities that are being measured and reported on a fair value basis. Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). The standards establish a framework for measuring fair value and expand disclosure about fair value measurements. The standards require fair value measurements be classified and disclosed in one of the following categories:

Level 1:	Measured based on unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities.
Level 2:	Measured based on quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability. This category includes those derivative instruments that we value using observable market data. Substantially all of these inputs are observable in the marketplace throughout the full term of the derivative instrument, can be derived from observable data, or supported by observable levels at which transactions are executed in the marketplace.
Level 3:	Measured based on prices or valuation models that require inputs that are both significant to the fair value measurement and less observable from objective sources (i.e., supported by little or no market activity). Our option pricing models are industry-standard and consider various inputs including forward commodity price estimates, volatility and time value of money.

Financial assets and liabilities are classified based on the lowest level input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and determines the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels.

Assets and Liabilities Measured at Fair Value on a Recurring Basis

The fair values of our derivative contracts are classified as Level 3 based on the significant unobservable inputs into our expected present value models (see Note 13, "Derivative Instruments and Price Risk Management Activities"). The following table sets forth a reconciliation of changes in the fair value of these financial assets (liabilities) during the year ended December 31, 2011 (in thousands):

	U.S. Gas Fixed-Price Physicals			U.S. Gas Calls			U.S. Oil Swaps(1)			U.S. Oil Swaps(2)			U.S. Gas Price Collars			U.K. Gas Swaps			Total
Balance at beginning of period	$	289		$	—		$	(27,519	)	$	(12,027	)	$	658		$	(4,031	)	$	(42,630	)
Derivative gains included in earnings		5,351			2,069			7,329			8,373			170			1,899			25,191
Sales		—			(2,133	)		(86,646	)		—			—			—			(88,779	)
Settlements and terminations		(3,446	)		—			37,775			3,654			(828	)		1,919			39,074
Balance at end of period	$	2,194		$	(64	)	$	(69,061	)	$	—		$	—		$	(213	)	$	(67,144	)
Changes in unrealized gain (loss) included in derivative income (expense) relating to derivatives still held at December 31, 2011	$	2,935		$	(64	)	$	(5,284	)	$	—		$	—		$	1,036		$	(1,377	)

(1) In 2011, we entered into certain off-market oil swap derivative contracts which provide us with $87.9 million of cash advances from the counterparty (of which $1.2 million will be received in 2012) and obligate us to pay market prices at the time of settlement.

(2) These swaps were matched with call options to allow us to reparticipate in price increases above certain levels.

The following table sets forth a reconciliation of changes in the fair value of these financial assets (liabilities) during the year ended December 31, 2010 (in thousands):

	U.S. Gas Fixed-Price Physicals			U.S. Gas Price Collars			U.S. Oil Swaps			U.S. Oil Swaps(1)			U.K. Gas Swaps			Total
Balance at beginning of period	$	(778	)	$	(339	)	$	(7,837	)	$	(14,910	)	$	—		$	(23,864	)
Derivative gains (losses) included in earnings		9,161			3,727			(24,276	)		(4,090	)		(5,751	)		(21,229	)
Settlements and terminations		(8,094	)		(2,730	)		4,594			6,973			1,720			2,463
Balance at end of period	$	289		$	658		$	(27,519	)	$	(12,027	)	$	(4,031	)	$	(42,630	)
Changes in unrealized gain (loss) included in derivative income (expense) relating to derivatives still held at December 31, 2010	$	289		$	1,170		$	(21,892	)	$	(10,520	)	$	(4,031	)	$	(34,984	)

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

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

Oil and gas properties are measured at fair value on a nonrecurring basis upon impairment and when acquired in a nonmonetary property exchange. During 2011, we recorded impairment expense of $57.6 million related to oil and gas properties. During 2010, we recorded impairment expense of $63.3 million related to oil and gas properties and gain on nonmonetary property exchange of $12.0 million related to proved Gulf of Mexico properties. The impairment charges reduce the oil and gas properties' carrying values to their estimated fair values and are classified as Level 3. Fair value is calculated as the estimated discounted future net cash flows attributable to the assets. The gain on nonmonetary property exchange reflects the difference between the carrying value of the property surrendered and the estimated fair value of the property received which is classified as Level 3 and which is calculated based on the estimated discounted future net cash flows attributable to that asset.

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

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Income Taxes

12 Months Ended

Dec. 31, 2011

Income Taxes [Abstract]

Income Taxes

Note 11 — Income Taxes

Income tax (expense) benefit consisted of the following (in thousands):

	Year Ended December 31,
	2011			2010			2009
Current:
Domestic	$	—		$	924		$	(924	)
Foreign		1,327			(65	)		379
		1,327			859			(545	)
Deferred:
Domestic		58,057			117,459			19,809
Foreign		(15,334	)		12,790			4,570
		42,723			130,249			24,379
Valuation allowance		(62,118	)		(94,835	)		(1,300	)
Total income tax (expense) benefit	$	(18,068	)	$	36,273		$	22,534

Income (loss) before income taxes consisted of the following (in thousands):

	Year Ended December 31,
	2011			2010			2009
Domestic	$	(142,330	)	$	(329,497	)	$	(46,860	)
Foreign		(4,879	)		(28,822	)		(11,255	)
	$	(147,209	)	$	(358,319	)	$	(58,115	)

The reconciliation of income tax computed at the U.S. federal statutory tax rates to the provision for income taxes is as follows:

	Year Ended December 31,
	2011			2010			2009
Statutory federal income tax rate		35.00	%		35.00	%		35.00	%
Nondeductible and other		(0.13	)		(0.80	)		(3.63	)
Foreign operations		(11.28	)		0.88			1.52
Impact of redeemable noncontrolling interest		6.33			1.51			8.06
Valuation allowance		(42.19	)		(26.47	)		(2.18	)
		(12.27	%)		10.12	%		38.77	%

Included in 2011 foreign operations is the effect of an increase in the UK statutory tax rate from 20% to 30% resulting in a decrease of 8.28% to the effective tax rate benefit on the current year pre tax book loss.

Significant components of our deferred tax assets (liabilities) as of December 31, 2011 and 2010 are as follows (in thousands):

	December 31, 2011
	U.S.			Foreign			Total
Deferred tax asset:
Net operating loss carry forwards	$	190,883		$	297,338		$	488,221
Unrealized derivative loss		1,250			—			1,250
Alternative minimum tax credit		1,841			—			1,841
Stock-based compensation		5,047			435			5,482
Asset retirement obligation		12,289			—			12,289
Other		563			—			563
Valuation allowance		(155,442	)		(5,418	)		(160,860	)
Deferred tax asset		56,431			292,355			348,786
Deferred tax liability:
Oil and gas property basis differences		(55,588	)		(317,591	)		(373,179	)
Other		(843	)		(1,915	)		(2,758	)
Deferred tax liability		(56,431	)		(319,506	)		(375,937	)
Net deferred tax liability		—			(27,151	)		(27,151	)
Less net current deferred tax liability		—			138			138
Less net current deferred tax asset		(480	)		—			(480	)
Noncurrent deferred tax liability	$	(480	)	$	(27,013	)	$	(27,493	)

	December 31, 2010
	U.S.			Foreign			Total
Deferred tax asset:
Net operating loss carry forwards	$	215,174		$	178,882		$	394,056
Unrealized derivative loss		13,356			—			13,356
Alternative minimum tax credit		1,840			—			1,840
Stock-based compensation		5,064			211			5,275
Asset retirement obligation		10,918			—			10,918
Other		572			—			572
Valuation allowance		(97,385	)		(1,676	)		(99,061	)
Deferred tax asset		149,539			177,417			326,956
Deferred tax liability:
Oil and gas property basis differences		(143,431	)		(186,182	)		(329,613	)
Other		(6,108	)		—			(6,108	)
Deferred tax liability		(149,539	)		(186,182	)		(335,721	)
Net deferred tax liability		—			(8,765	)		(8,765	)
Less net current deferred tax asset		(8,191	)		—			(8,191	)
Noncurrent deferred tax liability	$	(8,191	)	$	(8,765	)	$	(16,956	)

