10-Q/A

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q/A

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

For the quarterly period ended June 30, 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 or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
4600 Post Oak Place, Suite 100
Houston, Texas 77027
(Address of principal executive offices)
(Zip Code)

(713) 622-3311

(Registrant’s telephone number, including area code)

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

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

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

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

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

The number of shares outstanding of the issuer’s common stock, par value $0.001, as of July 27, 2011 was 51,615,686.

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

EXPLANATORY NOTE

The purpose of this amendment on Form 10–Q/A to ATP Oil and Gas Corporation and Subsidiaries’ report on Form 10–Q for the quarter ended June 30, 2011, filed with the Securities and Exchange Commission on August 9, 2011 (“Form 10–Q”), is solely to furnish Exhibit 101 to the Form 10–Q in accordance with Rule 405 of Regulation S–T.

No other changes have been made to the Form 10–Q. This amendment speaks as of the original filing date of the form 10–Q, does not reflect events that may have occurred subsequent to the original filing date and does not modify or update in any way disclosures made in the original Form 10–Q.

Pursuant to rule 406T of Regulation S–T, the interactive data files on Exhibit 101 hereto are deemed not filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, as amended, are deemed not filed for purposes of Section 18 of the Securities Act of 1934, as amended, and otherwise are not subject to liability under those sections.

Item 6. Exhibits

#3.1	Amended and Restated Certificate of Formation, incorporated by reference to Exhibit 3.1 of the Current Report on Form 8-K of ATP Oil & Gas Corporation (“ATP”) filed June 10, 2010.
#3.2	Statement of Resolutions Establishing the 8.00% Convertible Perpetual Preferred Stock of ATP Oil & Gas Corporation, incorporated by reference to Exhibit 4.4 of Registration Statement No. 333-162574 on Form S-3 of ATP filed October 19, 2009.
#3.3	Statement of Resolutions Establishing the 8.00% Convertible Perpetual Preferred Stock, Series B of ATP Oil & Gas Corporation, incorporated by reference to Exhibit 3.1 of ATP’s Current Report on Form 8-K filed June 21, 2011.
#3.4	Third Amended and Restated Bylaws of ATP Oil & Gas Corporation, incorporated by reference to Exhibit 3.1 of ATP’s Current Report on Form 8-K filed December 15, 2009.
#4.1	Rights Agreement dated October 11, 2005 between ATP and American Stock Transfer & Trust Company, as Rights Agent, specifying the terms of the Rights, which includes the form of Statement of Designations of Junior Participating Preferred Stock as Exhibit A, the form of Right Certificate as Exhibit B and the form of the Summary of Rights to Purchase Preferred Shares as Exhibit C, incorporated by reference to Exhibit 1 to the Company’s Registration Statement on Form 8-A filed with the Securities and Exchange Commission on October 14, 2005.
#4.2	Form of Stock Certificate for 8.00% Convertible Perpetual Preferred Stock, incorporated by reference to Exhibit 4.1 of ATP’s Form 8-K dated September 29, 2009.
#4.3	Form of Stock Certificate for 8.00% Convertible Perpetual Preferred Stock, Series B, incorporated by reference to Exhibit 4.1 of ATP’s Current Report on Form 8-K filed June 21, 2011.
#4.4	Indenture dated as of April 23, 2010 between the Company and The Bank of New York Mellon Trust Company, N.A., as trustee (“Trustee”), incorporated by reference to Exhibit 4.1 to ATP’s Current Report on Form 8-K dated April 29, 2010.
#4.5	Registration Rights Agreement dated as of April 23, 2010 between the Company and J.P. Morgan Securities Inc., incorporated by reference to Exhibit 10.2 to ATP’s Current Report on Form 8-K dated April 29, 2010.
#4.6	Form of Nonqualified Stock Option Agreement, incorporated by reference to Exhibit 4.6 of Registration Statement No. 333-171263 on Form S-8 of ATP filed December 17, 2010.
#4.7	Form of Restricted Stock Award Agreement (to be used in connection with awards to directors of ATP), incorporated by reference to Exhibit 4.7 of Registration Statement No. 333-171263 on Form S-8 of ATP filed December 17, 2010.
#4.8	Form of Restricted Stock Award Agreement (to be used in connection with awards to executive officers of ATP), incorporated by reference to Exhibit 4.8 of Registration Statement No. 333-171263 on Form S-8 of ATP filed December 17, 2010.
#10.1	Credit Agreement dated as of June 18, 2010 among ATP Oil & Gas Corporation, Credit Suisse AG and the lenders party thereto, incorporated by reference to Exhibit 10.1 of ATP’s Current Report on Form 8-K dated June 18, 2010.
#10.2	Term Loan Agreement, dated as of September 24, 2010 among Titan LLC, as the Borrower, CLMG Corp., as Agent, and the Lenders party thereto incorporated by reference to Exhibit 99.1 to ATP’s Current Report on Form 8-K dated September 24, 2010.
#10.3	ATP Oil & Gas Corporation 2010 Stock Plan incorporated by reference to Appendix A to ATP’s Schedule 14A dated April 29, 2010.
#10.4	Intercreditor Agreement dated as of April 23, 2010 among the Company, the Trustee and Credit Suisse AG, incorporated by reference to Exhibit 10.3 to ATP’s Current Report on Form 8-K dated April 29, 2010.

