Atp Oil & Gas 10Q 2010 Q1 Quarterly report

Atp Oil & Gas (ATPGQ) Inactive 10-Q2010 Q1 Quarterly report

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended March 31, 2010

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

Commission file number: 001-32647

ATP OIL & GAS CORPORATION

(Exact name of registrant as specified in its charter)

Texas

76-0362774

(State or other jurisdiction of

incorporation or organization)

(I.R.S. Employer

Identification No.)

4600 Post Oak Place, Suite 200

Houston, Texas 77027

(Address of principal executive offices)

(Zip Code)

(713) 622-3311

(Registrant’s telephone number, including area code)

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

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

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

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 3, 2010 was 51,183,508.

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

TABLE OF CONTENTS


		Page
PART I. FINANCIAL INFORMATION

Item 1. Financial Statements (Unaudited)
Consolidated Balance Sheets: March 31, 2010 and December 31, 2009		3
Consolidated Statements of Operations: For the three months ended March 31, 2010 and 2009		4
Consolidated Statements of Cash Flows: For the three months ended March 31, 2010 and 2009		5
Consolidated Statements of Shareholders’ Equity and Noncontrolling Interest: For the three months ended March 31, 2010 and 2009		6
Consolidated Statements of Comprehensive Income (Loss): For the three months ended March 31, 2010 and 2009		7
Notes to Consolidated Financial Statements		8

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		22

Item 3. Quantitative and Qualitative Disclosures about Market Risks		31

Item 4. Controls and Procedures		32

PART II. OTHER INFORMATION		34

Item 1. Legal Proceedings		34

Item 1A. Risk Factors		34

PART I. FINANCIAL INFORMATION

Item 1.

Financial Statements

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(In Thousands, Except Share and Per Share Amounts)

(Unaudited)


	March 31,			December 31,
	2010			2009
Assets
Current assets:
Cash and cash equivalents	$	96,835		$	108,961
Restricted cash		45,981			10,504
Accounts receivable (net of allowance of $225 and $291, respectively)		56,255			52,551
Deferred tax asset		44,720			101,956
Derivative asset		12,389			1,321
Other current assets		11,840			10,615

Total current assets		268,020			285,908

Oil and gas properties (using the successful efforts method of accounting):
Proved properties		3,903,933			3,609,131
Unproved properties		13,200			13,910

		3,917,133			3,623,041
Less accumulated depletion, depreciation, impairment and amortization		(1,174,400	)		(1,137,269	)

Oil and gas properties, net		2,742,733			2,485,772

Furniture and fixtures (net of accumulated depreciation)		280			342
Deferred financing costs, net		23,191			16,378
Other assets, net		14,444			14,747

Total assets	$	3,048,668		$	2,803,147


Liabilities and Equity

Current liabilities:
Accounts payable and accruals	$	255,681		$	212,736
Current maturities of term loans		—			16,838
Asset retirement obligation		44,950			43,418
Derivative liability		20,478			16,216
Other current liabilities		26,664			23,094

Total current liabilities		347,773			312,302

Term loans		1,245,299			1,199,847
Other long-term obligations		510,386			274,942
Asset retirement obligation		108,329			106,781
Deferred tax liability		89,213			146,764
Derivative liability		8,938			7,646
Deferred revenue		8,717			19,336

Total liabilities		2,318,655			2,067,618

Commitments and contingencies (Note 12)

Temporary equity – redeemable noncontrolling interest		140,490			139,598


Shareholders’ equity:
8% convertible perpetual preferred stock: $0.001 par value, 10,000,000 shares authorized; 1,400,000 issued and outstanding at March 31, 2010 and December 31, 2009; at liquidation value		140,000			140,000
Common stock: $0.001 par value, 100,000,000 shares authorized; 51,210,266 issued and 51,134,423 outstanding at March 31, 2010; 50,755,310 issued and 50,679,470 outstanding at December 31, 2009		51			51
Additional paid-in capital		573,205			571,595
Accumulated deficit		(17,403	)		(19,317	)
Accumulated other comprehensive loss		(105,419	)		(95,487	)
Treasury stock, at cost		(911	)		(911	)

Total shareholders’ equity		589,523			595,931

Total liabilities and equity	$	3,048,668		$	2,803,147

See accompanying notes to consolidated financial statements.

