Atp Oil & Gas (ATPGQ) 10-Q 2012 Q1 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-Q

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

For the quarterly period ended March 31, 2012

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 May 1, 2012 was 52,159,849.

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

TABLE OF CONTENTS

	Page
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements (Unaudited)
Consolidated Balance Sheets: March 31, 2012 and December 31, 2011	3
Consolidated Statements of Operations: For the three months ended March 31, 2012 and 2011	4
Consolidated Statements of Comprehensive Loss: For the three months ended March 31, 2012 and 2011	5
Consolidated Statements of Cash Flows: For the three months ended March 31, 2012 and 2011	6
Consolidated Statements of Temporary Equity and Shareholders’ Equity: For the three months ended March 31, 2012 and 2011	7
Notes to Consolidated Financial Statements	8
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	26
Item 3. Quantitative and Qualitative Disclosures about Market Risks	41
Item 4. Controls and Procedures	42
PART II. OTHER INFORMATION	43
Item 1. Legal Proceedings	43
Item 6. Exhibits	43

2

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

ATP OIL  & GAS CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(In Thousands, Except Shares Data)

(Unaudited)

	March 31, 2012			December 31, 2011
Assets
Current assets:
Cash and cash equivalents	$	224,743		$	65,678
Restricted cash		15,040			20,113
Accounts receivable (net of allowance of $0 and $225, respectively)		85,430			70,628
Deferred tax asset		2,655			480
Derivative asset		—			2,194
Other current assets		18,222			28,050
Total current assets		346,090			187,143
Oil and gas properties (using the successful efforts method of accounting):
Proved properties		5,049,543			4,875,232
Unproved properties		24,691			22,945
		5,074,234			4,898,177
Less accumulated depletion, depreciation, impairment and amortization		(1,853,185	)		(1,760,756	)
Oil and gas properties, net		3,221,049			3,137,421
Restricted cash		10,000			10,000
Deferred financing costs, net		37,874			40,873
Other assets, net		23,386			13,337
Total assets	$	3,638,399		$	3,388,774
Liabilities and Equity
Current liabilities:
Accounts payable and accruals	$	295,604		$	265,620
Current maturities of long-term debt		36,630			33,848
Asset retirement obligation		53,047			52,536
Deferred tax liability		—			138
Derivative liability		117,483			68,816
Current maturities of other long-term obligations		111,246			113,657
Total current liabilities		614,010			534,615
Long-term debt		2,115,483			1,976,157
Other long-term obligations		594,427			451,797
Asset retirement obligation		119,059			115,981
Deferred tax liability		41,737			27,493
Derivative liability		1,122			522
Total liabilities		3,485,838			3,106,565
Commitments and contingencies (Note 13)
Temporary equity:
Redeemable noncontrolling interest		115,819			115,820
8% convertible perpetual preferred stock: $0.001 par value; 790,957 shares and 806,847 shares issued and outstanding and liquidation value of $79.1 million and $80.7 million at March 31, 2012 and December 31, 2011, respectively		71,186			70,055
Shareholders’ equity:
8% convertible perpetual preferred stock: $0.001 par value, 10,000,000 shares authorized; 2,314,043 shares and 2,318,153 shares issued and outstanding and liquidation value of $231.4 million and $231.8 million at March 31, 2012 and December 31, 2011, respectively.		219,550			222,681
Common stock: $0.001 par value, 100,000,000 shares authorized; 52,127,262 issued and 52,051,422 outstanding at March 31, 2012; 52,034,547 issued and 51,958,707 outstanding at December 31, 2011		52			52
Additional paid-in capital		527,103			529,669
Accumulated deficit		(687,665	)		(548,765	)
Accumulated other comprehensive loss		(92,573	)		(106,392	)
Treasury stock, at cost		(911	)		(911	)
Total shareholders’ equity (deficit)		(34,444	)		96,334
Total liabilities and equity	$	3,638,399		$	3,388,774

See accompanying notes to consolidated financial statements.

3

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(In Thousands, Except Per Share Amounts)

(Unaudited)

	Three Months Ended March 31,
	2012			2011
Oil and gas production revenues	$	146,613		$	166,500
Costs, operating expenses and other:
Lease operating		26,905			32,407
Exploration		389			—
General and administrative		17,956			9,736
Depreciation, depletion and amortization		84,906			79,320
Impairment of oil and gas properties		1,202			—
Accretion of asset retirement obligation		3,804			3,664
Drilling interruption costs		—			18,498
(Gain) loss on abandonment		(364	)		1,269
		134,798			144,894
Income from operations		11,815			21,606
Other income (expense):
Interest income		40			57
Interest expense, net		(73,854	)		(75,485	)
Derivative expense		(58,971	)		(50,262	)
		(132,785	)		(125,690	)
Loss before income taxes		(120,970	)		(104,084	)
Deferred income tax expense		(10,551	)		(9,142	)
Net loss		(131,521	)		(113,226	)
Less income attributable to the redeemable noncontrolling interest		(7,379	)		(3,563	)
Less convertible preferred stock dividends		(6,179	)		(2,758	)
Net loss attributable to common shareholders	$	(145,079	)	$	(119,547	)
Net loss per share attributable to common shareholders:
Basic	$	(2.83	)	$	(2.34	)
Diluted	$	(2.83	)	$	(2.34	)
Weighted average number of common shares:
Basic		51,328			51,020
Diluted		51,328			51,020

See accompanying notes to consolidated financial statements.

4

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS

(In Thousands)

(Unaudited)

	Three Months Ended March 31,
	2012			2011
Net loss	$	(131,521	)	$	(113,226	)
Other comprehensive income – foreign currency translation adjustment		13,819			8,415
Comprehensive loss		(117,702	)		(104,811	)
Less income attributable to the redeemable noncontrolling interest		(7,379	)		(3,563	)
Less convertible preferred stock dividends		(6,179	)		(2,758	)
Comprehensive loss attributable to common shareholders	$	(131,260	)	$	(111,132	)

See accompanying notes to consolidated financial statements.

5

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In Thousands)

(Unaudited)

	Three Months Ended March 31,
	2012			2011
Cash flows from operating activities –
Net loss	$	(131,521	)	$	(113,226	)
Adjustments to reconcile net loss to net cash provided by operating activities –
Depreciation, depletion and amortization		84,906			79,320
Impairment of oil and gas properties		1,202			—
Accretion of asset retirement obligation		3,804			3,664
Deferred income tax expense		10,551			9,142
Derivative expense		39,197			42,856
Stock-based compensation		1,599			1,431
Noncash interest expense		11,457			17,412
Other noncash items, net		29			78
Changes in assets and liabilities –
Accounts receivable and other current assets		7,606			17,826
Accounts payable and accruals		83,780			42,490
Other assets and liabilities		(11,707	)		(14,818	)
Net cash provided by operating activities		100,903			86,175
Cash flows from investing activities –
Additions to oil and gas properties		(197,205	)		(95,648	)
Decrease (increase) in restricted cash		5,073			(3,504	)
Net cash used in investing activities		(192,132	)		(99,152	)
Cash flows from financing activities –
Proceeds from first lien term loans		148,243			59,400
Proceeds from term loan facility–ATP Titan assets		—			45,000
Payments of term loans		(7,875	)		(5,000	)
Deferred financing costs		(50	)		(2,781	)
Proceeds from other long-term obligations		183,775			—
Payments of other long-term obligations		(59,218	)		(33,926	)
Distributions to noncontrolling interest		(9,253	)		(3,563	)
Preferred stock dividends		(6,313	)		(2,758	)
Derivative contracts, net		13,033			—
Other financings, net		(12,157	)		(16,854	)
Exercise of stock options/warrants		13			163
Net cash provided by financing activities		250,198			39,681
Effect of exchange rate changes on cash and cash equivalents		96			726
Increase in cash and cash equivalents		159,065			27,430
Cash and cash equivalents, beginning of year		65,678			154,695
Cash and cash equivalents, end of period	$	224,743		$	182,125
Noncash investing and financing activities –
Decrease in noncash property additions	$	90,946		$	23,392

See accompanying notes to consolidated financial statements.