#10.5	Sale and Purchase Agreement between ATP Oil & Gas (UK) Limited and EDF Production UK Ltd., as amended and restated on October 23, 2008, incorporated by reference to Exhibit 10.1 to ATP’s Report on Form 10-Q for the quarter ended September 30, 2008.
#10.6	Employment Agreement between ATP and Leland E. Tate, dated December 30, 2010, incorporated by reference to Exhibit 10.5 to ATP’s Form 8-K dated December 30, 2010.
#10.7	Employment Agreement between ATP and Albert L. Reese, Jr., dated December 30, 2010, incorporated by reference to Exhibit 10.4 to ATP’s Form 8-K dated December 30, 2010.
#10.8	Employment Agreement between ATP and Keith R. Godwin, dated December 30, 2010, incorporated by reference to Exhibit 10.2 to ATP’s Form 8-K dated December 30, 2010.
#10.9	Employment Agreement between ATP and T. Paul Bulmahn, dated December 30, 2010, incorporated by reference to Exhibit 10.1 to ATP’s Form 8-K dated December 30, 2010.
#10.10	Employment Agreement between ATP and George R. Morris, dated December 30, 2010, incorporated by reference to Exhibit 10.3 to ATP’s Form 8-K dated December 30, 2010.
#10.11	All Employee Bonus Policy, incorporated by reference to exhibit 10.16 to ATP’s Annual Report on Form 10-K for the year ended December 31, 2008.
#10.12	Discretionary Bonus Policy, incorporated by reference to exhibit 10.17 to ATP’s Annual Report on Form 10-K for the year ended December 31, 2008.
#10.13	Incremental Loan Assumption Agreement and Amendment No. 1 to Credit Agreement among ATP, the lenders party thereto and Credit Suisse AG, incorporated by reference to Exhibit 10.1 of ATP’s Form 8-K dated February 19, 2011.
#10.14	Amended and restated letter agreement dated June 15, 2011 between the Company and Credit Suisse International, c/o Credit Suisse Securities USA LLC relating to the capped call transactions, incorporated by reference to Exhibit 10.1 of ATP’s Current Report on Form 8-K filed June 21, 2011.
#21.1	Subsidiaries of ATP, incorporated by reference to Exhibit 21.1 to ATP’s Report on Form 10-Q for the quarter ended March 31, 2011.
#31.1	Certification of Principal Executive Officer pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934, the “Act”
#31.2	Certification of Principal Financial Officer pursuant to Rule 13a-14(a) of the Act
#32.1	Certification of Principal Executive Officer pursuant to 18 U.S.C. Section 1350
#32.2	Certification of Principal Financial Officer pursuant to 18 U.S.C. Section 1350
*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

# Previously filed or furnished as an exhibit to ATP’s Report on Form 10-Q for the quarter ended June 30, 2011.

* Filed herewith

SIGNATURES

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

		ATP Oil & Gas Corporation
Date:	August 16, 2011	By:	/s/ Albert L. Reese Jr.
			Albert L. Reese Jr.
			Chief Financial Officer

XML



Consolidated Balance Sheets (Parenthetical) (USD $)	Jun. 30, 2011	Dec. 31, 2010
Consolidated Balance Sheets
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	785,189	0
Temporary equity, convertible perpetual preferred stock, shares outstanding	785,189
Temporary equity, convertible perpetual preferred stock, liquidation value	78,500,000	0
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	2,339,811	1,400,000
8% convertible perpetual preferred stock, outstanding	2,339,811	1,400,000
8% convertible perpetual preferred stock, liquidation value, discount	$ 234,000,000	$ 140,000,000
Common stock, par value	$ 0.001	$ 0.001
Common stock, shares authorized	100,000,000	100,000,000
Common stock, issued	51,691,526	51,347,163
Common stock, outstanding	51,615,686	51,271,323

XML



Consolidated Statements of Operations (USD $) In Thousands, except Per Share data	3 Months Ended		6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	Jun. 30, 2011	Jun. 30, 2010
Consolidated Statements of Operations
Oil and gas production revenues	$ 172,883	$ 101,099	$ 339,383	$ 194,128
Costs, operating expenses and other:
Lease operating	41,640	32,295	74,047	61,930
Exploration	1,000	9	1,000	721
General and administrative	10,166	8,060	19,902	18,623
Depreciation, depletion and amortization	74,318	60,115	153,638	96,116
Impairment of oil and gas properties	45,704	3,853	45,704	12,090
Accretion of asset retirement obligation	3,771	3,463	7,435	6,853
Drilling interruption costs	1,193	8,714	19,691	8,714
Loss on abandonment	114	50	1,383	201
Gain on exchange/disposal of properties		(46)		(12,020)
Total operating expenses	177,906	116,513	322,800	193,228
Income (loss) from operations	(5,023)	(15,414)	16,583	900
Other income (expense):
Interest income	59	154	116	298
Interest expense, net	(97,043)	(64,645)	(172,528)	(76,864)
Derivative income (expense)	35,918	23,929	(14,344)	27,464
Gain (loss) on debt extinguishment	1,091	(78,171)	1,091	(78,171)
Total other non operating income (expenses)	(59,975)	(118,733)	(185,665)	(127,273)
Loss before income taxes	(64,998)	(134,147)	(169,082)	(126,373)
Income tax benefit (expense):
Current		326		(227)
Deferred	14,494	57,473	5,352	56,621
Total	14,494	57,799	5,352	56,394
Net loss	(50,504)	(76,348)	(163,730)	(69,979)
Less income attributable to the redeemable noncontrolling interest	(3,562)	(3,771)	(7,125)	(8,226)
Less convertible preferred stock dividends	(2,786)	(2,800)	(5,544)	(5,600)
Net loss attributable to common shareholders	$ (56,852)	$ (82,919)	$ (176,399)	$ (83,805)
Net loss per share attributable to common shareholders:
Basic	$ (1.11)	$ (1.63)	$ (3.46)	$ (1.66)
Diluted	$ (1.11)	$ (1.63)	$ (3.46)	$ (1.66)
Weighted average number of common shares:
Basic	51,048	50,767	51,034	50,609
Diluted	51,048	50,767	51,034	50,609

XML



Subsequent Events

6 Months Ended

Jun. 30, 2011

Subsequent Events

Subsequent Events

Note 16 — Subsequent Events

Our evaluation has identified no matters which require disclosure as events subsequent to June 30, 2011.