We compute income taxes using an asset and liability approach which results in the recognition of deferred tax liabilities and assets for the expected future tax consequences of temporary differences between the carrying amounts and the tax basis of those assets and liabilities. As of December 31, 2011 and 2010, for U.S. tax provision purposes, we have provided valuation allowance for that portion of excess tax benefits resulting from stock options and restricted stock outstanding as of the date we adopted the accounting standards for stock-based compensation. Beginning December 31, 2010, for U.S. tax provision purposes, we have also provided valuation allowance for the remainder of our net deferred tax assets based on our cumulative net losses. Additionally, the deferred tax asset related to the U.S. net operating loss carry forwards ("NOLs") as disclosed does not include an additional $19.9 million of net operating loss, as reflected in our U.S. Income Tax Return and net operating loss carry forwards in relation to excess tax benefits on stock option exercises and restricted stock vested through the fiscal year ended December 31, 2011.

No tax expense is provided on the income attributable to the redeemable noncontrolling interest in ATP Infrastructure Partners, LP, as the partnership is a pass-through entity and is not subject to federal income taxes. Taxes attributable to the income of the redeemable noncontrolling interest would be the liability of the ultimate taxpayers owning that interest.

At December 31, 2011 and 2010, we had U.S. net operating loss carry forwards ("NOLs") for financial statement purposes of approximately $545.3 million and $614.8 million, respectively, which begin to expire in 2024. ATP (UK) had NOLs of $936.8 million and $678.5 million available for corporate tax carry-forward at December 31, 2011 and 2010, respectively, which are presented in Foreign Operations above. As of December 31, 2011 we have a net current deferred tax asset of approximately $0.5 million, which is primarily attributable to bad debt reserve and unrealized hedging losses.

The U.K. supplementary charge of corporation tax was increased from 20% to 32%, effective March 24, 2011, and Royal Assent was received on July 19, 2011. The U.K. rate increase has been reflected in the income tax provision as of December 31, 2011. All U.K. deferred tax assets and liabilities subject to the supplementary charge of corporation tax have been updated to reflect the 32% rate as of December 31, 2011.

At December 31, 2011 and 2010, for Netherlands' income tax provision purposes, we had a valuation allowance of $4.9 million and $1.7 million, respectively, related to the net operating loss carryovers generated in 2011 and in prior periods. If activity, development and acquisitions increase within the Dutch sector, we will reevaluate this valuation allowance.

At December 31, 2011 for Israeli income tax provision purposes, we have a valuation allowance of $0.5 million related to the net operating loss carryover generated in 2011. Since 2012 will be the first year of active drilling and operations in this area, there is insufficient evidence of future taxable profits.

The Company and its subsidiaries file income tax returns in the United States federal jurisdiction, two states, the U.K., the Netherlands and Israel. Our open tax years in our major jurisdictions are from 2003 to current. As of December 31, 2011, we are not aware of any uncertain tax positions requiring adjustments to our tax liability. If applicable, we will record to the income tax provision any interest and penalties related to unrecognized tax positions.

U.S. deferred taxes have not been recognized with respect to foreign income of $54.4 million that is permanently reinvested internationally. We currently do not have any foreign tax credits available to reduce U.S. taxes on this income if it was repatriated.

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Other Long-Term Obligations

12 Months Ended

Dec. 31, 2011

Other Long-Term Obligations [Abstract]

Other Long-Term Obligations

Note 7 — Other Long-term Obligations

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

	December 31,
	2011			2010
Net profits interests	$	336,669		$	331,776
Dollar-denominated overriding royalty interests		42,324			52,825
Gomez pipeline obligation		71,676			73,868
Vendor deferrals – Gulf of Mexico		17,493			7,096
Vendor deferrals – North Sea		94,710			90,874
Other		2,582			2,582
Total		565,454			559,021
Less current maturities		(113,657	)		(86,521	)
Other long-term obligations	$	451,797		$	472,500

Net Profits Interests – Beginning in 2009, we have granted dollar-denominated overriding royalty interests in the form of net profits interests ("NPIs") in certain of our proved oil and gas properties in and around the Telemark Hub, Gomez Hub and Clipper to certain of our vendors in exchange for oil and gas property development services and to certain finance entities in exchange for cash proceeds. During April 2011, we closed an NPI transaction in the Telemark Hub for $40.0 million. The purchaser acquired an existing vendor NPI for $19.7 million, thereby extinguishing the existing NPI liability of $20.8 million, and contributed an additional $20.3 million toward the development of the Telemark Hub in exchange for a larger percentage of the net profits from production at the Telemark Hub that will continue until the purchaser recovers $40.0 million, plus an overall rate of return.

The interests granted are paid solely from the net profits, as defined, of the subject properties. As the net profits increase or decrease, primarily through higher or lower production levels and higher or lower prices of oil and natural gas, the payments due the holders of the net profits interests increase or decrease accordingly. If there is no production from a property or if the net profits are negative during a payment period, no payment would be required. We also accrete the liability over the estimated term in which the NPI is expected to be settled using the effective interest method with related interest expense presented net of amounts capitalized on the Consolidated Statements of Operations. The term of the NPIs is dependent on the value of the services contributed by these vendors or the cash proceeds contributed by the finance companies coupled with the timing of production and future economic conditions, including commodity prices and operating costs. Upon recovery of the agreed rate of return, the NPIs terminate. Because NPIs were granted on proved properties where production is reasonably assured, we have accounted for these NPI's as financing obligations on our Consolidated Balance Sheets. As such, the reserves and production revenues associated with the NPIs are retained by the Company. We expect approximately 60%, or $205 million of the NPIs to be repaid over the next 12 months based on anticipated production, commodity prices and operating costs.

Dollar-denominated Overriding Royalty Interests – During April, June and December 2011, we sold, for an aggregate of $65.0 million, three dollar-denominated overriding royalty interests ("Overrides") in our Gomez Hub properties similar to those sold in 2009 and 2010. These Overrides obligate us to deliver proceeds from the future sale of hydrocarbons in the specified proved properties until the purchasers achieve a specified return. As the proceeds from the sale of hydrocarbons increase or decrease, primarily through changes in production levels and oil and natural gas prices, the payments due the holders of the overriding royalty interests will increase or decrease accordingly. If there is no production from a property during a payment period, no payment would be required. The percentage of property revenues available to satisfy these obligations is dependent upon certain conditions specified in the agreement. Upon recovery of the agreed rate of return, the Overrides terminate and our interest increases accordingly. Because of the explicit rate of return, dollar-denomination and limited payment terms of the Overrides, they are reflected in the accompanying financial statements as financing obligations. As such, the reserves and production revenues are retained by the Company. Related interest expense is presented net of amounts capitalized on the Consolidated Statements of Operations. As of December 31, 2011, if there is sufficient production from a certain property, we will incur up to $7.2 million of contingent interest costs. We expect approximately 93%, or $39 million of the Overrides to be repaid over the next 12 months based on anticipated production and commodity prices.