6

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF

TEMPORARY EQUITY AND SHAREHOLDERS’ EQUITY

(In Thousands)

(Unaudited)

		$(134,444)			$(134,444)			$(134,444)		$(134,444)
	Three Months Ended March 31,
	2012						2011
	Shares			Amount			Shares		Amount
Temporary Equity:
Redeemable Noncontrolling Interest
Balance, beginning of period				$	115,820				$	140,851
Income attributable to the redeemable noncontrolling interest					7,379					3,563
Limited partner distributions					(7,380	)				(3,563	)
Balance, end of period				$	115,819				$	140,851
8% Convertible Perpetual Preferred Stock
Balance, beginning of period		807		$	70,055			—	$	—
Shareholders’ equity transfers		(16	)		1,131			—		—
Balance, end of period		791		$	71,186			—	$	—
Shareholders’ Equity:
8% Convertible Perpetual Preferred Stock
Balance, beginning of period		2,318		$	222,681			1,400	$	140,000
Conversion to common stock		(20	)		(2,000	)		—		—
Temporary equity transfers		16			(1,131	)		—		—
Balance, end of period		2,314			219,550			1,400		140,000
Common Stock
Balance, beginning of period		51,959			52			51,268		51
Conversion of preferred stock		90			—			—		—
Issuance of common stock – exercise of stock options		3			—			31		—
Restricted stock, net of forfeitures		—			—			108		—
Balance, end of period		52,052			52			51,407		51
Paid-in Capital
Balance, beginning of period					529,669					570,739
Conversion of preferred stock					2,000					—
Issuance of common stock – exercise of stock options/warrants					14					163
Preferred stock dividends					(6,179	)				(2,758	)
Stock-based compensation					1,599					1,431
Balance, end of period					527,103					569,575
Accumulated Deficit
Balance, beginning of period					(548,765	)				(356,866	)
Net loss					(131,521	)				(113,226	)
Less income attributable to the redeemable noncontrolling interest					(7,379	)				(3,563	)
Balance, end of period					(687,665	)				(473,655	)
Accumulated Other Comprehensive Loss
Balance, beginning of period					(106,392	)				(101,027	)
Other comprehensive income					13,819					8,415
Balance, end of period					(92,573	)				(92,612	)
Treasury Stock, at Cost
Balance, beginning of period		76			(911	)		76		(911	)
Balance, end of period		76			(911	)		76		(911	)
Total Shareholders’ Equity (Deficit)				$	(34,444	)			$	142,448

See accompanying notes to consolidated financial statements.

7

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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. 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 Security and Exchange Commission’s definition of proved reserves.

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. In April 2012, we began drilling on the first of these exploratory 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 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 2011 Annual Report on Form 10-K. The results of operations for the three months ended March 31, 2012 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.

Note 2 — Recent Accounting Pronouncements

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.

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 unprecedented 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. Because of the moratoriums and permitting delays, it has taken until the first quarter of 2012 for us to bring to production the three additional wells at the Telemark Hub and the two wells planned for the Gomez Hub have been postponed. The new Telemark wells 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. We are currently

8

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

recompleting this well in hopes of bringing on a new sand and increasing production; however, this operation which in mid-March had been expected to be completed in the first quarter of 2012 has encountered downhole difficulties and is now expected to be completed in the second quarter of 2012. 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 overall production and operating cash flow growth in 2012 due to new production from our Clipper property and from projected increases at our Telemark Hub. Production in the first quarter of 2012 is lower than in the fourth quarter of 2011 primarily due to the Telemark well recompletion discussed above which required us to take the well offline and normal production declines. 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.)

As of March 31, 2012, we had a working capital deficit of $267.9 million. To preserve our development momentum in the negative working capital environment that we experienced throughout 2011, we increased our term loans, issued convertible perpetual preferred stock, granted net profits interests (“NPIs” discussed below) to certain of our vendors, sold NPIs and dollar-denominated overriding royalty interests (“Overrides” discussed below) in our properties to investors, and entered into prepaid swaps against our future production that provided cash proceeds to us at closing. We 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 begin during 2013 with production commencing in 2014. A similar arrangement is in place for the Octabuoy topside equipment, which is being constructed by the same company in China. We have continued this practice of managing capital and seeking financing proceeds in a negative working capital environment during the first quarter of 2012. We increased our term loans, sold NPIs and Overrides in our properties to investors, and entered into prepaid swaps against our future production that provided cash proceeds to us at closing.

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 planned operations for the remainder of 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.

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 effect 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. Despite continued production delays, we believe we can continue to meet our obligations for at least the next twelve months through a

9

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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 12, “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 severe 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 material 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. 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. 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 requirements.

10

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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 material adverse effect on our financial position, results of operations, cash flows, the quantities of oil and gas reserves that we can economically produce, and may restrict our ability to obtain additional financing or to meet the contractual requirements of our debt and other obligations.

Note 4 — Impairment of Oil and Gas Properties

During the first three months of 2012, we recognized impairment expense of $1.2 million on certain older Gulf of Mexico properties related to adjustments to fully depleted assets.

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 March 31, 2012 and December 31, 2011, for U.S., Netherlands, and Israel 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. We recognized deferred tax assets only to the extent we expect to be able to offset deferred tax liabilities. 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. Accordingly, the U.K. rate increase has been reflected in the income tax provision for the three months ended March 31, 2012 (but not as of March 31, 2011), and 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 March 31, 2012 and December 31, 2011. We recognized income tax expense related to our U.K. operations of $10.6 million and $9.1 million, respectively, for the three months ended March 31, 2012 and 2011. The worldwide effective income tax rates for the three months ended March 31, 2012 and 2011 were (8.7%) and (8.8%), respectively.

Note 6 — Long-term Debt

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

	March 31, 2012			December 31, 2011
First lien term loans, net of unamortized discount of $8,878 and $2,460, respectively,	$	353,286		$	204,703
Senior second lien notes, net of unamortized discount of $4,321 and $4,671, respectively,		1,495,679			1,495,329
Term loan facility –ATP Titanassets, net of unamortized discount of $15,322 and $16,373, respectively,		303,148			309,973
Total debt		2,152,113			2,010,005
Less current maturities		(36,630	)		(33,848	)
Total long-term debt	$	2,115,483		$	1,976,157

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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 our Credit Facility with an initial balance of $150.0 million and bearing interest at an annual rate of 11.0% to replace the previous credit facility. Initial proceeds of the Credit Facility were $144.3 million, net of original issue discount and transaction fees. In February 2011, we entered into Incremental Loan Assumption Agreement and Amendment No. 1, relating to our Credit Facility, dated as of June 18, 2010 to, among other things, decrease the interest rate on the entire balance outstanding to 9%. Additional borrowings were $60.0 million ($58.0 million, net of transaction costs and discount). On March 9, 2012, we entered into the Amendment which provided for an increase to the initial principal amount of the Credit Facility to $365.0 million. The Amendment also reduced the interest rate of the Credit Facility to a floating rate of 8.75% calculated based on LIBOR (floor of 1.5%) plus 7.25%. The other terms of the Credit Facility were essentially unchanged by the Amendment. Quarterly principal payments are required equal to 0.5% of remaining principal balance until June 18, 2014 and the remaining principal balance is due January 15, 2015. 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 Titan LLC financing discussed below.