XML



Document and Entity Information	6 Months Ended
	Jun. 30, 2011	Jul. 27, 2011
Document and Entity Information
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Jun. 30, 2011
Document Fiscal Year Focus	2011
Document Fiscal Period Focus	Q2
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		51,615,686

XML



Income Taxes

6 Months Ended

Jun. 30, 2011

Income Taxes

Income Taxes

Note 5 — Income Taxes

Income taxes during interim periods are based on the estimated annual effective income tax rate plus any significant, unusual or infrequently occurring items that are recorded in the period the specific item occurs. We compute income taxes using an asset and liability approach, which results in the recognition of deferred tax liabilities and assets for the expected future tax consequences of temporary differences between the financial basis and the tax basis of those assets and liabilities. As of June 30, 2011 and December 31, 2010, for U.S. and Netherlands tax provision purposes, we have provided valuation allowances for the entirety of our net deferred tax assets based on our cumulative net losses coupled with the uncertainties surrounding our future earnings forecasts arising from the continued permitting delays in the Gulf of Mexico. The U.K. supplementary charge of corporation tax was increased from 20% to 32%, effective March 24, 2011. This change has not been reflected in the provision for the six months ended June 30, 2011 because it was not signed into law at that date; however, it is expected to affect U.K. results of operations once it is enacted. We recognized income tax benefit of $14.5 million and $57.8 million, respectively, for the three months ended June 30, 2011 and 2010. We recognized income tax benefit of $5.4 million and $56.4 million, respectively, for the six months ended June 30, 2011 and 2010. The worldwide effective tax rates for the three months ended June 30, 2011 and 2010 were 22.3% and 43.1%, respectively. The worldwide effective tax rates for the six months ended June 30, 2011 and 2010 were 3.2% and 44.6%, respectively.

XML



Stock-Based Compensation

6 Months Ended

Jun. 30, 2011

Stock-Based Compensation

Stock-Based Compensation

Note 10 — Stock–Based Compensation

Stock-based compensation expense was as follows (in thousands):

	Three Months Ended June 30,				Six Months Ended June 30,
	2011		2010		2011		2010
Stock options		551		591		1,001		1,367
Restricted stock		902		1,120		1,882		2,193

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

	Three Months Ended June 30,						Six Months Ended June 30,
	2011			2010			2011			2010
Weighted average volatility		85	%		85	%		85	%		82	%
Expected term (in years)		3.8			3.8			3.8			3.8
Risk-free rate		1.4	%		1.4	%		1.4	%		1.8	%
Weighted average fair value of options — grant date	$	9.61		$	3.75		$	9.67		$	7.77

The following table sets forth a summary of option transactions for the six months ended June 30, 2011:

	Number of Options			Weighted Average Grant Price		Aggregate Intrinsic Value (1) ($000)		Weighted Average Remaining Contractual Life
								(in years)
Outstanding at beginning of period		1,521,291		$	23.31
Granted		314,510			16.12
Canceled		(48,027	)		24.47
Expired		(168,437	)		38.22
Exercised		(31,252	)		6.05	$	380
Outstanding at end of period		1,588,085			20.61	$	4,022		3.1
Vested and expected to vest		1,354,652			20.58	$	3,445		3.1
Options exercisable at end of period		502,109			29.78	$	991		1.9

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

At June 30, 2011, unrecognized compensation expense related to nonvested stock option grants totaled $4.2 million. Such unrecognized expense will be recognized as vesting occurs over a weighted average period of 2.6 years.

At June 30, 2011, unrecognized compensation expense related to restricted stock totaled $5.3 million. Such unrecognized expense will be recognized as vesting occurs over a weighted average period of 2.2 years. The following table sets forth the changes in nonvested restricted stock for the six months ended June 30, 2011:

	Number of Shares			Weighted Average Grant-date Fair Value		Aggregate Intrinsic Value (1) ($000)
Nonvested at beginning of period		422,637		$	19.76
Granted		313,111			16.62
Vested		(206,815	)		24.11
Nonvested at end of period		528,933			16.20	$	8,098

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

XML



Organization

6 Months Ended

Jun. 30, 2011

Organization

Organization

Note 1 — Organization

Organization

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. and Dutch sectors 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.

We recently acquired three licenses in the Mediterranean Sea covering potential natural gas resources in the deep water 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 capital investment in the Mediterranean Sea related to these three licenses is expected to be minimal for the remainder of 2011 as we prepare our exploration and development plans for drilling in 2012.

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 Energy, Inc.; ATP Oil & Gas (UK) Limited, or "ATP (UK);" ATP Oil & Gas (Netherlands) B.V.; 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, and we separate the redeemable noncontrolling interest in ATP-IP in the accompanying statements.

The accompanying unaudited consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States ("GAAP") for interim financial information and reflect all adjustments (consisting of normal recurring adjustments) which are, in the opinion of management, necessary for a fair statement of the results of operations for the interim periods. The interim financial information and notes hereto should be read in conjunction with our 2010 Annual Report on Form 10-K. The results of operations for the six months ended June 30, 2011 are not necessarily indicative of results to be expected for the entire year. We have reclassified certain amounts applicable to prior periods to conform to current classifications. These reclassifications do not affect earnings.