Gomez Pipeline Obligation – In 2009, we sold to a third party for net proceeds of $74.5 million the oil and natural gas pipelines that service the Gomez Hub. In conjunction with the sale, we entered into agreements with the purchaser to transport our oil and natural gas production for the remaining production life of our fields serviced by the ATP Innovator production platform 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 ATP in future periods within the same calendar year whenever fees owed during a month exceed the minimum due. We remain the operator of the pipeline and are responsible for all of the related operating costs. As a result of the retained asset retirement obligation and the purchaser's option to convey the pipeline back to us at the end of the life of the fields in the Gomez Hub, the transaction has been accounted for as a financing obligation equal to the net proceeds received. This obligation is being amortized based on the estimated proved reserve life of the Gomez Hub properties using the effective interest method with related interest expense presented net of amounts capitalized on the Consolidated Statements of Operations. All payments made in excess of the minimum fee in future periods will be reflected as interest expense of the financing obligation.

Vendor Deferrals – In the Gulf of Mexico, in addition to the NPIs exchanged for development services described above, we have negotiated with certain other vendors involved in the development of the Telemark and Gomez Hubs to partially defer payments over a twelve-month period beginning with first production. We accrue the present value of the deferred payments and accrete the balance over the estimated term in which it is expected to be paid using the effective interest method with related interest expense presented net of amounts capitalized, on the Consolidated Statements of Operations.

In the U.K. North Sea, development of our interest in the Cheviot field continues. During February 2012, we entered into an amendment to one of our agreements for the construction and delivery of the Octabuoy hull and topside utility module to align the payments with the new expected delivery date of hull. As amended, the agreements provide for a $41.1 million payment in the first quarter of 2012 and $228.9 million in 2013. As work is completed and amounts are earned under the amended agreement, we record obligations and related interest expense, net of amounts capitalized, on the Consolidated Financial Statements.

Effective Interest Rate – The weighted average effective interest rate on our other long-term obligations set forth above was 18.9% and 16.7% at December 31, 2011 and 2010, respectively.

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Oil And Gas Properties

12 Months Ended

Dec. 31, 2011

Oil And Gas Properties [Abstract]

Oil And Gas Properties

Note 5 — Oil and Gas Properties

Acquisitions

During June 2011, we acquired interests in three deepwater licenses in the Mediterranean Sea off the coast of Israel for approximately $1.7 million. We will operate the licenses with initial working interests of 40%. During November and December 2011, we acquired an aggregate additional 45% interest in GC 300 at our Clipper property from partners in the project. We now operate that property with a 100% working interest.

Dispositions

During December 2011, we sold to a third party our 100% working interest in the deep operating rights of one of our Gulf of Mexico properties resulting in a $26.0 million gain.

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Long-Term Debt

12 Months Ended

Dec. 31, 2011

Long-Term Debt [Abstract]

Long-Term Debt

Note 6 — Long-term Debt

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

	December 31,
	2011			2010
First lien term loans, net of unamortized discount of $2,460 and $2,644, respectively,	$	204,703		$	146,607
Senior second lien notes, net of unamortized discount of $4,671 and $6,071, respectively,		1,495,329			1,493,929
Term loan facility – ATP Titan assets, net of unamortized discount of $16,373 and $10,760, respectively,		309,973			238,873
Total debt		2,010,005			1,879,409
Less current maturities		(33,848	)		(21,625	)
Total long-term debt	$	1,976,157		$	1,857,784

Senior Second Lien Notes

In April 2010, we issued senior second lien notes (the "Notes") in an aggregate principal amount of $1.5 billion, due May 1, 2015. The Notes bear interest at an annual rate of 11.875%, payable each May 1 and November 1, and contain restrictions that, among other things, limit the incurrence of additional indebtedness, mergers and consolidations, and certain restricted payments.

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

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

First Lien Term Loans

In June 2010, we entered into a first lien credit agreement (the "Credit Facility") with an initial balance of $150.0 million, due October 15, 2014, to replace the previous credit facility. Initial proceeds of the Credit Facility were $144.3 million, net of original issue discount and transaction fees. Principal outstanding under the term loans issued pursuant to the Credit Facility initially bore interest at an annual rate of 11.0%. The Company granted the lenders a security interest in and a first lien on not less than 80% of its proved oil and gas reserves in the Gulf of Mexico, capital stock of material subsidiaries (limited in the case of the Company's non-U.S. subsidiaries to not more than 65% of the capital stock) and certain infrastructure assets, a portion of which has since been released in connection with the ATP Titan LLC financing discussed below. In February 2011, we entered into Incremental Loan Assumption Agreement and Amendment No. 1, relating to our First Lien Credit Agreement, dated as of June 18, 2010 to, among other things, decrease the interest rate on the entire balance outstanding from 11% to 9%. Additional borrowings were $60.0 million ($58.0 million, net of transaction costs and discount). Quarterly principal payments are required equal to ¹/2% of remaining principal balance until June 18, 2014 and the remaining principal balance is due January 15, 2015.

The Notes and Credit Facility contain certain negative covenants which place limits on the Company's ability to, among other things:

• incur additional indebtedness;

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

• make investments outside of our normal course of business;

• incur liens;

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

• engage in transactions with affiliates;

• sell assets; and

• consolidate, merge or transfer assets.

Term Loan Facility — ATP Titan Assets

In September 2010, we formed ATP Titan LLC ("Titan LLC"), a wholly owned and operated subsidiary which we consolidate in our financial statements, and transferred to it our 100% ownership of the ATP Titan platform and related infrastructure assets. Simultaneous with the transfer, Titan LLC entered into a $350.0 million term loan facility (the "ATP Titan Facility"). Under the initial agreement and the First and Second Amendments to Term Loan Agreement and Limited Waivers entered into in March and September 2011, respectively, we have now drawn down the entire amount available receiving proceeds of $317.9 million, net of discount and direct issuance costs. The ATP Titan Facility bears interest at LIBOR (floor of 0.75%) plus 8%. Principal payments are required equal to 2.25% (of original principal) per quarter until October 4, 2012, and 2.5% thereafter until final maturity at September 2017. The ATP Titan Facility requires us to maintain in a restricted account a minimum $10.0 million cash balance plus additional amounts based on production at the Telemark Hub to be used for the quarterly debt service of the ATP Titan Facility. The ATP Titan Facility is collateralized solely by the ATP Titan and related infrastructure assets (net book value at December 31, 2011 of $1,105.9 million) and the outstanding member interests in Titan LLC, which are all owned indirectly by the Company. The ATP Titan Facility includes a customary condition that there has not occurred a material adverse change with respect to the Company. The Company remains operator and 100% owner of the ATP Titan platform, related infrastructure assets and the working interest in its Telemark Hub oil and gas reserves.

The Credit Facility and the Notes contain customary events of default, and if certain of those events of default were to occur and remain uncured, such as a failure to pay principal or interest when due, our lenders could terminate future lending commitments under the Credit Facility, and our lenders could declare the outstanding borrowings due and payable. The Credit Facility also contains an event of default if there has occurred a material adverse change with respect to the Company's compliance with environmental requirements and applicable laws and regulations. The ATP Titan Facility contains standard events of default and an event of default if there has occurred a material adverse change with respect to the Company. The ATP Titan Facility also contains provisions that provide for cross defaults among the documents entered into in connection with the ATP Titan Facility and acceleration of Titan LLC's payment obligations under the ATP Titan Facility in certain situations. In addition, our hedging arrangements contain standard events of default, including cross default provisions, that, upon a default, provide for (i) the delivery of additional collateral, (ii) the termination and acceleration of the hedge, (iii) the suspension of the lenders' obligations under the hedging arrangement or (iv) the setoff of payment obligations owed between the parties.

The effective annual interest rate and fair value of our long-term debt was 12.0% and $1.5 billion, respectively, at December 31, 2011. Accrued interest payable was $37.7 million and $34.8 million at December 31, 2011 and 2010, respectively.