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(In Thousands, Except Per Share Amounts)

(Unaudited)


	Three Months Ended March 31,
	2010			2009
Revenues:
Oil and gas production	$	93,029		$	68,256
Other		—			13,664

		93,029			81,920


Costs, operating expenses and other:
Lease operating		29,635			20,214
Exploration		712			174
General and administrative		11,509			11,103
Depreciation, depletion and amortization		36,001			39,398
Impairment of oil and gas properties		8,237			8,049
Accretion of asset retirement obligation		3,390			2,904
Loss on abandonment		151			997
(Gain) loss on exchange/disposal of properties		(11,974	)		148
Other, net		(946	)		—

		77,715			82,987

Income (loss) from operations		16,314			(1,067	)


Other income (expense):
Interest income		144			213
Interest expense, net		(12,219	)		(12,623	)
Derivative income		3,535			16,245

		(8,540	)		3,835


Income before income taxes		7,774			2,768


Income tax (expense) benefit:
Current		(553	)		(378	)
Deferred		(852	)		1,252

		(1,405	)		874


Net income		6,369			3,642
Less income attributable to the redeemable noncontrolling interest		(4,455	)		(2,006	)
Less convertible preferred stock dividends		(2,800	)		—

Net income (loss) attributable to common shareholders	$	(886	)	$	1,636


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

Basic	$	(0.02	)	$	0.05


Diluted	$	(0.02	)	$	0.05


Weighted average number of common shares:
Basic		50,450			35,618
Diluted		50,450			35,706

See accompanying notes to consolidated financial statements.

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In Thousands)

(Unaudited)


	Three Months Ended
	March 31,
	2010			2009
Cash flows from operating activities
Net income	$	6,369		$	3,642
Adjustments to reconcile net income to net cash provided by operating activities –
Depreciation, depletion and amortization		36,001			39,398
Impairment of oil and gas properties		8,237			8,049
Gain on nonmonetary property exchange		(11,974	)		—
Accretion of asset retirement obligation		3,390			2,904
Deferred income tax expense (benefit)		852			(1,252	)
Derivative (income) expense		(5,514	)		116
Stock-based compensation		1,848			2,195
Amortization of deferred revenue		(10,619	)		(11,359	)
Noncash interest expense		4,119			3,734
Other noncash items, net		90			1,210
Changes in assets and liabilities –
Accounts receivable and other assets		(15,992	)		17,720
Accounts payable and accruals		(11,338	)		(43,472	)

Net cash provided by operating activities		5,469			22,885


Cash flows from investing activities
Additions to oil and gas properties		(157,342	)		(234,452	)
Proceeds from disposal of oil and gas properties		2,053			—
Increase in restricted cash		(35,477	)		(13,500	)
Additions to furniture and fixtures		(7	)		(88	)

Net cash used in investing activities		(190,773	)		(248,040	)


Cash flows from financing activities
Proceeds from term loans		46,000			—
Payments of term loans		(17,310	)		(33,812	)
Deferred financing costs		(8,858	)		—
Net profits interests payments		(472	)		—
Sale of redeemable noncontrolling interest, net of costs		—			148,751
Limited partner distributions to noncontrolling interest		(3,563	)		—
Principal payments - pipeline transaction		(660	)		—
Proceeds from sales of net profits interests		50,000			—
Proceeds from dollar-denominated overriding royalty transaction (“Overrides”)		121,136			—
Principal payments – Overrides		(12,318	)		—
Preferred stock dividends		(2,856	)		—
Exercise of stock options		2,562			—

Net cash provided by financing activities		173,661			114,939


Effect of exchange rate changes on cash and cash equivalents		(483	)		(1,397	)


Decrease in cash and cash equivalents		(12,126	)		(111,613	)
Cash and cash equivalents, beginning of year		108,961			214,993

Cash and cash equivalents, end of period	$	96,835		$	103,380


Noncash investing and financing activities
Increase (decrease) in accrued property additions	$	146,357		$	(55,601	)
Net property addition - nonmonetary exchange		13,375			—
Asset retirement costs capitalized		1,062			—
Accrued limited partner distributions		—			11,846

See accompanying notes to consolidated financial statements.