XML



Other Long-term Obligations

6 Months Ended

Jun. 30, 2011

Other Long-term Obligations

Other Long-term Obligations

Note 7 — Other Long-term Obligations

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

	June 30, 2011			December 31, 2010
Net profits interests	$	325,015		$	331,776
Dollar-denominated overriding royalty interests		54,725			52,825
Gomez pipeline obligation		74,104			73,868
Vendor deferrals — Gulf of Mexico		6,942			7,096
Vendor deferrals — North Sea		88,203			90,874
Other		2,582			2,582
Total		551,571			559,021
Less current maturities		(113,364	)		(86,521	)
Other long-term obligations	$	438,207		$	472,500

Net Profits Interests

Beginning in 2009, we have been granting 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 companies 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 80% of the NPIs to be repaid over the next 18 months based on anticipated production, commodity prices and operating costs.

Dollar-denominated Overriding Royalty Interests

During April and June 2011, we sold, for an aggregate $50.0 million, two 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. We expect the Overrides to be repaid over approximately the next 24 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 2011, we entered into an amendment to our agreement for the construction and delivery of the Octabuoy hull and topside equipment. The amendment provided for additional deferrals totaling approximately $124.3 million and delayed the final payment until the second quarter of 2013. The amount due under the amended agreement in 2011 is $20.2 million with an aggregate $191.7 million due in 2012 and 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.

The weighted average effective interest rate on our other long-term obligations was 17.9% at June 30, 2011.

XML



Derivative Instruments and Risk Management Activities

6 Months Ended

Jun. 30, 2011

Derivative Instruments and Risk Management Activities

Derivative Instruments and Risk Management Activities

Note 12 — Derivative Instruments and Risk Management Activities

At June 30, 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
Remainder 2011	Swaps		1,257,000	91.31		(6,858	)		—
2012	Swaps		3,133,750	89.64		(14,215	)		(14,636	)
2013	Swaps		90,000	90.40		—			(778	)
Remainder 2011	Swaps (2)		368,000	95.00		(155	)		—
Total						(21,228	)		(15,414	)
Natural Gas (MMBtu)
North Sea
Remainder 2011	Swaps		920,000	8.76		(1,121	)		—
2012	Swaps		1,646,000	8.79		(1,861	)		(1,376	)
Gulf of Mexico
Remainder 2011	Calls (3)		1,840,000	4.90		(442	)		—
2012	Calls (3)		3,660,000	5.35		(523	)		(655	)
Remainder 2011	Fixed-price physicals		2,760,000	4.64		456			—
2012	Fixed-price physicals		1,365,000	4.64		(251	)		—
Total						(3,742	)		(2,031	)
Total asset						206			—
Total liability						(25,176	)		(17,445	)
Total						(24,970	)		(17,445	)

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

(2) These swaps include call options to allow us to participate in per barrel price increases above $110.00 in the remainder of 2011.

(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 are designated as hedges 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 generally 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.

During the six months ended June 30, 2011, we paid net cash settlements of $16.7 million on our commodity derivatives. Our derivative income (expense) for the six months ended June 30, 2011 and 2010 is based entirely on nondesignated derivatives and consists of the following (in thousands):

	Three Months Ended June 30,					Six Months Ended June 30,
	2011			2010		2011			2010
Gains (losses) from:
Settlements of contracts	$	(9,148	)	$	620	$	(16,554	)	$	(1,449	)
Unrealized gains on open contracts		45,066			23,309		2,210			28,913
Derivative income (expense)	$	35,918		$	23,929	$	(14,344	)	$	27,464

XML



Preferred Stock

6 Months Ended

Jun. 30, 2011

Preferred Stock

Preferred Stock

Note 8 — Preferred Stock

In June 2011, we issued 1.7 million shares of convertible 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). 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 acquireable 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.

The Series B Preferred Stock has terms and features which are substantially identical to the convertible preferred stock we issued in 2009 (collectively, the "Preferred Stock"). Each share of Preferred Stock is perpetual, has no voting rights, has a liquidation preference of $100, pays cumulative dividends at an annual rate of 8% 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.

At June 30, 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 will be revalued in future reporting periods 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.

XML



Long-term Debt

6 Months Ended

Jun. 30, 2011

Long-term Debt

Long-term Debt

Note 6 — Long-term Debt

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

	June 30, 2011			December 31, 2010
First lien term loans, net of $2,866 and $2,644, respectively, unamortized discount	$	205,338		$	146,607
Senior second lien notes, net of $5,371 and $6,071, respectively, unamortized discount		1,494,629			1,493,929
Term loan facility — ATP Titan assets, net of $14,288 and $10,760, respectively, unamortized discount		274,346			238,873
Total debt		1,974,313			1,879,409
Less current maturities		(27,727	)		(21,625	)
Total long-term debt	$	1,946,586		$	1,857,784

During 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).

During March 2011, we entered into First Amendment to Term Loan Agreement and Limited Waiver, relating to our Term Loan Facility — ATP Titan assets to, among other things, modify the conditions precedent for incremental borrowings drawn under the facility. Additional borrowings were $50.0 million ($44.2 million, net of transactions costs and discount).

The effective annual interest rate and fair value of our long-term debt was 11.9% and approximately $2.0 billion, respectively, at June 30, 2011.