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Equity

12 Months Ended

Dec. 31, 2011

Equity [Abstract]

Equity

Note 8 — Equity

Preferred Stock

In September 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). In June 2011, we issued 1.7 million shares of 8% convertible perpetual preferred stock ("Series B Preferred Stock") and received net proceeds of $123.3 million ($90 per share before underwriters' discounts and commissions, option contract costs (discussed below) and offering expenses). The Series B Preferred Stock has terms and features which are substantially identical to the convertible preferred stock issued in 2009 (collectively, the "Preferred Stock"). Each share of convertible preferred stock is perpetual, has no voting rights, has a liquidation preference of $100, pays cumulative dividends at an annual rate of 8% payable in cash, shares of our common stock, or a combination thereof, 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 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 dilution and would receive a conversion benefit as defined in the related statement of resolutions that established the convertible preferred stock. In December 2011, we announced a quarterly cash dividend of $6.3 million ($2.02 per share of preferred stock) which was paid in January 2012.

In conjunction with issuance of the Series B Preferred Stock, we purchased for $26.5 million capped-call options ("Options") to cover all 14.1 million shares of common stock issuable upon conversion of the Series B Preferred Stock and the preferred stock we issued in 2009. The Options allow us to prevent dilution due to common stock issuance upon preferred stock conversion up to a price per common share of $27.50. The shares of common stock acquirable under the Options are indexed to our common stock price at the time of exercise and the Options can only be settled in common stock. As a result, the purchase price of the Options is recorded as a component of additional paid-in capital within Shareholders' Equity in the accompanying Consolidated Financial Statements.

At December 31, 2011, a portion of the Series B Preferred Stock is classified as temporary equity because, in the event of certain fundamental changes, as defined in the statement of resolutions, the Company could be required to issue in the aggregate more shares of common stock pursuant to the conversion ratio most favorable to the holders than currently are authorized and unissued (the "Common Share Shortfall"). The value of the temporary equity is deemed to be the number of shares of Preferred Stock that would account for such common share shortfall times the $86.83 fair value per share (net of issuance costs of $3.17 per share). This amount is revalued in each reporting period as the Common Share Shortfall changes, and at such time as we have sufficient authorized and unissued common shares to satisfy the most favorable conversion obligation possible under the statement of resolutions, this amount will be reclassified to permanent equity.

Common Stock

During 2009, we issued 14.6 million shares of common stock and received net proceeds of $170.6 million (an average of $12.31 per share before underwriters' discounts and commissions and offering expenses).

Rights Plan

On October 1, 2005, the Board of Directors of ATP authorized the issuance of one preferred share purchase right (a "Right") with respect to each outstanding share of common stock, par value $0.001 per share (the "Common Shares"), of the Company (the "Shareholder Rights Plan"). The Rights were issued on October 17, 2005 to the holders of record of Common Shares on that date. Each Right entitles the registered holder to purchase from the Company one one-hundredth (1/100) of a share of Junior Participating Preferred Stock, par value $0.001 per share (the "Preferred Shares"), of the Company at a price of $150 per one one-hundredth of a Preferred Share, subject to adjustment. The description and terms of the Rights are set forth in a Rights Agreement dated as of October 11, 2005 between the Company and American Stock Transfer & Trust Company, as Rights Agent.

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Derivative Instruments And Price Risk Management Activities

12 Months Ended

Dec. 31, 2011

Derivative Instruments And Price Risk Management Activities [Abstract]

Derivative Instruments And Price Risk Management Activities

Note 13 — Derivative Instruments and Price Risk Management Activities

At December 31, 2011, we had the following derivative contracts in place:

						Net Fair Value
						Asset (Liability) (1)
Period	Type	Volumes		Price		Current			Noncurrent
				$/Unit		($000)			($000)
Oil (Bbl) – Gulf of Mexico
2012	Swaps		3,408,250		95.87		(20,115	)		—
2013	Swaps		90,000		90.40		—			(522	)
2012	Prepaid Swaps (2)		476,950		—		(48,424	)		—
Total							(68,539	)		(522	)
Natural Gas (MMBtu)
North Sea
2012	Swaps		1,646,000		8.48		(213	)		—
Gulf of Mexico
2012	Calls (3)		3,660,000		5.35		(64	)		—
2012	Fixed-price physicals		1,365,000		4.64		2,194			—
Total							1,917			—
Total asset							2,194			—
Total liability							(68,816	)		(522	)
Total							(66,622	)		(522	)

(1) None of the derivatives outstanding is designated as a hedge for accounting purposes.

(2) In order to manage our exposure to oil price volatility and provide a current source of financing, in the second half of 2011, we entered into certain off-market oil swap derivative contracts which provide us with $87.9 million of cash advances from the counterparty and obligate us to pay market prices at the time of settlement.

(3) During the first quarter of 2011, we sold U.S. gas call options and received premiums of $2.1 million.

At December 31, 2010, we had the following derivative contracts in place:

					Net Fair Value
					Asset (Liability) (2)
Period	Type	Volumes		Price	Current			Noncurrent
				$/Unit (1)	($000)			($000)
Oil (Bbl) – Gulf of Mexico
2011	Swaps		2,124,500	81.99		(23,084	)		—
2012	Swaps		1,120,750	89.37		—			(4,236	)
2013	Swaps		90,000	90.40		—			(199	)
2011	Swaps (3)		911,000	78.41		(12,027	)		—
Total					$	(35,111	)	$	(4,435	)
Natural Gas (MMBtu)
North Sea
2011	Swaps		1,641,000	7.21		(2,782	)		—
2012	Swaps		1,464,000	8.20		—			(1,249	)
Gulf of Mexico
2011	Fixed-price physicals		5,025,000	4.78		1,030			—
2012	Fixed-price physicals		1,365,000	4.64		—			(741	)
2011	Collars		1,350,000	4.75-7.95		658			—
Total					$	(1,094	)	$	(1,990	)
Derivative asset					$	1,688		$	—
Derivative liability						(37,893	)		(6,425	)
Total					$	(36,205	)	$	(6,425	)

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

(2) None of the derivatives outstanding is designated as a hedge for accounting purposes.

(3) These swaps include call options to allow us to participate in per barrel price increases above $111.00.

During the first quarter of 2011, we sold certain natural gas call options in exchange for a premium from the counterparties. At settlement of a call option, if the market price exceeds the strike price of the call option, the Company pays the counterparty such excess. If the market price settles below the strike price of the call option, no payment is due from either party. Cash settlements of our derivative instruments are classified as operating cash flows unless the derivative contains a significant financing element at contract inception, in which case these cash settlements are classified as financing cash flows in the accompanying Consolidated Statements of Cash Flows.

There was no other comprehensive income related to hedges during 2011 or 2010. The following AOCI table shows where gains, net of taxes, on cash flow hedge derivatives were reported in the year ended December 31, 2009 (in thousands):

AOCI for cash flow hedges – December 31, 2008	$	(2,877	)
Derivative gains		3,736
Gains reclassified from AOCI to oil and gas revenues		(859	)
AOCI for cash flow hedges – December 31, 2009	$	—

During the year ended December 31, 2011, we paid net cash settlements of $13.0 million related to our derivatives. Additional information about derivatives is presented in Note 15 "Fair Value Measurements". Our derivative income (expense) is based entirely on nondesignated derivatives and consists of the following (in thousands):

	Year Ended December 31,
	2011			2010			2009
Realized gains (losses) from:
Settlements of contracts	$	(23,317	)	$	(2,686	)	$	18,335
Early terminations of contracts		10,700			—			19,226
Unrealized gains (losses) on open contracts		37,808			(19,733	)		(38,273	)
Derivative income (expense)	$	25,191		$	(22,419	)	$	(712	)

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Schedule I - Parent Company Financial Statements

12 Months Ended

Dec. 31, 2011

Schedule I - Parent Company Financial Statements [Abstract]