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 Titan LLC, a wholly owned and operated subsidiary which we consolidate in our financial statements, and transferred to it our 100% ownership of theATP 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

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ATP OIL & GAS CORPORATION AND SUBSIDIARIES

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(Unaudited)

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 theATP 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 Company remains operator and 100% owner of theATP 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 11.8% and $1.8 billion, respectively, at March 31, 2012. Accrued interest payable was $82.2 million and $37.7 million at March 31, 2012 and December 31, 2011, respectively.

Note 7 — Other Long-term Obligations

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

	March 31, 2012			December 31, 2011
Net profits interests	$	298,944		$	336,669
Dollar-denominated overriding royalty interests		214,387			42,324
Gomez pipeline obligation		71,110			71,676
Vendor deferrals – Gulf of Mexico		15,071			17,493
Vendor deferrals – North Sea		103,579			94,710
Other		2,582			2,582
Total		705,673			565,454
Less current maturities		(111,246	)		(113,657	)
Other long-term obligations	$	594,427		$	451,797

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 investors in exchange for cash proceeds.

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 is 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

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(Unaudited)

contributed by these vendors or the cash proceeds contributed by the investor 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 and our net interest increases accordingly. Because NPIs are granted on proved properties where production is reasonably assured, they are reflected 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 63%, or $189.8 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 the first quarter of 2012, we sold, for an aggregate of $185.0 million, limited-term dollar-denominated overriding royalty interests (“Overrides”) in our Gomez Hub and Clipper properties similar to Overrides sold previously. 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 Overrides will increase or decrease accordingly. If there is no production from a property during a payment period, no payment is 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 March 31, 2012, if there is sufficient production from a certain property, we will incur up to $5.8 million of contingent interest costs through the remaining life of the Override. We expect approximately 74%, or $159.8 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 theATP 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 the Company in future periods within the same calendar year whenever fees owed during a month exceed the minimum due. We remain the operator of the pipeline and are responsible for all of the related operating costs. As a result of the retained asset retirement obligation and the purchaser’s option to convey the pipeline 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 over 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 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 defer the final payments until April 2013. As of March 31, 2012 $103.6 million has been accrued and, as construction continues, we expect this amount to increase to $210.1 million of which $125.0 million is due in April 2013 and $85.1 million is due upon delivery of the topside utility module which is expected in the fourth quarter of 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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Effective Interest Rate– The weighted average effective interest rate on our other long-term obligations set forth above was 18.5% and 18.9% at March 31, 2012 and December 31, 2011, respectively.

Note 8 — Preferred Stock

In September 2009, we issued 1.4 million shares of convertible preferred stock (“Series A 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 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.

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 $90.00 fair value 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.

During the first quarter of 2012 an aggregate 20,000 shares of Series A Preferred Stock were converted into 90,090 shares of common stock.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 9 — Asset Retirement Obligation

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

	Three Months Ended March 31,
	2012			2011
Asset retirement obligation, beginning of period	$	168,517		$	166,858
Liabilities incurred		–			1,268
Liabilities settled		(278	)		(3,461	)
Accretion of asset retirement obligation		3,804			3,664
Changes in estimates		63			627
Total asset retirement obligation		172,106			168,956
Less current portion		(53,047	)		(41,955	)
Total long-term asset retirement obligation, end of period	$	119,059		$	127,001

Note 10 — Stock–Based Compensation

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

	Three Months Ended March  31,
	2012		2011
Stock options		598		451
Restricted stock		1,001		980

There were no options granted during the three-month period ended March 31, 2012. The fair values of options granted during the three-month period ended March 31, 2011 were estimated at the date of grant using a Black-Scholes option-pricing model assuming no dividends and with the following weighted average assumptions:

	Three Months Ended March  31, 2011
Volatility		85	%
Expected term (in years)		3.8
Risk-free rate		1.8	%
Weighted average fair value of options – grant date	$	17.94

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ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

The following table sets forth a summary of option transactions for the three months ended March 31, 2012:

	Number of Options			Weighted Average Grant Price		Aggregate Intrinsic Value (1) ($000)		Weighted Average Remaining Contractual Life
								(in years)
Outstanding at beginning of period		1,678,237		$	19.40
Canceled		(7,887	)		29.80
Exercised		(2,625	)		5.28	$	4
Outstanding at end of period		1,667,725			19.38	$	566		2.5
Vested and expected to vest		1,457,493			20.10	$	480		2.5
Options exercisable at end of period		789,899			26.41	$	328		1.5

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

At March 31, 2012, unrecognized compensation expense related to nonvested stock option grants totaled $2.7 million. Such unrecognized expense will be recognized as vesting occurs over a weighted average period of 2.5 years.

At March 31, 2012, unrecognized compensation expense related to restricted stock totaled $4.3 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 three months ended March 31, 2012:

	Number of Shares			Weighted Average Grant-date Fair Value		Aggregate Intrinsic Value (1) ($000)
Nonvested at beginning of period		832,029		$	11.74
Vested		(123,967	)		14.60
Nonvested at end of period		708,062			11.24	$	5,204

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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 March 31,
	2012			2011
Net loss attributable to common shareholders:
Net loss attributable to common shareholders	$	(145,079	)	$	(119,547	)
Add impact of assumed preferred stock conversions (if-converted method)		—			—
Net loss attributable to common shareholders and impact of assumed conversions	$	(145,079	)	$	(119,547	)
Weighted average shares outstanding:
Weighted average shares outstanding - basic		51,328			51,020
Effect of potentially dilutive securities - stock options and warrants		—			—
Nonvested restricted stock		—			—
Preferred stock		—			—
Weighted average shares outstanding - diluted		51,328			51,020
Net loss per share attributable to common shareholders:
Basic	$	(2.83	)	$	(2.34	)
Diluted	$	(2.83	)	$	(2.34	)

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

	Three Months Ended March 31,
	2012		2011
Net loss attributable to common shareholders:
Preferred stock dividends	$	6,179	$	2,758
Weighted average shares outstanding:
Common stock equivalents		252		477
Assumed conversion of preferred stock		14,077		6,306
Out-of-the-money stock options		1,299		663

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 12 — Derivative Instruments and Risk Management Activities

At March 31, 2012, 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 of 2012	Swaps		2,268,750		97.36		(39,546	)		—
2013	Swaps		1,002,500		107.22		(2,028	)		(211	)
Remainder of 2012	Prepaid Swaps (2)		574,500		—		(66,287	)		—
Remainder of 2012	Basis Swap (3)		754,000		11.71		(2,528	)		—
2013	Basis Swap (3)		783,000		4.44		(636	)		(911	)
Remainder of 2012	Swaption (4)		365,000		96.50		(4,268	)		—
Total							(115,293	)		(1,122	)
Natural Gas (MMBtu)
North Sea
Remainder of 2012	Swaps		1,375,000		8.88		(1,993	)		—
2013	Swaps		180,000		11.28		(186	)		—
Gulf of Mexico
Remainder of 2012	Calls		2,750,000		5.37		(11	)		—
Total							(2,190	)		—
Total Liability							(117,483	)		(1,122	)

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

(2) In March 2012, we entered into certain commodity price derivative contracts which have provided us with cash advances of $29.5 million and obligate us to pay market prices at the time of settlement. These contracts are similar to those we entered into in 2011.

(3) In March 2012, we entered into certain commodity price derivative contracts which fix for us the basis differential between West Texas Intermediate oil and Louisiana Light Sweet oil at specified amounts. These contracts help us to align more closely the existing commodity price derivative contracts we have entered into with the actual price we receive for our production.

(4) In January 2012, we entered into certain commodity price derivative contracts which give the counterparty the right, for a period of time, to bind us in agreed-upon oil price swap contracts in exchange for a premium paid to us. The oil price swap contracts to which we would be bound settle the same as other swaps we currently have and would be accounted for similarly. Should the counterparty elect not to bind us to the swap contract, the option to do so terminates and there is no further financial exposure to either party.

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(Unaudited)

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 was 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 provided us with $87.9 million of cash advances from the counterparty and obligated 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.