XML



Consolidated Statements of Shareholders' Equity and Temporary Equity (USD $) In Thousands	Temporary Equity-Redeemable Noncontrolling Interest [Member]	Temporary Equity-Eight Percent Convertible Perpetual Preferred Stock, Series B [Member]	Eight Percent Convertible Perpetual Preferred Stock [Member]	Eight Percent Convertible Perpetual Preferred Stock, Series B [Member]	Common Stock [Member]	Paid-in Capital [Member]	Accumulated Deficit [Member]	Accumulated Other Comprehensive Loss [Member]	Treasury Stock [Member]	Total
Balance, beginning of period at Dec. 31, 2009			$ 140,000		$ 51	$ 571,595	$ (19,317)	$ (95,487)	$ (911)
Balance, beginning of period at Dec. 31, 2009	139,598
Balance, beginning of period, shares at Dec. 31, 2009			1,400		50,679				76
Income attributable to the redeemable noncontrolling interest	8,226						(8,226)			8,226
Limited partner distributions	(7,125)
Issuance of preferred stock, shares
Issuance costs, shares
Issuance of common stock-exercise of stock options/warrants						3,547
Issuance of common stock-exercise of stock options/warrants, shares					415
Restricted stock, net of forfeitures, shares					177
Preferred stock dividends						(5,600)
Stock-based compensation						3,559
Net loss							(69,979)			(69,979)
Other comprehensive income (loss)								(9,690)
Balance, end of period at Jun. 30, 2010			140,000		51	573,101	(97,522)	(105,177)	(911)	509,542
Balance, end of period at Jun. 30, 2010	140,699
Balance, end of period, shares at Jun. 30, 2010			1,400		51,271				76
Balance, beginning of period at Dec. 31, 2010			140,000		51	570,739	(356,866)	(101,027)	(911)	251,986
Balance, beginning of period at Dec. 31, 2010	140,851									140,851
Balance, beginning of period, shares at Dec. 31, 2010			1,400		51,271				76
Income attributable to the redeemable noncontrolling interest	7,125						(7,125)			7,125
Limited partner distributions	(32,571)
Issuance of preferred stock		70,667		84,583
Issuance of preferred stock, shares		785		940
Issuance costs		(2,493)
Issuance costs, shares
Purchase of capped-call options						(26,500)				(26,500)
Issuance of common stock-exercise of stock options/warrants						163
Issuance of common stock-exercise of stock options/warrants, shares					31
Restricted stock, net of forfeitures					1
Restricted stock, net of forfeitures, shares					314
Issuance costs related to preferred stock						(2,990)
Preferred stock dividends						(5,544)
Stock-based compensation						2,910
Net loss							(163,730)			(163,730)
Other comprehensive income (loss)								7,348
Balance, end of period at Jun. 30, 2011			140,000	84,583	52	538,778	(527,721)	(93,679)	(911)	141,102
Balance, end of period at Jun. 30, 2011		68,174								68,174
Balance, end of period at Jun. 30, 2011	$ 115,405									$ 115,405
Balance, end of period, shares at Jun. 30, 2011		785	1,400	940	51,616				76

XML



Recent Accounting Pronouncements

6 Months Ended

Jun. 30, 2011

Recent Accounting Pronouncements

Recent Accounting Pronouncements

Note 2 — Recent 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. 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.

XML



Risks and Uncertainties

6 Months Ended

Jun. 30, 2011

Risks and Uncertainties

Risks and Uncertainties

Note 3 — Risks and Uncertainties

Our near-term operating and development plans in the Gulf of Mexico as well as our longer-term business plan are dependent on receiving additional approvals for deepwater drilling and other permits under applications which have been and will be submitted to the Bureau of Ocean Energy Management, Regulation and Enforcement of the Department of the Interior ("BOEM"). In the first quarter of 2011, we received permits to complete the drilling of the third well in Mississippi Canyon Block 941 at our Telemark Hub and to complete a well at Green Canyon Block 300. Completion activities on the third well at our Telemark Hub are underway. Also, while we believe we can satisfy the permitting requirements for the additional planned 2011 development wells, which we expect will allow us to increase significantly our production from current levels, there is no assurance that the permits will be issued or, if issued, that they will be received in time to benefit our 2011 results. Should the regulatory process in the Gulf of Mexico continue to cause delays, we believe we can continue to meet our existing obligations for at least the next twelve months based on forecasted production levels and the continuation of commodity sales prices and operating costs near current levels.

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 found in 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 and cash flows and our ability to meet our commitments as they come due.

The size of our operations and our capital expenditures budget limit the number of properties that we can develop in any given year. We have historically obtained various other sources of funding to supplement our cash flow from operations and we will continue to pursue them in the future. There is no assurance, however, that these alternative sources will be available should these risks and uncertainties materialize.

We cannot predict how the authorities will further respond to the Macondo incident in the Gulf of Mexico or whether additional changes in laws and regulations governing oil and gas operations in the Gulf of Mexico will result. New regulations already issued will, and potential future regulations or additional statutory limitations, if enacted or issued, could, require a change in the way we conduct our business, increase our costs of doing business or ultimately prohibit us from drilling for or producing hydrocarbons in the Gulf of Mexico. We cannot predict if or how the governments of other countries in which we operate will respond to the accident in the Gulf of Mexico. We incurred additional costs in 2010 caused by the deepwater drilling moratoriums and subsequent drilling permit delays and some of these additional costs are continuing into 2011 and are expected to continue.