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF

SHAREHOLDERS’ EQUITY AND NONCONTROLLING INTEREST

(In Thousands)

(Unaudited)


	Three Months Ended March 31,
	2010				2009
	Shares	Amount			Shares	Amount
Temporary Equity – Redeemable Noncontrolling Interest:

Balance, beginning of period		$	139,598			$	—
Sale of Class A Limited Partner Interest, net of formation costs							148,751
Income attributable to the redeemable noncontrolling interest			4,455				2,006
Limited partner distributions			(3,563	)			(11,846	)

Balance, end of period		$	140,490			$	138,911


Shareholders’ Equity:

8% Convertible Perpetual Preferred Stock, liquidation value
Balance, beginning of period	1,400	$	140,000		—	$	—

Balance, end of period	1,400		140,000		—		—


Common Stock
Balance, beginning of period	50,679		51		35,903		36
Issuance of common stock – exercise of stock options/warrants	362		—		—		—
Restricted stock, net of forfeitures	91		—		115		—

Balance, end of period	51,132		51		36,018		36


Paid-in Capital
Balance, beginning of period			571,595				400,334
Issuance of common stock – exercise of stock options/warrants			2,562				2
Preferred stock dividends			(2,800	)			—
Stock-based compensation			1,848				2,195

Balance, end of period			573,205				402,531


Retained Earnings (Accumulated Deficit)
Balance, beginning of period			(19,317	)			29,644
Net income			6,369				3,642
Less income attributable to the redeemable noncontrolling interest			(4,455	)			(2,006	)

Balance, end of period			(17,403	)			31,280


Accumulated Other Comprehensive Loss
Balance, beginning of period			(95,487	)			(112,754	)
Other comprehensive income (loss)			(9,932	)			2,654

Balance, end of period			(105,419	)			(110,100	)


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

Balance, end of period	76		(911	)	76		(911	)


Total Shareholders’ Equity		$	589,523			$	322,836

See accompanying notes to consolidated financial statements.

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(In Thousands)

(Unaudited)


	Three Months Ended
	March 31,
	2010			2009

Net income	$	6,369		$	3,642


Other comprehensive income (loss):
Reclassification adjustment for settled hedge contracts (net of taxes of $0 and ($147), respectively)		—			147
Changes in fair value of outstanding hedge positions (net of taxes of $0 and ($2,750), respectively)		—			2,750
Foreign currency translation adjustment		(9,932	)		(243	)

Other comprehensive income (loss)		(9,932	)		2,654


Comprehensive income (loss)		(3,563	)		6,296
Less comprehensive income attributable to the redeemable noncontrolling interest		(4,455	)		(2,006	)
Less preferred stock dividends		(2,800	)		—

Comprehensive income (loss) attributable to common shareholders	$	(10,818	)	$	4,290

See accompanying notes to consolidated financial statements.

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 1 — Organization

ATP Oil & Gas Corporation (“ATP”) was incorporated in Texas in 1991. We are engaged in the acquisition, development and production of oil and natural gas properties in the Gulf of Mexico and the U.K. and Dutch Sectors of the North Sea (the “North Sea”). We primarily focus our efforts on oil and natural gas properties where previous drilling has encountered reservoirs that appear to contain commercially productive quantities of oil and gas. Many of these properties contain proved undeveloped reserves that are economically attractive to us but are not strategic to major or large exploration-oriented independent oil and gas companies. Occasionally we will acquire properties that are already producing or where previous drilling has encountered reservoirs that appear to contain commercially productive quantities of oil and gas even though the reservoirs do not meet the Securities and Exchange Commission (“SEC”) definition of proved reserves.

The consolidated financial statements include our accounts, the accounts of our majority owned limited partnership, ATP Infrastructure Partners, L.P. (“ATP-IP”) and those of our wholly-owned subsidiaries; ATP Energy, Inc.; ATP Oil & Gas (UK) Limited, or “ATP (UK);” ATP Oil & Gas (Netherlands) B.V. and three wholly owned limited liability companies created to own our interests in ATP-IP. All intercompany transactions are eliminated in consolidation, and we separate in the accompanying statements the redeemable noncontrolling interest in ATP-IP.