During the three months ended March 31, 2012, we paid net cash settlements of $49.0 million related to our derivatives. Additional information about derivatives is presented in Note 15 “Fair Value Measurements”. Our derivative expense is based entirely on nondesignated derivatives and consists of the following (in thousands):

	Three Months Ended March 31,
	2012		2011
Losses from:
Settlements of contracts	$	5,517	$	7,406
Early terminations of contracts		10,696		—
Unrealized losses on open contracts		42,758		42,856
Derivative expense	$	58,971	$	50,262

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. We may be required

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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 March 31, 2012, the aggregate amount of such contingent commitments related to unmet operational milestones was $8.1 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, we have up to an aggregate of $2.5 billion of various insurance coverages with individual policy limits ranging from $1 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 incidents 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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

negative environmental incidents 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 material 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 workers’ 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 the Company in the United States District Court for the Southern district of New York alleging the Company 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. The Company provided for this judgment in the financial statements as of December 31, 2010. Subsequently, Bison gave notice that it would appeal the judgment. On April 3, 2012 the Court of Appeals entered a Summary Order confirming the Company’s position that a re-trial should not be granted. Unless further appealed by Bison, the case will now go back to the Trial Court for hearings on the amount of expenses and interest.

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 March 31, 2012, either individually or in the aggregate, will have a material adverse effect on our financial condition, results of operations or cash flows.

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ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 14 — Segment Information

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

For the Three Months Ended –	Gulf of Mexico		North Sea			Mediterranean Sea			Total
March 31, 2012:
Revenues	$	143,117	$	3,496		$	—		$	146,613
Depreciation, depletion and amortization		82,101		2,805			—			84,906
Impairment of oil and gas properties		1,202		—			—			1,202
Income (loss) from operations		14,627		(1,948	)		(864	)		11,815
Interest income		40		—			—			40
Interest expense, net		73,854		—			—			73,854
Derivative expense		57,404		1,567			—			58,971
Income tax expense		—		10,551			—			10,551
Additions to oil and gas properties		45,376		127,137			3,544			176,057
Total assets		2,940,667		683,798			13,934			3,638,399
March 31, 2011:
Revenues	$	160,947	$	5,553		$	—		$	166,500
Depreciation, depletion and amortization		75,498		3,822			—			79,320
Income (loss) from operations		22,277		(671	)		—			21,606
Interest income		43		14			—			57
Interest expense, net		75,485		—			—			75,485
Derivative expense		47,509		2,753			—			50,262
Income tax expense		—		9,142			—			9,142
Additions to oil and gas properties		13,090		77,743			—			90,833
Total assets		2,879,899		447,180			—			3,327,079

23

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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 three months ended March 31, 2012 (in thousands):

	U.S. Gas Fixed- Price Physicals			U.S. Gas Calls			U.S. Oil Swaps(1)			U.S. Oil Swaptions(2)			U.K. Gas Swaps			Total
Balance at beginning of period	$	2,194		$	(64	)	$	(69,061	)	$	—		$	(213	)	$	(67,144	)
Derivative gains (losses) included in earnings		281			52			(53,186	)		(4,135	)		(1,983	)		(58,971	)
Sales		—			—			(30,702	)		(10,829	)		—			(41,531	)
Settlements and terminations		(2,475	)		—			40,803			10,696			17			49,041
Balance at end of period	$	—		$	(12	)	$	(112,146	)	$	(4,268	)	$	(2,179	)	$	(118,605	)
Changes in unrealized gain (loss) included in derivative income (expense) relating to derivatives still held at March 31, 2012	$	—		$	52		$	(41,124	)	$	(1,083	)	$	(1,588	)	$	(43,743	)

(1) In 2011 and 212, we entered into certain off-market oil swap derivative contracts which provide us with $117.4 million of cash advances from the counterparty and obligate us to pay market prices at the time of settlement. Also included here is activity for oil price basis swaps.

(2) In January 2012, we entered into certain commodity price derivate contracts which give the counterparty the right, for a period of time, to bind us in agreed-upon oil price swap contracts in exchange for a premium paid to us. See Note 12, “Derivative Instruments and Risk Management Activities.”

The following table sets forth a reconciliation of changes in the fair value of these financial assets (liabilities) during the three months ended March 31, 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)		576			(3	)		(52,081	)		4,849			171			(3,774	)		(50,262	)
Premium received		—			(2,133	)		—			—			—			—			(2,133	)
Settlements		(1,128	)		—			5,089			2,923			(829	)		1,351			7,406
Balance at end of period	$	(263	)	$	(2,136	)	$	(74,511	)	$	(4,255	)	$	—		$	(6,454	)	$	(87,619	)
Changes in unrealized gain (loss) included in derivative income (expense) relating to derivatives still held at March 31, 2011	$	410		$	(3	)	$	(51,276	)	$	3,343		$	—		$	(4,099	)	$	(51,625	)

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

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ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Qualitative Disclosures about Fair Value Measurements

Commodity Derivatives - The fair values of our derivative contracts are classified as Level 3 because they are 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. The pricing variables are sensitive to market volatility as well as changes in future price forecasts and regional price differences. Significant changes in the quoted forward prices for commodities generally lead to corresponding changes in the fair value measurement of our oil and gas derivative contracts. Significant changes in the volatility factors utilized in our option-pricing model can cause significant changes in the fair value measurements of our oil and gas derivative contracts.

Fair Value of Debt –The estimated fair value of our long-term debt is $1.8 billion at March 31, 2012. These estimated fair values are classified as Level 2 because in our calculation the unadjusted quoted prices for recent sales of our debt are from markets which are not active.

Quantitative Disclosures about Unobservable Inputs for Level 3 Fair Value Measurements at March 31, 2012

Instrument Type	Estimated Fair Value of Liability (in thousands)		Valuation Technique	Significant Unobservable Input	Oil - $/Bbl Gas - $/MMbtu
Oil swaps/prepaid swaps	$	108,073	Discounted cash flow	NYMEX oil price forward curve	101.57 – 105.33
				Argus oil price forward curve	107.93 – 125.58
Oil basis swaps		4,075	Discounted cash flow	NYMEX oil price forward curve	101.57 – 105.33
				WTI vs Argus differential	6.35 – 20.26
Oil swaption		4,268	Option model	NYMEX oil price forward curve	101.57 – 105.33
				Oil price volatility curve	28%
Natural gas swaps		2,178	Discounted cash flow	NBP natural gas price forward curve	9.60 – 12.80
Natural gas calls		11	Option model	NBP natural gas price forward curve	2.13 – 3.88
				Natural gas price volatility curve	0% – 53%

Note 16 — Subsequent Events

Our evaluation has identified no matters which require disclosure as events subsequent to March 31, 2012.

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ATP OIL & GAS CORPORATION AND SUBSIDIARIES

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

Executive Overview

General

ATP Oil & Gas Corporation is engaged 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 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 Securities and Exchange Commission’s 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 (“East Mediterranean”). In the East Mediterranean our licenses relate to exploratory prospects where drilling has occurred nearby and hydrocarbons have been discovered by others. In April 2012, we began drilling on the first of these exploratory licenses.

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

• significant undeveloped reserves or nearby discoveries;

• close proximity to developed markets for oil and natural gas;

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

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

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

In the Gulf of Mexico and the North Sea, our focus is on acquiring properties that are noncore or nonstrategic to the seller for a variety of reasons. For example, larger oil companies from time to time adjust their capital spending or shift their focus to exploration prospects they believe offer greater reserve potential. Some projects may provide lower economic returns to a company due to the cost structure and focus of that company. Also, due to timing or budget constraints, a company may be unwilling or unable to develop a property before the expiration of the lease. With our cost structure and acquisition strategy, it is not unusual for us to acquire a property at a cost that is less than the exploration and development costs incurred by the previous owner. This strategy, coupled with our expertise in our areas of focus and our ability to develop projects, tends to make our oil and gas property acquisitions more financially attractive to us than to the seller. Given our strategy of acquiring properties that contain proved reserves, or where previous drilling by others indicates to us the presence of recoverable hydrocarbons, our operations typically are lower risk than exploration-focused Gulf of Mexico and North Sea operators.