We have financed a significant portion of our development program with transactions entered into with our vendors and financial institutions that either defer payments to future periods or will be repaid based on production throughput or from the revenues or net profits generated from future production. While these financing transactions have enabled us to continue the development of our properties and preserve cash, they will significantly burden the future net cash flows from our production until these obligations are satisfied. (See Note 7, "Other Long-term Obligations," for further details.)

As an independent oil and gas producer, our revenue, profitability, cash flows, and future rate of growth are substantially dependent on prevailing prices for oil and natural gas. Historically, the energy markets have been very volatile, and we expect such price volatility to continue. Any extended decline in oil or gas prices could have a 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.

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 estimates. As of December 31, 2010, approximately 81% of our total proved reserves were undeveloped. We intend to continue to develop these reserves through the end of the year and beyond, but there can be no assurance we will be successful. Development of these reserves may not yield the expected results, or the development may be delayed or the costs may exceed our estimates, any of which may materially affect our financial position, results of operations, cash flows and our ability to meet the requirements of our financing obligations.

XML



Earnings Per Share

6 Months Ended

Jun. 30, 2011

Earnings Per Share

Earnings Per Share

Note 11 — Earnings Per Share

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

	Three Months Ended June 30,						Six Months Ended June 30,
	2011			2010			2011			2010
Net loss attributable to common shareholders:
Net loss attributable to common shareholders	$	(56,852	)	$	(82,919	)	$	(176,399	)	$	(83,805	)
Add impact of assumed preferred stock conversions (if-converted method)		—			—			—			—
Net loss attributable to common shareholders and impact of assumed conversions	$	(56,852	)	$	(82,919	)	$	(176,399	)	$	(83,805	)
Weighted average shares outstanding:
Weighted average shares outstanding — basic		51,048			50,767			51,034			50,609
Effect of potentially dilutive securities — stock options and warrants		—			—			—			—
Nonvested restricted stock		—			—			—			—
Preferred stock		—			—			—			—
Weighted average shares outstanding — diluted		51,048			50,767			51,034			50,609
Net loss per share attributable to common shareholders:
Basic	$	(1.11	)	$	(1.63	)	$	(3.46	)	$	(1.66	)
Diluted	$	(1.11	)	$	(1.63	)	$	(3.46	)	$	(1.66	)

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

	Three Months Ended June 30,				Six Months Ended June 30,
	2011		2010		2011		2010
Net loss attributable to common shareholders:
Preferred stock dividends	$	2,786	$	2,800	$	5,544	$	5,600
Weighted average shares outstanding:
Common stock equivalents		359		268		228		211
Assumed conversion of preferred stock		7,246		6,300		6,779		6,300
Out-of-the-money stock options		593		1,148		636		1,251

XML



Oil and Gas Properties

6 Months Ended

Jun. 30, 2011

Oil and Gas Properties

Oil and Gas Properties

Note 4 — Oil and Gas Properties

Acquisitions

During June 2011, we acquired interests in three deepwater licenses in the Mediterranean Sea off the coast of Israel. We will operate the licenses with working interests of 40%.

Impairment of Oil and Gas Properties

During the second quarter of 2011, we recognized impairment expense of $45.7 related to two older properties South Timbalier 77 (acquired in 2005) and Eugene Island 30 (acquired in 1999). The impairment at South Timbalier 77 represents the majority of the expense and was primarily due to our decision not to move forward with a related capital program.

XML



Segment Information

6 Months Ended

Jun. 30, 2011

Segment Information

Segment Information

Note 14 — Segment Information

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

For the Three Months Ended —	Gulf of Mexico		North Sea			Total
June 30, 2011:
Revenues	$	168,304	$	4,579		$	172,883
Depreciation, depletion and amortization		70,988		3,330			74,318
Impairment		45,704		—			45,704
Loss from operations		3,407		1,616			5,023
Interest income		59		—			59
Interest expense, net		97,043		—			97,043
Derivative income		34,801		1,117			35,918
Gain on debt extinguishment		1,091		—			1,091
Income tax benefit		14,494		—			14,494
Additions to oil and gas properties		90,134		43,719			133,853
June 30, 2010:
Revenues	$	96,002	$	5,097		$	101,099
Depreciation, depletion and amortization		54,451		5,664			60,115
Impairment		3,853		—			3,853
Income (loss) from operations		12,517		2,897			15,414
Interest income		39		115			154
Interest expense, net		64,645		—			64,645
Derivative income		30,288		(6,359	)		23,929
Loss on debt extinguishment		78,171		—			78,171
Income tax expense		57,799		—			57,799
Additions to oil and gas properties		168,078		39,934			208,012
For the Six Months Ended —	Gulf of Mexico		North Sea			Total
June 30, 2011:
Revenues	$	329,251	$	10,132		$	339,383
Depreciation, depletion and amortization		146,486		7,152			153,638
Impairment		45,704		—			45,704
Income (loss) from operations		18,870		(2,287	)		16,583
Interest income		116		—			116
Interest expense, net		172,528		—			172,528
Derivative expense		12,708		1,636			14,344
Gain on debt extinguishment		1,091		—			1,091
Income tax benefit		5,352		—			5,352
Additions to oil and gas properties		103,224		121,462			224,686
Total assets		2,830,231		469,461			3,299,692
June 30, 2010:
Revenues	$	183,370	$	10,758		$	194,128
Depreciation, depletion and amortization		84,862		11,254			96,116
Impairment		12,090		—			12,090
Income (loss) from operations		5,742		(4,842	)		900
Interest income		76		222			298
Interest expense, net		76,864		—			76,864
Derivative income		32,902		(5,438	)		27,464
Loss on debt extinguishment		78,171		—			78,171
Income tax expense		56,394		—			56,394
Additions to oil and gas properties		448,495		64,805			513,300
Total assets		2,924,795		339,637			3,264,432