Schedule I - Parent Company Financial Statements

SCHEDULE I — PARENT COMPANY FINANCIAL STATEMENTS

ATP OIL & GAS CORPORATION

UNCONSOLIDATED BALANCE SHEETS OF REGISTRANT

(In Thousands, Except Share Amounts)

	December 31,
	2011			2010
Assets
Current assets:
Cash and cash equivalents	$	48,106		$	124,047
Restricted cash		4,839			—
Accounts receivable (net of allowance of $225 and $291, respectively)		64,980			69,660
Accounts receivable – intercompany		—			—
Deferred tax asset		480			8,191
Derivative asset		2,194			1,688
Other current assets		25,558			22,735
Total current assets		146,157			226,321
Oil and gas properties (using the successful efforts method of accounting):
Proved properties		2,691,609			2,325,507
Unproved properties		10,711			9,249
		2,702,320			2,334,756
Less accumulated depletion, depreciation, impairment and amortization		(1,423,859	)		(1,157,412	)
Oil and gas properties, net		1,278,461			1,177,344
Deferred financing costs, net		30,732			38,897
Investment in and advance to subsidiaries		1,034,671			1,193,462
Notes receivable – intercompany		290,470			93,280
Other assets, net		12,832			12,504
Total assets	$	2,793,323		$	2,741,808
Liabilities and Equity
Current liabilities:
Accounts payable and accruals	$	227,933		$	176,843
Accounts payable – intercompany		12,038			3,119
Current maturities of long-term debt		2,066			1,500
Asset retirement obligation		44,577			40,472
Derivative liability		68,778			35,581
Other current liabilities		72,541			32,959
Total current liabilities		427,933			290,474
Long-term debt		1,697,966			1,639,036
Other long-term obligations		398,203			431,626
Asset retirement obligation		101,831			115,017
Deferred tax liability		480			8,191
Derivative liability		521			5,478
Deferred revenue		—			—
Total liabilities		2,626,934			2,489,822
Commitments and contingencies (Note 12, Notes to Consolidated Financial Statements in Part II, Item 8)
Temporary equity:
8% convertible perpetual preferred stock: $0.001 par value; 806,847 issued and outstanding at December 31, 2011; None issued and outstanding at December 31, 2010. Liquidation value of $80.7 million		70,055			—
Shareholders' equity:
8% convertible perpetual preferred stock: $0.001 par value, 10,000,000 shares authorized; 2,318,153 issued and outstanding at December 31, 2011; 1,400,000 issued and outstanding at December 31, 2010. Liquidation value of $231.8 million and $140.0 million at December 31, 2011 and 2010, respectively		222,681			140,000
Common stock: $0.001 par value, 100,000,000 shares authorized; 52,034,547 issued and 51,958,707 outstanding at December 31, 2011; 51,347,163 issued and 51,271,323 outstanding at December 31, 2010		52			51
Additional paid-in capital		529,669			570,739
Accumulated deficit		(548,765	)		(356,866	)
Accumulated other comprehensive loss		(106,392	)		(101,027	)
Treasury stock, at cost		(911	)		(911	)
Total shareholders' equity		96,334			251,986
Total liabilities and equity	$	2,793,323		$	2,741,808

See notes to unconsolidated financial statements of registrant.

ATP OIL & GAS CORPORATION

UNCONSOLIDATED STATEMENTS OF OPERATIONS OF REGISTRANT

(In Thousands)

	Year Ended December 31,
	2011			2010			2009
Revenues:
Oil and gas production	$	668,184		$	416,836		$	281,460
Other		—			—			13,664
		668,184			416,836			295,124
Costs, operating expenses and other:
Lease operating		116,792			126,394			74,973
Processing costs – intercompany		98,059			58,031			32,937
Exploration		1,034			1,165			233
General and administrative		36,274			42,085			41,397
Depreciation, depletion and amortization		210,248			179,042			121,125
Impairment of oil and gas properties		56,400			48,392			45,799
Accretion of asset retirement obligation		12,903			12,466			10,441
Drilling interruption costs		19,691			23,647			—
Loss on abandonment		3,916			4,829			2,872
Gain on exchange/disposal of properties		(27,000	)		(26,720	)		(13,177	)
Other, net		(2	)		(948	)		(743	)
		528,315			468,383			315,857
Income (loss) from operations		139,869			(51,547	)		(20,733	)
Other income (expense):
Interest income		—			236			16
Interest expense, net		(299,351	)		(221,808	)		(45,955	)
Derivative income (expense)		23,372			(16,253	)		(9,834	)
Loss on debt extinguishment		1,095			(75,316	)		—
Equity in subsidiary earnings, net of tax		(56,884	)		3,116			8,660
		(331,768	)		(310,025	)		(47,113	)
Loss before income taxes		(191,899	)		(361,572	)		(67,846	)
Income tax (expense) benefit:
Current		—			924			(924	)
Deferred		—			23,099			19,809
		—			24,023			18,885
Net loss		(191,899	)		(337,549	)		(48,961	)
Less convertible preferred stock dividends		(18,583	)		(11,248	)		(2,856	)
Net loss attributable to common shareholders	$	(210,482	)	$	(348,797	)	$	(51,817	)

See notes to unconsolidated financial statements of registrant.

ATP OIL & GAS CORPORATION

UNCONSOLIDATED STATEMENTS OF CASH FLOWS OF REGISTRANT

(In Thousands)

	Year Ended December 31,
	2011			2010			2009
Net cash provided by (used in) operating activities	$	113,648		$	(100,773	)	$	162,309
Cash flows from investing activities
Additions to oil and gas properties		(234,861	)		(534,295	)		(551,555	)
Proceeds from disposition of properties		27,000			17,053			13,000
Increase in restricted cash		(4,841	)		—			—
Distributions from subsidiaries		109,419			218,790			144,271
Net cash used in investing activities		(103,283	)		(298,452	)		(394,284	)
Cash flows from financing activities
Proceeds from senior second lien notes		—			1,492,965			—
Proceeds from first lien term loans		59,400			147,000			—
Proceeds from term loans		—			46,000			19,000
Payments of term loans		(2,087	)		(1,263,360	)		(176,511	)
Deferred financing costs		(1,561	)		(53,017	)		(6,490	)
Loans to subsidiaries		(213,758	)		(68,116	)		(157,680	)
Payments from subsidiary loans		16,569			16,494			146,105
Issuance of common stock, net of costs		—			—			170,629
Issuance of preferred stock, net of costs		149,866			—			135,549
Purchase of capped-call options on ATP common stock		(26,500	)		—			—
Proceeds from other long-term obligations		85,326			231,888			89,011
Payments of other long-term obligations		(163,364	)		(102,818	)		(2,298	)
Preferred stock dividends		(15,098	)		(11,276	)		—
Derivative contracts, net		67,129			—			—
Other financings, net		(42,433	)		(11,180	)		—
Exercise of stock options/warrants		205			3,609			3
Net cash provided by (used in) financing activities		(86,306	)		428,189			217,318
Increase (decrease) in cash and cash equivalents		(75,941	)		28,964			(14,657	)
Cash and cash equivalents, beginning of year		124,047			95,083			109,740
Cash and cash equivalents, end of year	$	48,106		$	124,047		$	95,083

See notes to unconsolidated financial statements of registrant.

ATP OIL & GAS CORPORATION

NOTES TO UNCONSOLIDATED FINANCIAL STATEMENTS OF REGISTRANT

Note 1 — Basis of Presentation

The financial statements of ATP Oil & Gas Corporation (the "Registrant" or "Parent Company") have been prepared pursuant to Rule 5-04 of Regulation S-X of the Securities Exchange Act of 1934, as amended, because certain of ATP's subsidiaries are contractually prohibited from making payments, loans or transferring assets to the Parent Company or other affiliated entities. Specifically, under the terms of our ATP Titan facility, ATP Titan, LLC is restricted from transferring assets or making dividends in excess of one quarter's debt service plus $10.0 million at any time. Additionally, ATP-IP is prohibited from making distributions to ATP Oil & Gas Corporation other than those specifically provided for in the Partnership Agreement. The restricted net assets associated with each of these entities exceed 25% of the consolidated net assets of ATP Oil & Gas Corporation as of December 31, 2011 and 2010.