Practically all of our properties have previously defined and targeted reservoirs, eliminating from our development plan the time necessary in typical exploration efforts to locate and determine the extent of oil and gas reservoirs. Since we operate almost all of the properties in which we acquire a working interest, we are able to influence the plans for and timing of a project’s development; however, our ability to exert this influence is also dependent on external factors beyond our control.

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During the first quarter of 2012 we placed on production the fourth well (the Mississippi Canyon “MC” 942 A-3), at the Telemark Hub. This well had originally been scheduled to begin production in late 2010 but was delayed due to the moratorium that was imposed on drilling in the Gulf of Mexico related to the Deepwater Horizon incident. This is the fourth well to be placed on production at the Telemark Hub and is the last one in the initial development phase. After placing this fourth well on production, a recompletion operation was begun on another well, the MC 941 A-2, at the Telemark Hub to establish production from another productive sand. This operation, which was originally expected to be completed in the first quarter of 2012, is now expected to be completed during the second quarter of 2012. We have been notified by Shell Pipeline Company LP, the operator of the Mars pipeline, that it intends to temporarily shut in the pipeline to allow for the tie-in of a new offsetting platform. As a result, we estimate production at our Telemark Hub could be shut-in for up to two weeks during the second quarter of 2012.

Construction of the Octabuoy continued in the first quarter 2012. The hull and the utility portion of the topsides are being constructed in China and the process module of the topsides is being constructed in Louisiana. The Octabuoy is scheduled to be deployed into the North Sea where it will serve as the floating production facility for our Cheviot project beginning in 2014. As discussed below, 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 defer the final payments until April 2013.

During the first quarter we made the final preparations required before drilling our first well in the Israel portion of the deepwater Eastern Mediterranean. We operate this exploratory well with an initial 40% ownership. The well was spudded on April 29, 2012. Initial results are expected during the third quarter of 2012.

We also closed several financings during the first quarter of 2012. We increased the size of our first lien facility by $155 million and reduced the interest rate from a fixed 9.0% to a floating 8.75% (LIBOR floor of 1.5% plus a margin of 7.25%). We also added four new net profits interests (discussed below) and overriding royalty interests (discussed below) totaling $185.0 million. Additional details of these transactions can be found inLiquidity and Capital Resources.

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 unprecedented 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. Because of the moratoriums and permitting delays, it has taken until the first quarter of 2012 for us to bring to production the three additional wells at the Telemark Hub and the two wells planned for the Gomez Hub have been postponed. The new Telemark wells 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. We are currently recompleting this well in hopes of bringing on a new sand and increasing production; however, this operation which in mid-March had been expected to be completed in the first quarter of 2012 has encountered downhole difficulties and is now expected to be completed in the second quarter of 2012. 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 overall production and operating cash flow growth in 2012 due to new production from our Clipper property and from projected increases at our Telemark Hub. Production in the first quarter of 2012 is lower than in the fourth quarter of 2011 primarily due to the Telemark well recompletion discussed above which required us to take the well offline and normal production declines. 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.)

As of March 31, 2012, we had a working capital deficit of $267.9 million. To preserve our development momentum in the negative working capital environment that we experienced throughout 2011, we increased our term loans, issued convertible perpetual preferred stock, granted net profits interests (“NPIs” discussed

27

below) to certain of our vendors, sold NPIs and dollar-denominated overriding royalty interests (“Overrides” discussed below) in our properties to investors, and entered into prepaid swaps against our future production that provided cash proceeds to us at closing. We 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 begin during 2013 with production commencing in 2014. A similar arrangement is in place for the Octabuoy topside equipment, which is being constructed by the same company in China. We have continued this practice of managing capital and seeking financing proceeds in a negative working capital environment during the first quarter of 2012. We increased our term loans, sold NPIs and Overrides in our properties to investors, and entered into prepaid swaps against our future production that provided cash proceeds to us at closing.

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 planned operations for the remainder of 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.

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 effect 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. Despite continued production delays, 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 12, “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

28

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 severe 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 material 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. 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. 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 requirements.

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 material adverse effect on our financial position, results of operations, cash flows, the quantities of oil and gas reserves that we can economically produce, and may restrict our ability to obtain additional financing or to meet the contractual requirements of our debt and other obligations.

Results of Operations

Three Months Ended March 31, 2012 Compared to Three Months Ended March 31, 2011

For the three months ended March 31, 2012 and 2011 we reported net loss attributable to common shareholders of $145.1 million and $119.5 million, or $2.83 and $2.34 per diluted share, respectively.

Oil and Gas Production Revenues

Revenues presented in the table and the discussion below represent revenues from sales of oil and natural gas production volumes. The table below also includes oil and natural gas production revenues from amortization of deferred revenue in the first quarter of 2011 related to the second quarter 2008 sale of a limited-term overriding royalty interest. The table below does not reflect any production volumes associated with those revenues.

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	Three Months Ended March 31,				% Change from  2011 to 2012
	2012		2011
Production:
Oil and NGL (MBbl)		1,257		1,600		(21	%)
Natural gas (MMcf)		4,473		4,449		1	%
Total (MBoe)		2,002		2,341		(14	%)
Gulf of Mexico (MBoe)		1,937		2,234
North Sea (MBoe)		65		107
Revenues from production (in thousands):
Oil and NGL	$	130,948	$	144,634		(9	%)
Natural gas		15,665		21,866		(28	%)
Total	$	146,613	$	166,500		(12	%)
Average realized sales price:
Oil and NGL (per Bbl)	$	104.17	$	90.40		15	%
Natural gas (per Mcf)		3.50		4.91		(29	%)
Gulf of Mexico (per Mcf)		3.00		4.30
North Sea (per Mcf)		8.81		8.57
Oil, NGL and natural gas (per Boe)		73.23		71.10		3	%
Gulf of Mexico (per Boe)		73.89		72.04
North Sea (per Boe)		53.77		51.90

Revenues from production in the first three months of 2012 are 12% lower than the first three months of 2011 primarily due to a 14% decrease in production partially offset by a 15% increase in oil sales price. The production decrease occurred in the Gulf of Mexico where we have normal production declines at our Gomez and Telemark Hubs and a well temporarily shut-in for recompletion at Telemark through the second quarter. Partially offsetting these decreases is production from the fourth well at Telemark which was brought on in February 2012 and approximately 0.1 MMBoe from a royalty relief adjustment ($3.0 million benefit) related to 2011 production. The higher average realized sales price for oil is due to increased commodity market prices.

Lease Operating

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

	Three Months Ended March 31,				% Change from 2011 to 2012
	2012		2011
Recurring operating expenses	$	23,163	$	24,981		(7	%)
Workover expenses		3,742		7,426		(50	%)
Lease operating	$	26,905	$	32,407		(17	%)
Recurring operating expenses per Boe	$	11.57	$	10.67		8	%
Gulf of Mexico		11.22		10.65		5	%
North Sea		21.77		11.07		97	%

Lease operating expense for the first quarter of 2012 decreased overall by $5.5 million compared to 2011. The decrease in recurring lease operating expense was primarily due to the lower production from the Gomez Hub. The workover expenses during the first quarter of 2012 were primarily due to hull repairs at our MC 711 property. The workover expenses during the first quarter of 2011 were primarily due to hydrate remediation activities and hull repair work at our Atwater Valley 63 property and MC 711 properties, respectively. Per unit costs changed primarily due to the effect of changing production volumes on fixed costs.