XML



Consolidated Statements of Cash Flows (USD $) In Thousands	6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010
Cash flows from operating activities
Net loss	$ (163,730)	$ (69,979)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities -
Depreciation, depletion and amortization	153,638	96,116
Impairment of oil and gas properties	45,704	12,090
Gain on exchange/disposal of properties		(12,020)
Accretion of asset retirement obligation	7,435	6,853
Deferred income tax benefit	(5,352)	(56,621)
Derivative income	(2,347)	(28,732)
Loss (gain) on debt extinguishment	(1,091)	21,829
Stock-based compensation	2,883	3,560
Amortization of deferred revenue		(18,484)
Noncash interest expense	26,085	12,439
Other noncash items, net	198	387
Changes in assets and liabilities -
Accounts receivable and other current assets	58,904	(6,125)
Accounts payable and accruals	(53,713)	15,615
Other assets and liabilities	(26,325)	5,283
Net cash provided by (used in) operating activities	42,289	(17,789)
Cash flows from investing activities
Additions to oil and gas properties	(169,180)	(377,329)
Proceeds from disposition of properties		2,053
Increase in restricted cash	(7,178)	(2,436)
Net cash used in investing activities	(176,358)	(377,712)
Cash flows from financing activities
Proceeds from senior second lien notes, net of discount		1,492,965
Proceeds from first lien term loans	59,400	147,000
Proceeds from term loan facility-ATP Titan assets	45,000
Proceeds from term loans		46,000
Payments of term loans	(12,047)	(1,262,610)
Deferred financing costs	(3,035)	(52,613)
Proceeds from other long-term obligations	70,327	171,136
Payments of other long-term obligations	(89,181)	(39,605)
Distributions to noncontrolling interest	(7,126)	(7,125)
Proceeds from preferred stock, net of costs	149,767
Purchase of capped-call options on ATP common stock	(26,500)
Preferred stock dividends	(5,544)	(5,656)
Other financings, net	(16,954)
Exercise of stock options/warrants	189	3,547
Net cash provided by financing activities	164,296	493,039
Effect of exchange rate changes on cash and cash equivalents	938	(567)
Increase in cash and cash equivalents	31,165	96,971
Cash and cash equivalents, beginning of year	154,695	108,961
Cash and cash equivalents, end of period	185,860	205,932
Noncash investing and financing activities
Increase (decrease) in noncash property additions	(3,305)	138,882
Net property additions - nonmonetary exchange		11,778
Asset retirement costs capitalized		$ 1,258

XML



Fair Value Measurements

6 Months Ended

Jun. 30, 2011

Fair Value Measurements

Fair Value Measurements

Note 15 — Fair Value Measurements

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. The following table sets forth a reconciliation of changes in the fair value of these financial assets (liabilities) during the six months ended June 30, 2011 (in thousands):

	U.S Gas Fixed- Price Physicals			U.S Gas Calls			U.S. Oil Swaps			U.S Oil Swaps(1)			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 income (expense)		1,443			513			(21,511	)		7,262			170			(2,221	)		(14,344	)
Premium received		—			(2,133	)		—			—			—			—			(2,133	)
Settlements		(1,526	)		—			12,542			4,610			(828	)		1,895			16,693
Balance at end of period	$	206		$	(1,620	)	$	(36,488	)	$	(155	)	$	—		$	(4,357	)	$	(42,414	)
Changes in unrealized gain (loss) included in derivative income (expense) relating to derivatives still held at June 30, 2011	$	1,155		$	(1,620	)	$	(19,300	)	$	3,467		$	—		$	(2,413	)	$	(18,711	)

(1) These swaps include those which have been 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 six months ended June 30, 2010 (in thousands):

	Gas Fixed- Price Physicals			Gas Price Collars			Oil Swaps			Oil Swaps(1)			Oil Puts			Subtotal U.S.
U.S.
Balance at beginning of period	$	(778	)	$	(339	)	$	(7,837	)	$	(14,910	)	$	2		$	(23,862	)
Derivative income (expense)		6,212			2,487			13,894			10,311			(2	)		32,902
Settlements and terminations		(2,682	)		(935	)		2,221			3,036						1,640
Balance at end of period	$	2,752		$	1,213		$	8,278		$	(1,563	)	$	—		$	10,680
Changes in unrealized gain (loss) included in derivative income (expense) relating to derivatives still held at June 30, 2010	$	3,195		$	1,762		$	15,682		$	3,687		$	(2	)	$	24,324

	Gas Fixed- Price Physicals			Financial Gas Swaps			Subtotal U.K.			Grand Total
U.K.
Balance at beginning of period	$	1,321		$	—		$	1,321		$	(22,541	)
Derivative income		(1,213	)		(4,225	)		(5,438	)		27,464
Settlements and terminations		(472	)		99			(373	)		1,267
Balance at end of period	$	(364	)	$	(4,126	)	$	(4,490	)	$	6,190
Changes in unrealized gain (loss) included in derivative income (expense) relating to derivatives still held at June 30, 2010	$	(802	)	$	(4,126	)	$	(4,928	)	$	19,396

Assets Measured at Fair Value on a Nonrecurring Basis

Oil and gas property is measured at fair value on a nonrecurring basis upon impairment and when acquired in a nonmonetary property exchange. During the six months ended June 30, 2011 and 2010, we recorded impairment expense of $45.7 million and $12.1 million, respectively, related to proved and unproved Gulf of Mexico properties. In the six months ended June 30, 2010, we recorded gain on nonmonetary property exchange of $12.0 related to proved Gulf of Mexico properties. The impairment charges reduce the oil and gas properties' carrying values to their estimated fair values and are classified as Level 3. Fair value is calculated as the estimated discounted future net cash flows attributable to the assets. The gain on nonmonetary property exchange reflects the difference between the carrying value of the property surrendered and the estimated fair value of the property received, classified as Level 3, and is calculated based on the estimated discounted future net cash flows attributable to that asset.