The accompanying unaudited consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”) for interim financial information and reflect all adjustments (consisting of normal recurring adjustments) which are, in the opinion of management, necessary for a fair statement of the results of operations for the interim periods. The interim financial information and notes hereto should be read in conjunction with our 2009 Annual Report on Form 10-K. The results of operations for the quarter ended March 31, 2010 are not necessarily indicative of results to be expected for the entire year.

Fair Value of Financial Instruments

For cash and cash equivalents, receivables and payables, the carrying amounts approximate fair value because of the short maturity of these instruments. The interest rate on our term loans is variable and is based on London Interbank Offered Rates (“LIBOR”) subject to various minimums as discussed in Note 6 “Long-term Debt.” The fair value of the debt as of March 31, 2010 was approximately $1.3 billion.

Note 2 — Recent Accounting Pronouncements

Effective January 1, 2010, the Company partially adopted the provisions of FASB ASU No. 2010-06, “Improving Disclosures about Fair Value Measurements,” which amends ASC 820-10-50 to require new disclosures concerning (1) transfers into and out of Levels 1 and 2 of the fair value measurement hierarchy, and (2) activity in Level 3 measurements. In addition, ASU No. 2010-06 clarifies certain existing disclosure requirements regarding the level of disaggregation and inputs and valuation techniques and makes conforming amendments to the guidance on employers’ disclosures about postretirement benefit plans assets. The requirements to disclose separately purchases, sales, issuances, and settlements in the Level 3 reconciliation are effective for fiscal years beginning after December 15, 2010 (and for interim periods within such years). Accordingly, we will apply the disclosure requirements relative to the Level 3 reconciliation in the first quarter of 2011. There was no impact on our financial position, results of operations or cash flows as a result of the partial adoption of ASU No. 2010-06.

Note 3 — Risks and Uncertainties

As an independent oil and gas producer, our revenue, profitability, cash flows, and future rate of growth are substantially dependent on prevailing prices for oil and natural gas. Historically, the energy markets have been very volatile, and we expect such price volatility to continue. 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 long-term obligations.

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

reliability of this data can vary. Estimates of our oil and natural gas reserves and the costs and timing associated with developing these reserves are subject to change, which could materially impact the quantities of oil and natural gas that we ultimately produce. As of December 31, 2009, approximately 87% of our total proved reserves are undeveloped. Throughout the year, we intend to continue to develop these reserves, but there can be no assurance we will be successful. Development of these reserves may not yield the expected results, or the development may be delayed or the costs may exceed our estimates, any of which may materially affect our financial position, results of operations, cash flows and our ability to meet the requirements of our financing obligations.

We are also vulnerable to certain concentrations that could expose our revenues, profitability, cash flows and access to capital to the risk of a near-term severe impact. The size of our operations and our capital expenditures budget limit the number of properties that we can develop in any given year and a substantial portion of our current production is contributed from relatively few wells located offshore in the Gulf of Mexico and in the North Sea. In 2008 and 2009, a significant amount of time and money has been spent by us on our Telemark Hub development. Our 2010 results of operations, financial position and cash flows will be significantly impacted by the timing and success at this development, which began production at the end of the quarter. We have also recently conveyed to certain vendors and financial parties dollar-denominated net profits interests and overriding royalty interests in our Telemark Hub and Gomez Hub 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 until after production has begun. These net profits interests and deferrals, while they allowed development to continue, will burden the net cash flows available to us from Telemark Hub and Gomez Hub production activities until the obligations have been satisfied.

In addition to the numerous risks associated with offshore operations, some of which may not be covered by insurance, these properties are also characterized by rapid production declines, which require us to incur significant capital expenditures to replace declining production. Complications in the development of any single material well or infrastructure installation, including lack of sufficient capital, or if we were to experience operational problems, uninsured events, or prolonged adverse commodity prices resulting in the curtailment of production in any of these wells, our current and future production levels would be adversely affected, which may materially affect our financial condition, results of operations and cash flows.