For purposes of these financial statements, the Parent Company's investments in wholly owned subsidiaries are accounted for under the equity method. Under this method, the accounts of the subsidiaries are not consolidated. The investments in and advances to subsidiaries are recorded in the unconsolidated balance sheets. The income (loss) from operations of subsidiaries is reported on an equity basis as equity in subsidiary earnings, net of tax, in the unconsolidated statements of operations of registrant. These statements should be read in conjunction with the consolidated financial statements and notes thereto, included in Part II, Item 8 of in this Annual Report on Form 10-K.

Note 2 — Notes Receivable — Intercompany

Notes receivable – intercompany represents cumulative net advances to ATP Oil & Gas (UK) Limited and ATP Oil & Gas (Netherlands) B.V. that are subject to intercompany loan agreements (the "Notes"). The Notes provide for borrowings to each subsidiary on a revolving basis of up to $800.0 million. Outstanding balances bear interest at the same rate of interest as the principal borrowings of ATP Oil & Gas Corporation, which at December 31, 2011 was 11.875%. The Notes mature on June 27, 2018.

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Consolidated Statements Of Comprehensive Income (Loss) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Consolidated Statements Of Comprehensive Income (Loss) [Abstract]
Net loss	$ (165,277)	$ (322,046)	$ (35,581)
Other comprehensive income (loss):
Reclassification adjustment for settled hedge contracts (net of taxes of $0, $0 and $859, respectively)			(859)
Change in fair value of outstanding hedge positions (net of taxes of $0, $0 and ($3,736), respectively)			3,736
Foreign currency translation adjustment, net of tax	(5,365)	(5,540)	14,390
Other comprehensive income (loss)	(5,365)	(5,540)	17,267
Comprehensive loss	(170,642)	(327,586)	(18,314)
Less income attributable to the redeemable noncontrolling interest	(26,622)	(15,503)	(13,380)
Less convertible preferred stock dividends	(18,583)	(11,248)	(2,856)
Comprehensive loss attributable to common shareholders	$ (215,847)	$ (354,337)	$ (34,550)

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Summary Of Significant Accounting Policies

12 Months Ended

Dec. 31, 2011

Summary Of Significant Accounting Policies [Abstract]

Summary Of Significant Accounting Policies

Note 2 — Summary of Significant Accounting Policies

Use of Estimates

The preparation of financial statements in accordance with U.S. generally accepted accounting principles and pursuant to the rules and regulations of the SEC requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and disclosure of contingent assets and liabilities in the financial statements. Actual results could differ from those estimates.

Cash and Cash Equivalents

Cash and cash equivalents primarily consist of cash on deposit and investments in funds with original maturities of three months or less, stated at market value.

Restricted Cash

Restricted cash relates to an escrow account for ATP-IP, discussed below, which holds cash in excess of monthly partnership distributions and operating needs. Also, the ATP Titan Facility, discussed below, requires us to maintain in a restricted account a minimum $10.0 million cash balance (classified as noncurrent on the Consolidated Balance Sheet) plus additional amounts based on production at the Telemark Hub to be used for the quarterly debt service of the ATP Titan Facility. Occasionally, we also receive cash which is restricted for use to retire certain assets or perform other operations.

Oil and Gas Properties

We account for our oil and gas property costs using the successful efforts accounting method. Under the successful efforts method, lease acquisition costs and intangible drilling and development costs on successful wells and development dry holes are capitalized. Costs of drilling exploratory wells are initially capitalized, but charged to expense if and when a well is determined to be unsuccessful.

Capitalized proved property acquisition costs are depleted on the unit-of-production method on the basis of total estimated units of proved reserves. Capitalized costs relating to producing properties are depleted on the unit-of-production method on the basis of total estimated units of proved developed reserves. When significant development costs (such as the cost of an offshore production platform) are incurred in connection with a planned group of development wells before all of the planned wells have been drilled, it is occasionally necessary to exclude a portion of those development costs in determining the unit-of-production depletion rate until the additional development wells are drilled. However, in no case are future development costs anticipated in computing our depletion rate. Estimated dismantlement, restoration and abandonment costs and estimated residual salvage values are taken into account in determining depletion provisions. Our ATP Titan and ATP Innovator floating platforms are included in oil and gas properties and depreciated straight line over 40 and 25 years, respectively since they can be relocated to other fields once existing production is depleted. Expenditures for geological and geophysical testing costs are generally charged to expense unless the costs can be specifically attributed to mapping a proved reservoir and determining the optimal placement for future developmental well locations. Expenditures for repairs and maintenance are charged to expense as incurred; renewals and betterments are capitalized. The costs and related accumulated depreciation, depletion, and amortization of properties sold or otherwise retired are eliminated from the accounts, and gains or losses on disposition are reflected in the statements of operations.

We perform impairment analysis whenever events or changes in circumstances indicate that an asset's carrying amount may not be recoverable. To determine if a depletable unit is impaired, we compare the carrying value of the depletable unit to the undiscounted future net cash flows by applying management's estimates of future oil and gas prices to the estimated future production of oil and gas reserves over the economic life of the property and deducting future costs. Future net cash flows are based upon reservoir engineers' estimates of proved reserves. In addition, other factors such as probable and possible reserves are taken into consideration when justified by economic conditions and actual or planned drilling or other development activities. For a property determined to be impaired, an impairment loss equal to the difference between the carrying value and the estimated fair value of the impaired property will be recognized. Fair value, on a depletable unit basis, is estimated to be the present value of the aforementioned expected future net cash flows. Unproved properties are assessed periodically to determine whether they have been impaired. An impairment allowance is provided on an unproved property when we determine that the property will not be developed, but no later than lease expiration. Any impairment charge incurred is recorded in accumulated depletion, depreciation, impairment and amortization to reduce our basis in the asset. Each part of these calculations is subject to a large degree of judgment, including estimated reserves, future net cash flows and fair value.

We recorded impairments during the years ended December 31, 2011, 2010 and 2009 totaling $53.0 million, $42.4 million and $44.6 million, respectively, on certain proved properties in the Gulf of Mexico. We also recorded impairments totaling $1.2 million and $14.9 million during 2011 and 2010, respectively on certain proved properties in the North Sea. The 2011 and 2010 impairments were primarily due to updated performance history. The 2009 impairments were primarily a result of reduced commodity prices and unfavorable operating performance.

Impairments of unproved properties were $3.4 million, $6.0 million and $1.2 million in 2011, 2010 and 2009, respectively, primarily related to surrendered leases in the Gulf of Mexico.

Management's assumptions used in calculating oil and gas reserves or regarding the future net cash flows or fair value of our properties are subject to change in the future. Any change could cause impairment expense to be recorded, impacting our net income or loss and our basis in the related asset. Any change in reserves directly impacts our estimate of future cash flows from the property, as well as the property's fair value. Additionally, as commodity price forecasts change, so too will the estimate of future net cash flows and the fair value estimates.

As of December 31, 2011, there were $9.7 million of capitalized exploratory well costs (suspended well costs) related to two wells in the North Sea which were still being evaluated, and for which drilling was completed in 2010. We are still performing our work program and completing studies that will allow us to calculate estimates of gas in place and potential reserves for Kilmar, part of our Tors development. In 2011, the only change in the suspended well costs was for additions of $0.2 million.

Asset Retirement Obligation

We recognize liabilities associated with the eventual retirement of tangible long-lived assets, upon the acquisition, construction and development of the assets. We record the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of the related long-lived asset. Changes in estimates on fully depleted properties are charged directly to loss on abandonment.