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General and Administrative

General and administrative expenses are overhead-related expenses, including employee compensation, legal and accounting fees, insurance, and investor relations expenses. General and administrative expense was as follows:

	Three Months Ended March 31,				% Change from 2011 to 2012
	2012		2011
General and administrative (in thousands)	$	17,956	$	9,736		84	%
Per Boe		8.97		4.16		116	%

General and administrative expense in the first quarter of 2012 increased $8.2 million compared to the first quarter of 2011 primarily due to $3.8 million of organization and startup costs of operations in Israel and other international prospect generation costs and bonuses totalling $4.4 million awarded to executives by our Board of Directors.

Depreciation, Depletion and Amortization

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

	Three Months Ended March 31,				% Change from 2011 to 2012
	2012		2011
DD&A (in thousands)	$	84,906	$	79,320		7	%
Per Boe		42.40		33.88		25	%
Gulf of Mexico		42.38		33.79		25	%
North Sea		43.18		35.73		21	%

DD&A expense for the first quarter of 2012 increased $5.6 million compared to the same period during 2011 primarily due to a per unit increase in the Gulf of Mexico. The per unit increase in the Gulf of Mexico is primarily a result of higher costs incurred at our Telemark Hub and other more recent developments relative to some of our older properties.

Impairment of Oil and Gas Properties

During the first quarter of 2012, we recognized impairment expense of $1.2 million on certain older Gulf of Mexico properties related to adjustments to fully depleted assets.

Interest Expense, Net

Interest expense, net of amounts capitalized, decreased to $73.9 million in the first quarter of 2012 compared to $75.5 million in the first quarter of 2011. Interest expense in the first quarter of 2012 and 2011 is net of capitalized interest of $10.4 million and $5.0 million, respectively, related to our Cheviot development in the North Sea. The increase in interest, before amounts capitalized, is primarily due to: (i) an approximate $220 million increase in our aggregate average balance outstanding of debt and other long term obligations in the first quarter of 2012 as compared to the same period in 2011. Partially offsetting the effect of this increase is the weighted average interest rate which decreased to 12.7% in the first quarter of 2012 compared to 13.2% in the first quarter of 2011 (see Note 6, “Long-term Debt” and Note 7, “Other Long-term Obligations” to the Consolidated Financial Statements).

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Derivative Expense

Derivative expense is related to net losses associated with our oil and gas price derivative contracts and is as follows (in thousands):

	Three Months Ended March 31,
	2012		2011
Gulf of Mexico
Realized losses	$	16,196	$	6,055
Unrealized losses		41,208		41,454
		57,404		47,509
North Sea
Realized losses		17		1,351
Unrealized losses		1,550		1,402
		1,567		2,753
Total
Realized losses		16,213		7,406
Unrealized losses		42,758		42,856
	$	58,971	$	50,262

Income Tax Benefit (Expense)

We recorded income tax expense of $10.6 million during the first quarter of 2012 resulting in an overall effective tax rate of (8.7%). In each jurisdiction, the rates were determined based on our expectations of net income or loss for the year, taking into consideration permanent differences. As of March 31, 2012, for U.S., Netherlands, and Israel 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. In the comparable quarter of 2011 we recorded income tax expense of $9.1 million resulting in an overall effective tax rate of (8.8%).

Income Attributable to the Redeemable Noncontrolling Interest

Income attributable to the redeemable noncontrolling interest represents the 49% Class A limited partner interest in the earnings of ATP-IP. The amount of $7.4 million in the first quarter of 2012 is an increase from $3.6 million in the first quarter of 2011 primarily because in 2011 we entered a period under the agreements when all of the partnership income and 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 us, as the owner of the general partner and subordinated limited partner 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.

Convertible Preferred Stock Dividends

Convertible preferred stock dividends represent declared cash dividends due for outstanding shares which were issued in September 2009 ($140.0 million liquidation value) and June 2011 ($172.5 million liquidation value) which accrue cumulative preferred dividends at the annual rate of 8% of the liquidation value and are payable in either cash or stock at the Company’s option. We anticipate continuing to pay these dividends in cash.

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Liquidity and Capital Resources

Historically, we have funded our acquisition and development activities through a combination of bank borrowings, proceeds from equity offerings, cash from operations, the sale or conveyance of interests in selected properties, vendor financings, and proceeds of forward sales of our production in the financial derivatives market. Our ongoing cash requirements consist primarily of servicing our debt and other obligations and funding development of our oil and gas reserves. During the three months ended March 31, 2012, we paid cash for capital expenditures for oil and gas properties of approximately $197.2 million and we obtained additional financing from term loans and other sources as discussed below.

Production in the first quarter of 2012 is lower than in the fourth quarter of 2011 primarily due to a workover operation on a well at our Telemark Hub and due to normal production declines. In late February 2012, we completed the Mississippi Canyon (MC) 942 A-3 well, the fourth well at our Telemark Hub. Shortly thereafter, we began a workover operation at the MC 941 A-2 well, where we have been required to temporarily shut in production while an additional oil sand, the B sand, is completed. The completion operation is expected to conclude during second quarter 2012, and we expect a substantial increase in the well’s productivity afterward. Upon completion of this operation, we also intend to conduct a sleeve shift operation at the MC 941 A-1 well, which is expected to add production of approximately 1.5 MBoe per day during second quarter 2012. We expect the sleeve shift operation at MC 941 A-1 to be substantially less complex and therefore faster than the recompletion operation at MC 941 A-2.

Despite actual and anticipated production delays, we believe we can continue to fund our projected capital expenditures and our existing obligations, including our long-term debt and other obligations (which include those to the noncontrolling interest and to our preferred shareholders), for at least the next twelve months, using projected cash flows from operations, cash on hand, asset monetizations which include the sale of working interests, NPIs and Overrides, and if necessary, additional forward sales of our production in the financial derivative markets. In certain cases, we will also continue to work with certain vendors to extend out the timing of certain payments to preserve cash. With certain limitations, we may also delay certain anticipated development expenditures to further preserve cash if necessary. While some of the transactions we had planned for the remainder of 2012 have been completed or committed, others are still incomplete. Our ability to consummate those transactions is dependent on a number of factors including our production results, commodity prices and general market conditions; therefore there is no assurance that we will be able to repeat these types of transactions in the future if they are required to meet our short-term liquidity needs. Our longer-term liquidity is also dependent on our production levels and the prevailing prices for oil and natural gas which have historically been very volatile. To mitigate future price volatility, we may continue to hedge the sales price of a portion of our future production.

The size of our operations and our capital expenditures budget limit the number of properties that we can develop in any given year, and a substantial portion of our current production is concentrated among relatively few wells located offshore in the Gulf of Mexico and in the North Sea, which are characterized by rapid production declines. 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 severe weather. Any unanticipated significant disruption to, or decline in, our current production levels or negative changes in current commodity prices or operating cost levels could have a material adverse effect on our financial position, results of operations and cash flows and our ability to meet our commitments as they come due. 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, however; there is no assurance that these alternative sources will be available should these risks and uncertainties materialize.

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As discussed, we have conveyed to certain vendors and investors NPIs and Overrides in our Telemark Hub, Gomez Hub and Clipper oil and gas properties in exchange for development services, equipment and cash. We have also negotiated with certain other vendors involved in the development of the Telemark Hub to partially defer payments for periods up to a year. These arrangements allow us to match our development cost cash flows with those from production. During the first quarter of 2012, we sold for an aggregate $185.0 million certain Overrides in our Gomez Hub and our Clipper property, which is currently being developed. Similar to previous Overrides sold by us, the purchasers receive a designated portion of the revenues produced at the Gomez Hub and Clipper 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. During the three months ended March 31, 2012, we paid $89.3 million of principal and interest related to our other long-term obligations, which is significantly increased from the comparable period in 2011 due to increased production, higher oil prices and the additional conveyances. SeeOther Long-term Obligations discussion below.