Although we believe that we will have adequate liquidity to meet our future capital requirements, the factors described above create uncertainty. We consider the control and flexibility afforded by operating our properties under development to be key to our business plan and strategy. By operating our properties, we retain significant control over the development plans and their timing. Within certain constraints, we can conserve capital by delaying or eliminating capital expenditures. While postponing or eliminating capital projects will delay or reduce future cash flows from scheduled new production, this control and flexibility helps us to match our capital commitments to our available capital resources.

On Tuesday, April 20, 2010, a semi-submersible drilling rig operating in the deepwater Gulf of Mexico exploded, burned for two days and sank, resulting in an oil spill in Gulf of Mexico waters. In response to this crisis, the U.S. Secretary of the Interior, on May 6, 2010, announced a moratorium on U.S. offshore drilling permits issued after April 20, 2010 until May 28, 2010, when a report on the accident is expected to be completed. Such permits, among other required approvals, are necessary prior to commencement of offshore drilling operations.

We have ongoing and planned drilling operations in the deepwater Gulf of Mexico, some of which were permitted prior to April 20, 2010 and some of which are not yet permitted. The successful execution of our business plan depends on our ability to continue drilling for and producing hydrocarbons in the Gulf of Mexico. While the moratorium is scheduled to end later this month, we cannot predict when it will end. We cannot predict how federal and state authorities will further respond to the incident or whether additional changes in laws and regulations governing oil and gas operations in the Gulf of Mexico will result. It is possible that additional regulations or limitations may be imposed on us. Such regulations or limitations may require a change in the way we conduct our business, may increase our costs of doing business or may ultimately prohibit us from drilling for or producing hydrocarbons in the Gulf of Mexico. A prolonged interruption in our drilling or production operations would adversely affect our financial position, results of operations and cash flows.

Note 4 — Income Taxes

Income tax expense during interim periods is 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. We recognized income tax expense of $1.4 million and income tax benefit of $0.9 million for the three months ended March 31, 2010 and 2009, respectively. The worldwide effective tax rates for the first three months of 2010 and 2009 were 18.1% and (31.6%), respectively.

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

Note 5 — Oil and Gas Properties

Acquisitions and Dispositions

During the three months ended March 31, 2010, we were the apparent high bidder on U.S. Department of Interior Minerals Management Service leases for 100% of the working interests in the Ship Shoal (“SS”) Block 361 and the Garden Banks Block 782 (which is known as “Entrada” and which was awarded in April 2010). SS Block 361 is in close proximity to our SS Block 358 Hub. Entrada is in the vicinity of existing infrastructure owned by others.

During January 2010, we consummated a nonmonetary exchange of our 10% nonoperated working interest in Mississippi Canyon (“MC”) Block 800, for an incremental 50% working interest in MC Block 754, both proved undeveloped properties. The consolidated financial statements reflect the incremental interest acquired in MC Block 754 at fair value and removal of the carrying costs of MC Block 800, resulting in recognition of a $12.0 million gain.

Also during January 2010, we acquired a 100% working interest in MC Block 710, an exploratory prospect adjacent to our Gomez Hub in MC Block 711 and surrounding blocks, in exchange for the conveyance of an overriding royalty interest.

Impairment of Oil and Gas Properties

We recorded impairments during the three months ended March 31, 2010 and 2009 of $8.2 million and $8.0 million, respectively. These amounts represented the remaining carrying costs of those properties, and were primarily due to relinquishment of the leases. We also recorded a $1.0 million loss on abandonment related to the property impaired in 2009.