Shortages or an increase in cost of drilling rigs, equipment, supplies or personnel could delay or adversely affect our abandonment operations, which could have a material adverse effect on our business, financial condition and results of operations. Increased drilling activity in the Gulf of Mexico and the North Sea decreases the availability of offshore rigs and associated equipment. In periods of increased drilling activity in the Gulf of Mexico and the North Sea, we may experience increases in associated costs, including those related to drilling rigs, equipment, supplies and personnel and the services and products of other vendors to the industry. These costs may increase further and necessary equipment and services may not be available to us at economical prices.

We recognize (i) depletion expense on the additional capitalized asset retirement costs; (ii) accretion expense as the present value of the future asset retirement obligation increases with the passage of time, and; (iii) the impact, if any, of changes in estimates of the liability. The following table sets forth a reconciliation of the beginning and ending asset retirement obligation (in thousands):

	December 31,
	2011			2010			2009
Asset retirement obligation, beginning of year	$	166,858		$	150,199		$	132,108
Liabilities incurred		14,457			5,960			16,220
Liabilities settled		(26,725	)		(15,362	)		(9,603	)
Property dispositions		—			(242	)		(292	)
Accretion expense		15,000			13,827			11,676
Changes in estimates		(1,073	)		12,476			90
Total asset retirement obligation, end of year		168,517			166,858			150,199
Less current portion		(52,536	)		(43,386	)		(43,418	)
Total long-term asset retirement obligation, end of year	$	115,981		$	123,472		$	106,781

During 2011, 2010 and 2009, we recognized loss on abandonment of $3.9 million, $4.8 million and $2.9 million, respectively. These amounts are primarily the result of actual abandonment operations in the Gulf of Mexico requiring more work than originally estimated.

Limited Partnership

On March 6, 2009, along with GE Energy Financial Services ("GE"), we formed ATP-IP to own the ATP Innovator, the floating production facility that currently serves our Mississippi Canyon Block 711 Gomez Hub properties. We contributed the ATP Innovator in exchange for a 49% subordinated limited partner interest, a 2% general partner interest and cash. 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 the ATP Innovator during 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 the ATP 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 the ATP Innovator. ATP-IP pays us a monthly fee for certain administrative services we provide to the partnership.

We have entered a period under the agreements when all of the cash distributions from the partnership are paid to the Class A limited partner until such time as they have achieved the return of their invested capital plus a specified return. Once those amounts have been received by the Class A limited partner, all cash distributions will be made to the general partner and subordinated limited partner (ATP's interests) until specified amounts have been received. At the conclusion of the special distribution periods, all partners will again share in distributions proportionately according to their ownership in the partnership.

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 GE Class A limited partner interest is reflected as a noncontrolling interest in our consolidated financial statements. Under the provisions of our limited partnership agreement with ATP-IP, we could be required to repurchase the Class A limited partner interest if certain change of control events were to occur. If a change of control were to become probable in a future period, we would be required to adjust the carrying amount of the redeemable noncontrolling interest to its redemption amount, to the extent it differed from the carrying amount, at the time the change of control was deemed to be probable. We do not currently believe a change of control is probable.

Capitalized Interest

Interest costs during the construction phase of certain long-term assets are capitalized and amortized over the related assets' estimated useful lives. Interest expense capitalized during the last three years and the properties to which it relates is set forth in the following table (in thousands):

	Year Ended December 31,
	2011		2010		2009
ATP Titan – Telemark (Gulf of Mexico)	$	—	$	40,400	$	102,200
Octabuoy – Cheviot (North Sea)		29,246		12,900		7,900
Total capitalized interest	$	29,246	$	53,300	$	110,100

Deferred Financing Costs

Costs incurred in connection with the issuance of long-term debt and other obligations are capitalized and amortized to interest expense over the term of the related agreement, using the effective interest method.

Environmental Liabilities

Environmental liabilities are recognized when the expenditures are considered probable and can be reasonably estimated. Measurement of liabilities is based on currently enacted laws and regulations, existing technology and undiscounted site-specific costs. Generally, such recognition would coincide with a commitment to a formal plan of action. We have no accruals for such liabilities at December 31, 2011 or 2010.

Revenue Recognition

We use the sales method of accounting for oil and natural gas revenues. Under this method, revenues are recognized based on actual volumes of oil and gas sold to purchasers. The volumes sold may differ from the volumes to which we are entitled based on our interests in the properties. Differences between volumes sold and entitled volumes create oil and gas imbalances which are generally reflected as adjustments to reported proved oil and gas reserves and future cash flows in our supplemental oil and gas disclosures. If our excess takes of oil or natural gas exceed our estimated remaining proved reserves for a property, an oil or natural gas imbalance liability is recorded in the consolidated balance sheet.

Drilling Interruption Costs

Drilling interruption costs represent the costs we have incurred as a result of the deepwater drilling moratoriums and subsequent drilling permit delays caused by the April 2010 Deepwater Horizon incident in the Gulf of Mexico. During 2011, we incurred $19.7 million stand-by costs related to drilling operations at our Telemark and Gomez Hubs. During 2010 a side-track well operation in 7,000 feet of water was interrupted when the moratorium was imposed and work on that project stopped, resulting in the early termination of a drilling contract. In the course of obtaining a full release from our obligations under the contract, we incurred net costs of $8.7 million. Additionally, because the necessary deepwater drilling permits were not issued, drilling interruption costs during 2010 also include $14.9 million of stand-by costs related to drilling operations at our Telemark and Gomez Hubs.

Concentration of Credit Risk

We extend credit, primarily in the form of uncollateralized oil and gas sales and joint interest owners' receivables, to various companies in the oil and gas industry, which results in concentrations of credit risk. Concentrations of credit risk may be affected by changes in economic or other conditions within our industry and may accordingly impact our overall credit risk. However, we believe that the risk of these unsecured receivables is mitigated by the size, reputation, and nature of the companies to which we extend credit.

Major Customers

Historically, we have sold our oil and natural gas production to a relatively small number of purchasers. We are not dependent upon, or confined to, any one purchaser or small group of purchasers. Due to the nature of oil and natural gas markets and because oil and natural gas are commodities and there are numerous purchasers in the areas in which we sell production, we do not believe the loss of a single purchaser, or a few purchasers, would materially affect our ability to sell our production.

For the year ended December 31, 2011, revenues from two purchasers accounted for 67% and 20%, respectively, of oil and gas production revenues. For the year ended December 31, 2010, revenues from four purchasers accounted for 65%, 12%, 11% and 5%, respectively, of oil and gas production revenues. For the year ended December 31, 2009, revenues from four purchasers accounted for 39%, 33%, 13% and 7%, respectively, of oil and gas production revenues. A substantial portion of our oil and gas production revenues in the North Sea are from one customer.

Translation of Foreign Currencies

The local currency is the functional currency for our foreign subsidiaries, and as such, assets and liabilities are translated into U.S. dollars at year-end exchange rates. Income and expense items are translated at average exchange rates during the year. The gains or losses resulting from such translations are deferred and included in accumulated other comprehensive income as a separate component of shareholders' equity. Gains and losses arising from transactions denominated in a currency other than the functional currency of a particular entity are included in net income. At December 31, 2011, accumulated other comprehensive loss consisted of $106.4 million of loss related to cumulative foreign currency translation adjustments.

Insurance Recoveries

When realized, insurance recoveries under our loss of production income policy are reported as other revenues in the consolidated statements of operations and in cash flows from operating activities in the consolidated statements of cash flows. During 2009 insurance recoveries of $13.7 million were related to disruptions caused by Hurricane Ike in 2008.