In March 2012, we entered into a commodity price derivatives contract which provided us with a cash advance of $29.5 million and obligated us to pay market prices at the time of settlement.

In the 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 defer the final payments until April 2013. As of March 31, 2012 $103.6 million has been accrued and, as construction continues, we expect this amount to increase to $210.1 million of which $125.0 million is due in April 2013 and $85.1 million is due upon delivery of the topside utility module which is expected in the fourth quarter of 2013.

By the end of 2012, our plan calls for us to incur $400 million to $500 million in total capital expenditures, excluding capitalized interest, of which $50 million to $70 million is expected to be contributed by vendors through existing NPI or deferral programs. As operator of most of our projects under development, within certain constraints we have the ability to influence the timing and extent of most of our capital expenditures should future market conditions warrant. We plan to finance anticipated expenses, debt service, development and abandonment requirements for the remainder of 2012 with cash on hand and funds generated by operating activities and, potentially, proceeds from other capital market transactions, other financings and possible sales of assets.

Cash Flows

	Three Months Ended March 31,
	2012			2011
Cash provided by (used in) (in thousands):
Operating activities	$	100,903		$	86,175
Investing activities		(192,132	)		(99,152	)
Financing activities		250,198			39,681

As of March 31, 2012, we had a working capital deficit of approximately $267.9 million, a decrease of approximately $79.6 million from December 31, 2011. This deficit is the cumulative result of our capital expenditures exceeding our cash flows from operating and financing activities over the last three years as we invested heavily in infrastructure and wells expected to increase production and cash flow from operations in future periods. With the increased production we are forecasting and our efforts to seek partners for certain of our major capital intensive projects, we expect this working capital deficit to shrink during the remainder of 2012 and into 2013.

While we believe we can continue to meet our obligations for at least the next twelve months, 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, 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 effect 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 more of the types financing transactions we have completed in the past; however, there is no assurance that we will be able to repeat these types of transactions even if they are required.

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Cash provided by operating activities during the first three months of 2012 and 2011 was $100.9 million and $86.2 million, respectively. Cash flow from operating activities has increased primarily due to increased working capital partially offset by decreased cash flows from operations and derivatives.

Cash used in investing activities was $192.1 million and $99.2 million during the first three months of 2012 and 2011, respectively. During the first three months of 2012, cash expended in the Gulf of Mexico, North Sea and Mediterranean Sea for additions to oil and gas properties was approximately $76.9 million, $117.3 million and $3.0 million, respectively. During the first three months of 2011, cash expended in the Gulf of Mexico and North Sea for additions to oil and gas properties was approximately $31.2 million and $64.4 million, respectively.

Cash provided by financing activities was $250.2 million and $39.7 million during the first three months of 2012 and 2011, respectively. The amount in 2012 is primarily related to $332.0 million of proceeds from term loans and other long-term obligations and $13.0 million, net from derivative contracts, partially offset by $94.9 million payments of other long-term liabilities, to the noncontrolling interest and of term loans and other financings. The amount in the first three months of 2011 is primarily related to $104.4 million of proceeds from term loans, partially offset by $55.8 million payments of other long-term liabilities, term loans and other financings.

Long-term Debt

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

	March 31,			December 31,
	2012			2011
First lien term loans, net of unamortized discount of $8,878 and $2,460, respectively,	$	353,286		$	204,703
Senior second lien notes, net of unamortized discount of $4,321 and $4,671, respectively,		1,495,679			1,495,329
Term loan facility –ATP Titanassets, net of unamortized discount of $15,322 and $16,373, respectively,		303,148			309,973
Total debt		2,152,113			2,010,005
Less current maturities		(36,630	)		(33,848	)
Total long-term debt	$	2,115,483		$	1,976,157

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.

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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 our Credit Facility with an initial balance of $150.0 million and bearing interest at an annual rate of 11.0% to replace the previous credit facility. Initial proceeds of the Credit Facility were $144.3 million, net of original issue discount and transaction fees. In February 2011, we entered into Incremental Loan Assumption Agreement and Amendment No. 1, relating to our Credit Facility, dated as of June 18, 2010 to, among other things, decrease the interest rate on the entire balance outstanding to 9%. Additional borrowings were $60.0 million ($58.0 million, net of transaction costs and discount). On March 9, 2012, we entered into the Amendment which provided for an increase to the initial principal amount of the Credit Facility to $365.0 million. The Amendment also reduced the interest rate of the Credit Facility to a floating rate of 8.75% calculated based on LIBOR (floor of 1.5%) plus 7.25%. The other terms of the Credit Facility were essentially unchanged by the Amendment. Quarterly principal payments are required equal to 0.5% of remaining principal balance until June 18, 2014 and the remaining principal balance is due January 15, 2015. 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 Titan LLC financing discussed below.

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 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 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.

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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 11.8% and $1.8 billion, respectively, at March 31, 2012. Accrued interest payable was $82.2 million and $37.7 million at March 31, 2012 and December 31, 2011, respectively.

Other Long-term Obligations

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

	March 31,			December 31,
	2012			2011
Net profits interests	$	298,944		$	336,669
Dollar-denominated overriding royalty interests		214,387			42,324
Gomez pipeline obligation		71,110			71,676
Vendor deferrals – Gulf of Mexico		15,071			17,493
Vendor deferrals – North Sea		103,579			94,710
Other		2,582			2,582
Total		705,673			565,454
Less current maturities		(111,246	)		(113,657	)
Other long-term obligations	$	594,427		$	451,797

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 investors in exchange for cash proceeds.

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 is 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 investor 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 and our net interest increases accordingly. Because NPIs are granted on proved properties where production is reasonably assured, they are reflected 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 63%, or $189.8 million of the NPIs to be repaid over the next 12 months based on anticipated production, commodity prices and operating costs.

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Dollar-denominated Overriding Royalty Interests – During the first quarter of 2012, we sold, for an aggregate of $185.0 million, limited-term dollar-denominated overriding royalty interests (“Overrides”) in our Gomez Hub and Clipper properties similar to Overrides sold previously. 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 Overrides will increase or decrease accordingly. If there is no production from a property during a payment period, no payment is 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 March 31, 2012, if there is sufficient production from a certain property, we will incur up to $5.8 million of contingent interest costs through the remaining life of the Override. We expect approximately 74%, or $159.8 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 theATP 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 the Company in future periods within the same calendar year whenever fees owed during a month exceed the minimum due. We remain the operator of the pipeline and are responsible for all of the related operating costs. As a result of the retained asset retirement obligation and the purchaser's option to convey the pipeline 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 over 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 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 defer the final payments until April 2013. As of March 31, 2012 $103.6 million has been accrued and, as construction continues, we expect this amount to increase to $210.1 million of which $125.0 million is due in April 2013 and $85.1 million is due upon delivery of the topside utility module which is expected in the fourth quarter of 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 18.5% and 18.9% at March 31, 2012 and December 31, 2011, respectively.

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Contractual Obligations

The following table summarizes certain contractual obligations at March 31, 2012 (in thousands):

			Less than		1 – 3		3 – 5		More than
	Total		1 year		years		years		5 years
First lien term loans	$	362,164	$	3,614	$	358,550	$	—	$	—
Interest on first lien term loans (1)		88,428		31,958		56,470		—		—
Senior second lien notes		1,500,000		—		—		1,500,000		—
Interest on senior second lien notes (1)		549,219		178,125		356,250		14,844		—
Term loan facility –ATP Titan assets		318,470		32,657		70,000		70,000		145,813
Interest on term loan facility –ATP Titan assets (1)		105,999		26,104		43,234		30,974		5,687
Asset retirement obligations		172,106		62,918		31,028		—		78,160
Other long-term obligations (2)		425,990		121,030		286,627		18,333		—
Other trade commitments		6,875		—		6,875		—		—
Noncancelable operating leases		1,694		1,068		626		—		—
Total contractual obligations	$	3,530,945	$	457,474	$	1,209,660	$	1,634,151	$	229,660

(1) Interest is based on rates and principal repayment requirements in effect at March 31, 2012.