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

XML



Consolidated Statements of Comprehensive Income (Loss) (USD $) In Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	Jun. 30, 2011	Jun. 30, 2010
Consolidated Statements of Comprehensive Income (Loss)
Net loss	$ (50,504)	$ (76,348)	$ (163,730)	$ (69,979)
Other comprehensive income (loss) - foreign currency translation adjustment	(1,067)	242	7,348	(9,690)
Comprehensive loss	(51,571)	(76,106)	(156,382)	(79,669)
Less comprehensive income attributable to the redeemable noncontrolling interest	(3,562)	(3,771)	(7,125)	(8,226)
Less convertible preferred stock dividends	(2,786)	(2,800)	(5,544)	(5,600)
Comprehensive loss attributable to common shareholders	$ (57,919)	$ (82,677)	$ (169,051)	$ (93,495)

XML



Asset Retirement Obligation

6 Months Ended

Jun. 30, 2011

Asset Retirement Obligation

Asset Retirement Obligation

Note 9 — Asset Retirement Obligation

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

	Six Months Ended June 30,
	2011			2010
Asset retirement obligation, beginning of period	$	166,858		$	150,199
Liabilities incurred		1,383			1,459
Liabilities settled		(13,812	)		(2,626	)
Property dispositions		—			(242	)
Accretion of asset retirement obligation		7,435			6,853
Changes in estimates		682			(950	)
Total asset retirement obligation		162,546			154,693
Less current portion		(47,897	)		(43,720	)
Total long-term asset retirement obligation, end of period	$	114,649		$	110,973

XML



Commitments and Contingencies

6 Months Ended

Jun. 30, 2011

Commitments and Contingencies

Commitments and Contingencies

Note 13 — 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 in each locality in which we operate. 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 June 30, 2011, the aggregate amount of such contingent commitments related to unmet operational milestones was $8.9 million.

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, ATP has up to an aggregate of $2.4 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 BOEM 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 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. Either party could file a notice of appeal within 30 days of the judgment. Subsequently, Bison gave notice that it will appeal the judgment and, thus, the case is still pending.

We are, in the ordinary course of business, involved in various other legal proceedings from time to time. Management does not believe that the outcome of these proceedings as of June 30, 2011, either individually or in the aggregate, will have a materially adverse effect on our financial condition, results of operations or cash flows.

XML



Consolidated Balance Sheets (USD $) In Thousands	Jun. 30, 2011	Dec. 31, 2010
Assets
Cash and cash equivalents	$ 185,860	$ 154,695
Restricted cash	37,448	30,270
Accounts receivable (net of allowance of $225 and $225, respectively)	70,782	92,737
Deferred tax asset	3,390	8,191
Derivative asset	206	1,688
Other current assets	9,677	26,408
Total current assets	307,363	313,989
Oil and gas properties (using the successful efforts method of accounting):
Proved properties	4,513,526	4,291,440
Unproved properties	23,003	20,402
Total oil and gas	4,536,529	4,311,842
Less accumulated depletion, depreciation, impairment and amortization	(1,612,753)	(1,407,206)
Oil and gas properties, net	2,923,776	2,904,636
Restricted cash	10,000	10,000
Deferred financing costs, net	45,460	48,353
Other assets, net	13,093	13,124
Total assets	3,299,692	3,290,102
Liabilities and Equity
Accounts payable and accruals	236,710	230,703
Current maturities of long-term debt	27,727	21,625
Asset retirement obligation	47,897	43,386
Deferred tax liability	143
Derivative liability	25,176	37,893
Current maturities of other long-term obligations	113,364	86,521
Total current liabilities	451,017	420,128
Long-term debt	1,946,586	1,857,784
Other long-term obligations	438,207	472,500
Asset retirement obligation	114,649	123,472
Deferred tax liability	7,107	16,956
Derivative liability	17,445	6,425
Total liabilities	2,975,011	2,897,265
Commitments and contingencies (Note 13)
Temporary equity:
Redeemable noncontrolling interest	115,405	140,851
8% convertible perpetual preferred stock: $0.001 par value; 785,189 issued and outstanding at June 30, 2011; None issued at December 31, 2010; Liquidation value of $78.5 million	68,174
Shareholders' equity:
8% convertible perpetual preferred stock: $0.001 par value, 10,000,000 shares authorized; 2,339,811 issued and outstanding at June 30, 2011; 1,400,000 issued and outstanding at December 31, 2010. Liquidation value of $234.0 million and $140.0 million at June 30, 2011 and December 31, 2010, respectively.	224,583	140,000
Common stock: $0.001 par value, 100,000,000 shares authorized; 51,691,526 issued and 51,615,686 outstanding at June 30, 2011; 51,347,163 issued and 51,271,323 outstanding at December 31, 2010	52	51
Additional paid-in capital	538,778	570,739
Accumulated deficit	(527,721)	(356,866)
Accumulated other comprehensive loss	(93,679)	(101,027)
Treasury stock, at cost	(911)	(911)
Total shareholders' equity	141,102	251,986
Total liabilities and equity	$ 3,299,692	$ 3,290,102