Income Taxes

Income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences or benefits attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases and for operating loss and tax credit carry forwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes that enactment date. A valuation allowance is recorded to reduce deferred tax assets to an amount that management believes is more likely than not to be realized in future years.

Stock-based Compensation

We recognize stock-based compensation expense as vesting of the stock award occurs. Generally, restricted stock awards vest over three years and common stock option awards vest evenly over four years.

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.

Derivative Instruments

We utilize derivative instruments and fixed-price forward sales contracts with respect to a portion of our expected production in order to manage our exposure to oil and natural gas price volatility. These instruments expose us to risk of financial loss if:

• production is less than expected for forward sales contracts;

• the counterparty to the derivative instrument defaults on its contract obligations; or

• there is an adverse change in the expected differential between the underlying price in the derivative instrument and the actual prices received for our production at the physical sales point.

Our results of operations may be negatively impacted in the future by our derivative instruments and fixed-price forward sales contracts as these instruments may limit any benefit we would otherwise receive from increases in the prices for oil and natural gas.

We primarily utilize fixed-price physical forward contracts, price swaps, prepaid swaps, price collars and put and call 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 with changes in fair value recorded as a component of derivative income (expense) in our consolidated statement of operations. Cash settlements of our derivative instruments are classified as operating cash flows unless the derivative contains a significant financing element at contract inception, in which case these cash settlements are classified as financing cash flows in the accompanying Consolidated Statements of Cash Flows.

From time to time, we utilize foreign currency and interest rate derivative instruments to mitigate risks associated with our foreign operations and borrowings, respectively.

Recently Issued Accounting Pronouncements

In May 2011, the FASB issued guidance which will result in common fair value measurement and disclosure requirements in GAAP and International Financial Reporting Standards. For public entities, the guidance is effective for fiscal years, and interim periods within those years, beginning after December 15, 2011. We expect to adopt the provisions for the quarter ended March 31, 2012 and we do not anticipate that this will have a material impact on our financial position or results of operations.

In June 2011, the FASB issued guidance which eliminates the option to present components of other comprehensive income as part of the statement of changes in shareholders' equity and requires that all nonowner changes in shareholders' equity be presented either in a single continuous statement of comprehensive income or in two separate but consecutive statements. We have adopted the provisions of this standard at December 31, 2011 and it has not had a material impact on our financial statements.

In December 2011, the FASB deferred the provisions that relate to the presentation of reclassification adjustments. For public entities, the guidance is effective for fiscal years, and interim periods within those years, beginning after December 15, 2011.

In December 2011, the FASB issued guidance related to disclosure of information about offsetting and related arrangements for financial instruments and derivative instruments recognized as assets and liabilities. The guidance is effective for fiscal years and interim periods within those years, beginning after January 1, 2013. We expect to adopt the provisions for the quarter ending March 31, 2013 and we do not anticipate that this will have a material impact on our financial position or results of operations.

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Schedule II - Valuation And Qualifying Accounts

12 Months Ended

Dec. 31, 2011

Schedule II - Valuation And Qualifying Accounts [Abstract]

Schedule II - Valuation And Qualifying Accounts

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS

FOR EACH OF THE THREE YEARS ENDED DECEMBER 31, 2011

(In Thousands)

	Balance at Beginning of Period		Charged to Costs and Expenses		Charged to Other Accounts			Deduction			Balance at End of Period
2009
Allowance for doubtful accounts	$	352	$	86	$	—		$	(147	)	$	291
Valuation allowance on deferred tax assets		3,025		1,300		—			—			4,325
2010
Allowance for doubtful accounts		291		—		—			(66	)		225
Valuation allowance on deferred tax assets		4,325		94,835		(99	)		—			99,061
2011
Allowance for doubtful accounts		225		—		—			—			225
Valuation allowance on deferred tax assets		99,061		62,118		(319	)		—			160,860

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Commitments And Contingencies

12 Months Ended

Dec. 31, 2011

Commitments And Contingencies [Abstract]

Commitments And Contingencies

Note 12 — Commitments and Contingencies

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

Under the provisions of our limited partnership agreement with ATP-IP, we could be required to repurchase the Class A limited partner interest if certain change of control events were to occur. If a change of control were to become probable in a future period, we would be required to adjust the carrying amount of the redeemable noncontrolling interest to its redemption amount, to the extent it differed from the carrying amount, at the time the change of control was deemed to be probable. We do not currently believe a change of control is probable.

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

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 December 31, 2011, the aggregate amount of such contingent commitments related to unmet operational milestones was $7.8 million. During 2010, we paid $2.4 million of additional consideration for two of our North Sea properties under a similar provision.

We maintain insurance to protect the Company and its subsidiaries against losses arising out of our oil and gas operations. Our insurance includes coverage for physical damage to our offshore properties, general (third party) liability, workers compensation and employers liability, seepage and pollution and other risks. Our insurance includes various limits and deductibles or retentions, which must be met prior to or in conjunction with recovery. Additionally, our insurance is subject to the terms, conditions and exclusions of such policies. For losses emanating from offshore operations, we have up to an aggregate of $2.5 billion of various insurance coverages with individual policy limits ranging from $1.0 million to over $500 million each. While we maintain insurance levels, deductibles and retentions that we believe are prudent and responsible, there is no assurance that such coverage will adequately protect us against liability from all potential consequences and damages.

In general, our current insurance policies cover physical damage to our oil and gas assets. The coverage is designed to repair or replace assets damaged by insurable events.

Our excess liability policies generally provide coverage (dependent on the asset) for bodily injury and property damage, including coverage for negative environmental effects such as seepage and pollution. This liability coverage would cover claims for bodily injury or death brought against the company by or on behalf of individuals who are not employees of the company. The liability limits scale to either our operating interest or the total insured interest including nonoperating partners.

Our energy insurance package includes coverage for operator's extra expense, which provides coverage for control of well, re-drill and pollution arising from a covered event. We maintain a $150 million Oil Spill Financial Responsibility policy in order to provide a Certificate of Financial Responsibility to the BSEE under the requirements of the Oil Pollution Act of 1990. Additionally, as noted above, our excess liability policies provide coverage (dependent on the asset) for bodily injury and property damage, including coverage for negative environmental effects such as seepage and pollution. Legislation has been proposed but has not passed to increase the limit of the Oil Spill Financial Responsibility policy required for the certificate and there is no assurance that we will be able to obtain this insurance should that happen.

The occurrence of a significant accident or other event not fully covered by our insurance could have a materially adverse effect on our operations and financial condition. Our insurance does not protect us against all operational risks. We do not carry business interruption insurance at levels that would provide enough funds for us to continue operating without access to other funds. For some risks, we may not obtain insurance if we believe the cost of available insurance is excessive relative to the risks presented. Because third-party contractors and other service providers are used in our offshore operations, we may not realize the full benefit of worker's compensation laws in dealing with their employees. In addition, pollution and environmental risks generally are not fully insurable.

On January 29, 2010, Bison Capital Corporation ("Bison") filed suit against ATP in the United States District Court for the Southern district of New York alleging ATP owed fees totaling $102 million to Bison under a February 2004 agreement. The case was tried in January 2011. On March 8, 2011 the Court entered a judgment in favor of Bison for $1.65 million plus prejudgment interest and Bison's reasonable attorney's fees. ATP provided for this judgment in the financial statements as of December 31, 2010. Subsequently, Bison gave notice that it would appeal the judgment. By September 16, 2011, both Bison and ATP filed their respective briefs with the United States Court of Appeals for the Second Circuit. The case remains active pending resolution by the appellate court.

We are, in the ordinary course of business, involved in various other legal proceedings from time to time. Management does not believe that the outcome of these proceedings as of December 31, 2011, either individually or in the aggregate, will have a material adverse effect on our financial condition, results of operations or cash flows.