(2) Of these amounts, $189.8 million is accrued at March 31, 2012 of which $70.0 million is to be paid in less than one year with the balance due in one to three years.

Excluded from the table above are the following:

• NPIs and Overrides of $298.9 million and $214.4 million, respectively, as of March 31, 2012 that are payable only from the future cash flows of specified properties. The ultimate amount and timing of the payments will depend on production from the properties and future commodity prices and operating costs. We expect approximately 68% or $349.6 million of the NPIs and Overrides to be repaid over the next 12 months based on projected production, commodity prices and operating costs.

• Dividends on our 8% convertible perpetual preferred stock, which are approximately $24.8 million per year. These dividends are payable in cash or stock at the Company's option, although covenants with our creditors may prevent us from paying cash in the future.

• ATP-IP is currently obligated to distribute effectively all of its cash earnings to the noncontrolling interest until approximately $74 million has been paid, which represents the unpaid portion of the original investment plus a return on that investment. The ultimate amount and timing of the payments will depend on the oil and gas volumes which flow across theATP Innovator production platform. We expect approximately $30 million or 41% of the $74 million payments discussed above to be repaid over the next 12 months.

• Obligations under commodity derivative contracts, which at March 31, 2012 represent an aggregate net liability of $117.5 million related to the 12 months following March 31, 2012 and $1.1 million related to the following period, based on period-end market prices. See additional discussion of commodity derivative contracts in Note 12, Derivative Instruments and Price Risk Management Activities.

• Contingent interest on certain Overrides which may total $5.8 million, the ultimate amount and timing of which will depend on production from the properties and future commodity prices.

• Contingent consideration of $8.1 million to be paid by us upon achieving specified operational milestones because the ultimate amount and timing of the payments will depend on production from the specified properties and future commodity prices.

• 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

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we control our nominations, we are subject to the risk we may be required to prepay or ultimately pay transportation on undelivered volumes. The ultimate amount and timing of any payments is uncertain and dependent upon our production levels. At current production levels, the minimum annual obligation under these agreements is approximately £0.6 million per year, or approximately $1.0 million at March 31, 2012.

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Commitments and Contingencies

Management is periodically faced with uncertainties, the outcomes of which are not within its control and will not be known for some time. We are involved in actions from time to time, which if determined adversely, could have a material adverse impact on our financial position, results of operations and cash flows. Management, with the assistance of counsel makes estimates, if determinable, of our probable liabilities and records such amounts in the consolidated financial statements. Such estimates may be the minimum amount of a range of probable loss when no single best estimate is determinable. Disclosure is made, when determinable, of any additional possible amount of loss on these claims, or if such estimate cannot be made, that fact is disclosed. Along with our counsel, we monitor developments related to these legal matters and, when appropriate, we make adjustments to recorded liabilities to reflect current facts and circumstances. See Note 13, “Commitments and Contingencies” to Consolidated Financial Statements for additional discussion.

Accounting Pronouncements

See the discussion in Note 2, “Recent Accounting Pronouncements” to Consolidated Financial Statements.

Critical Accounting Policies

Our discussion and analysis of our financial condition and results of operations are based on consolidated financial statements which have been prepared in accordance with generally accepted accounting principles in the United States of America. The preparation of these financial statements requires us to make estimates and judgments that affect the reported amounts or assets, liabilities, revenues and expenses. We believe that certain accounting policies affect our more significant judgments and estimates used in the preparation of our consolidated financial statements. Critical accounting policies have not changed materially from those disclosed on our 2011 Annual Report on Form 10-K .

Item 3.Quantitative and Qualitative Disclosures about Market Risks

Interest Rate Risk

We are exposed to changes in interest rates only on our Credit Facility and our ATP Titan Facility as described in Management’s Discussion and Analysis of Financial Condition and Results of Operations: Liquidity and Capital Resources. For the Credit Facility, each 1% change in LIBOR above the floor rate of 1.5% equates to approximately $3.0 million of additional annual interest expense. For the Term Loan Facility, each 1% change in LIBOR above the floor rate of 0.75% equates to approximately $3.7 million of additional annual interest expense on these obligations. Otherwise we have no exposure to changes in interest rates because the interest rates on our other long-term debt instruments are fixed.

Foreign Currency Risk

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

Commodity Price Risk

Our revenues, profitability and future growth depend substantially on prevailing prices for oil and natural gas. Prices also affect the amount of cash flow available for capital expenditures and our ability to borrow and raise additional capital. Lower prices may also reduce the amount of oil and natural gas that we can economically produce. We currently sell a portion of our oil and natural gas production under market price contracts. We periodically use derivative instruments to hedge our commodity price risk. We hedge a portion of our projected oil and natural gas production through a variety of financial and physical arrangements intended to support oil and natural gas prices at targeted levels and to manage our exposure to price fluctuations. We may use futures contracts, swaps, prepaid swaps, put options, price collars, call options and fixed-price physical forward contracts to hedge our commodity prices. See Note 12, “Derivative Instruments and Risk Management Activities” to Consolidated Financial Statements. We do not hold or issue derivative instruments for speculative purposes.

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Item 4.Controls and Procedures

Evaluation of Disclosure Controls and Procedures

Our chief executive officer and chief financial officer have reviewed and evaluated the effectiveness of our disclosure controls and procedures, as defined in Exchange Act Rules13a-15(e) and 15d-15(e), as of March 31, 2012 (the “Evaluation Date”). Based on this evaluation, the chief executive officer and chief financial officer have concluded that the Company's disclosure controls and procedures were effective as of the Evaluation Date to ensure that information that is required to be disclosed by the Company in the reports it files or submits under the Exchange Act is (i) recorded, processed, summarized and reported, within the time periods specified in the Securities and Exchange Commission's rules and forms and (ii) accumulated and communicated to the Company's management, including our chief executive officer and chief financial officer, as appropriate to allow timely decisions regarding required disclosure.

Changes in Internal Control Over Financial Reporting

During the three months ended March 31, 2012, we have made no change to our internal controls over financial reporting that has materially affected, or is reasonably likely to materially affect, our internal controls over financial reporting.

Forward-looking Statements and Associated Risks

This Quarterly Report contains projections and other forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934. These projections and statements reflect the Company's current views with respect to future events and financial performance. No assurances can be given, however, that these events will occur or that these projections will be achieved and actual results could differ materially from those projected as a result of certain factors. A discussion of these factors is included in the Company's 2011 Annual Report on Form 10-K.

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PART II. OTHER INFORMATION

Item 1.Legal Proceedings

On January 29, 2010, Bison Capital Corporation (“Bison”) filed suit against the Company in the United States District Court for the Southern district of New York alleging the Company 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. The Company provided for this judgment in the financial statements as of December 31, 2010. Subsequently, Bison gave notice that it would appeal the judgment. On April 3, 2012 the Court of Appeals entered a Summary Order confirming the Company’s position that a re-trial should not be granted. Unless further appealed by Bison, the case will now go back to the Trial Court for hearings on the amount of expenses and interest.

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

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.

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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	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.
10.6	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.
10.7	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.
10.8	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.
10.9	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.
10.10	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.
10.11	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.
10.12	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.
10.13	Amendment and Restatement and Incremental Loan Assumption Agreement to the Credit Agreement, incorporated by reference to Exhibit 10.1 of ATP’s Form 8-K dated March 9, 2012.
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.
*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

* Filed herewith

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SIGNATURES

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

	ATP Oil & Gas Corporation
Date: May 10, 2012	By:	/s/ Albert L. Reese Jr.
		Albert L. Reese Jr.
		Chief Financial Officer

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