Note 6 — Long-term Debt

Term Loans consisted of the following (in thousands):


	March 31,			December 31,
	2010			2009
Term Loans – Tranche B-1	$	1,031,625		$	1,034,250
Term Loans – Asset Sale Facility		146,017			160,701
Term Loans – revolving credit facility		100,000			50,000
Unamortized discount		(32,343	)		(28,266	)

Total Term Loans		1,245,299			1,216,685
Less current maturities		—			(16,838	)

Total Term Loans - noncurrent	$	1,245,299		$	1,199,847

The Term Loans include a tranche of initially, $1.05 billion (“Tranche B-1”), a tranche of, initially, $600.0 million (the “Asset Sale Facility”) and a revolving credit facility for up to $50.0 million. The Term Loans were issued with an original issue discount of 2.5%. The interest rates on the Term Loans were based on a minimum 3.25% LIBOR plus a prescribed amount which varies as discussed below. The Term Loans were secured by substantially all of our oil and gas assets in the Gulf of Mexico and a pledge of 65% of the common stock of our wholly owned subsidiaries, ATP Oil & Gas (UK) Limited and ATP Oil and Gas (Netherlands) B.V. The combined effective annual interest rate under the Term Loans at March 31, 2010 was approximately 13.1%. During April 2010, the Term Loans were repaid in full with the proceeds of new borrowings as described below.

During November 2009, we entered into an amendment (the “First Amendment”) to the Term Loans to maintain compliance with our covenants as of December 31, 2009 and to provide additional flexibility during the period from October 1, 2009 through December 31, 2010 (the “Amendment Period”). Certain financial ratios were expanded in exchange for compensating changes in interest rates during the Amendment Period. We paid an initial fee of 0.5% to each of the lender group and the administrative agent of the outstanding balance of the Term Loans at closing plus related expenses for a total of $12.6 million for the First Amendment. A portion of these costs were capitalized.

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

On January 29, 2010, we entered into a second amendment (the “Second Amendment”) to the Term Loans to maintain compliance with our covenants as of December 31, 2009 and to provide us the right to issue unlimited indebtedness in the form of unsecured senior debt, provided that 75% of the net proceeds from any such additional indebtedness were used to repay the outstanding Term Loans. The calculation of trailing-twelve-months EBITDAX, as defined in the Term Loans, was expanded to include, for certain periods, amounts representing realized economic gains from certain property transactions that did not qualify for gain accounting treatment. We paid a fee of 0.5% of the outstanding balance of the Term Loans to the lender group and 0.25% of the outstanding balance of the Term Loans and Revolver to the administrative agent at closing, plus related expenses, for a total of $9.2 million, a portion of which was capitalized, for the Second Amendment.

In March 2010, we entered into a third amendment to the Term Loans to increase the maximum commitment under the revolving credit facility by $50.0 million. The original issue discount and related transaction costs of $4.2 million were capitalized. At March 31, 2010, there was $100 million outstanding under the revolving credit facility portion of the Term Loans.

During the first three months of 2010, we repaid a total of $14.7 million of the Asset Sale Facility with amounts received from our asset monetizations and financing transactions discussed below.

In April 2010, we entered into a first lien revolving credit facility (the “Credit Facility”) with an initial borrowing base of $100.0 million, due April 23, 2013, and issued senior second lien notes (the “Notes”) in an aggregate principal amount of $1.5 billion, due May 1, 2015 (collectively, the “Borrowings”). The Borrowings are currently collateralized by substantially all of our oil and gas properties in the Gulf of Mexico and a pledge of 65% of the common stock of our wholly owned subsidiary, ATP Oil & Gas (UK) Limited. We used proceeds from the Notes to repay the entire amount outstanding under the Term Loans.

The Credit Facility may be increased to $150.0 million, bears interest at a variable rate and imposes covenants on us to meet certain financial ratios, including (i) a minimum current ratio of not less than 0.8 to 1.0 for the remainder of 2010 and 1.0 to 1.0 thereafter, (ii) a total debt to EBITDAX ratio not to exceed 5.0 to 1.0, with subsequent adjustment to 3.0 to 1.0 and (iii) an EBITDAX to interest expense ratio initially of not less than 2.0 to 1.0. No event of default will occur if we are not in compliance with the financial covenants of the Credit Facility unless we have amounts outstanding under the facility. We must be in compliance with these covenants, however, in order for the lenders to be obligated to fund borrowings we request. We incurred costs of $2.1 million for the Credit Facility and there are no amounts outstanding under the Credit Facility as of May 3, 2010.

The Notes bear interest at 11.875% per annum, payable each May 1 and November 1 and contain customary covenants and restrictions that, among other things, limit the incurrence of additional indebtedness, mergers and consolidations, and certain restricted payments. In connection with the issuance of the Notes, we granted registration rights to the holder of the Notes and agreed to register the Notes with the SEC within 270 days of their initial issuance. The Notes were issued at 99.531% of their face amount to yield 12.0% and we incurred issuance costs of $60.1 million.

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 111.875%, 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 and 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.

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

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.

Note 7 — Other Long-term Obligations

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


	March 31, 2010			December 31, 2009
Net profits interests	$	269,399		$	180,819
Dollar-denominated overriding royalty interests		124,726			14,941
Gomez pipeline obligation		75,414			75,152
Vendor deferrals – Gulf of Mexico		17,045			7,490
Vendor deferrals - North Sea		47,884			17,053
Other		2,582			2,582

Total		537,050			298,037
Less current portion (included in other current liabilities)		(26,664	)		(23,095	)

Other long-term obligations	$	510,386		$	274,942

Net Profits Interests

During 2009, we granted dollar-denominated overriding royalty interests in the form of net profits interests (“NPIs”) in certain of our oil and gas properties in and around the Telemark Hub and Clipper to certain of our vendors in exchange for oil and gas property development services. The interests earned by the vendors will be paid solely from the net profits, as defined, of the subject properties. We accrue the present value of the NPIs as a liability on our consolidated balance sheet with an offsetting increase recorded as additions to oil and gas properties. As the NPI is earned, 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 reflected in interest expense net of amounts capitalized on the Consolidated Statement of Operations. The term of the NPIs will be dependent on the value of the services contributed by these vendors coupled with the estimated timing of production and future economic conditions, including commodity prices and operating costs. Because we have accounted for these NPI’s as financing obligations on our consolidated balance sheet, the reserves and production revenues associated with the NPIs are retained by the Company. A portion of the NPI balance relates to financing of property acquisitions prior to 2009. During the first three months of 2010, we granted additional NPIs and received cash proceeds of $49.5 million net of costs.

Dollar-denominated Overriding Royalty Interests

In October 2009, we sold a dollar-denominated overriding royalty interest (“Override”) in our Gomez Hub properties for $14.5 million, net of costs. During the three months ended March 31, 2010, we sold Overrides (primarily dollar-denominated) in future production from the Gomez Hub properties for $140 million ($121.1 million net of transaction costs and fourth quarter 2009 royalty payments). A total of $35.0 million of the proceeds was restricted pending the successful completion of a workover operation. At March 31, 2010, those funds are reflected on the accompanying balance sheet as restricted cash. During April, that restriction was lifted and the funds are now available. These Overrides obligate us to deliver proceeds from the future sale of hydrocarbons from the specified properties equal to the purchasers’ original investments plus an overall rate of return. The percentage of property revenues available to satisfy this obligation is dependent upon certain conditions specified in the agreement. Upon payment of the agreed dollar amounts, the ownership of the Overrides reverts to us. 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 and the reserves and production revenues are retained by the Company.

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

Gomez Pipeline Transaction

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

Vendor Deferrals

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

In the U.K. North Sea, development of our interest in the Cheviot field continues and we have arranged with the fabricator of the floating production and drilling facility to defer $99 million of payments until construction is complete, which is expected to be in 2011. As work is completed, we record obligations and related interest expense, net of amounts capitalized on the Consolidated Statement of Operations.

The weighted average effective interest rate on other long-term obligations was 16.9% at March 31, 2010.

Note 8 — 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,
	2010			2009
Asset retirement obligation, beginning of period	$	150,199		$	132,108
Liabilities incurred		1,409			36
Liabilities settled		(782	)		(1,521	)
Property dispositions		(242	)		(292	)
Accretion of asset retirement obligation		3,390			2,904
Changes in estimates		(695	)		618

Total asset retirement obligation		153,279			133,853
Less current portion		(44,950	)		(36,305	)

Total long-term asset retirement obligation, end of period	$	108,329		$	97,548

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

Note 9 — Stock–Based Compensation

We recognized stock option compensation expense of $0.8 million for each of the three months ended March 31, 2010 and 2009. We recognized restricted stock compensation expense of $1.1 million, and $1.4 million for the three months ended March 31, 2010 and 2009, respectively.

There were no options granted during the three months ended March 31, 2009. The fair values of options granted during the three months ended March 31, 2010 were estimated at the date of grant using a Black-Scholes option-pricing model assuming no dividends and with the following weighted average assumptions:


Weighted average volatility		79.5	%
Expected term (in years)		3.8
Risk-free rate		2.1	%
Weighted average fair value of options – grant date	$	10.79

The following table sets forth a summary of option transactions for the three months ended March 31, 2010:


	Number of Options		Weighted Average Grant Price		Aggregate Intrinsic Value (1) ($000)		Weighted Average Remaining Contractual Life
							(in years)
Outstanding at beginning of period	1,634,105		$	24.69
Granted	4,000			18.81
Forfeited	(7,480	)		19.09
Exercised	(12,681	)		5.28	$	182

Outstanding at end of period	1,617,944			24.85	$	4,904	2.6

Vested and expected to vest	1,449,398			24.88	$	4,217	2.5

Options exercisable at end of period	767,997			28.56	$	1,072	1.4

(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, 2010, unrecognized compensation expense related to nonvested stock option grants totaled $3.3 million. Such unrecognized expense will be recognized as vesting occurs over a weighted average period of 2.7 years.

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

At March 31, 2010, 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 1.9 years. The following table sets forth the changes in nonvested restricted stock for the three months ended March 31, 2010:


	Number of Shares		Weighted Average Grant-date Fair Value		Aggregate Intrinsic Value (1) ($000)
Nonvested at beginning of period	419,293		$	26.25
Granted	91,939			18.28
Forfeited	(2,181	)		8.84
Vested	(96,713	)		23.93

Nonvested at end of period	412,338			25.11	$	7,756

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

Note 10 — Earnings Per Share

Basic earnings per share (“EPS”) is computed by dividing net income or loss attributable to common shareholders by the weighted average number of common shares (other than nonvested restricted stock) outstanding during the period. Weighted average shares outstanding for diluted EPS also includes a hypothetical number of additional shares (“Common Stock Equivalents”) calculated assuming the exercise or conversion of all in-the-money options, warrants and convertible preferred stock and full vesting of restricted stock awards. Common Stock Equivalents are excluded from the computation of weighted average common shares outstanding when the per share effect is antidilutive. The impact of assumed conversion of preferred stock on net income is excluded from the computation of EPS when its impact is antidilutive. For the three months ended March 31, 2010 and 2009, 1.5 million and 1.8 million, respectively, Common Stock Equivalents were excluded from the diluted EPS calculation in the table below because their inclusion would have been antidilutive. For the three months ended March 31, 2010, preferred stock dividends of $2.8 million were excluded from the diluted EPS computation of net income (loss) attributable to common shareholders because their inclusion would have been antidilutive. A total of 6.3 million potential shares from the assumed conversion of preferred stock have been excluded because their effect would have been antidilutive.

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

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


	Three Months Ended March 31,
	2010			2009
Net income (loss) attributable to common shareholders	$	(886	)	$	1,636
Add impact of assumed preferred stock conversions (if-converted method)		—			—

Net income (loss) attributable to common shareholders and impact of assumed conversions	$	(886	)	$	1,636


Shares outstanding:
Weighted average shares outstanding - basic		50,450			35,618
Effect of potentially dilutive securities - stock options and warrants		—			—
Nonvested restricted stock		—			88
Preferred stock		—			—

Weighted average shares outstanding - diluted		50,450			35,706


Net income (loss) per share attributable to common shareholders:
Basic	$	(0.02	)	$	0.05

Diluted	$	(0.02	)	$	0.05

Note 11 — Derivative Instruments and Risk Management Activities

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

Gains and losses for derivatives which have not been designated as hedges are recorded as components of derivative income (expense) in our consolidated statement of operations. Gains and losses for derivatives which have been designated as hedges are recorded instead to accumulated other comprehensive income (“AOCI”) until the period in which the forecasted hedged transactions occur, at which time the gains and losses are reclassified from AOCI to the consolidated statement of operations as components of the revenue items to which they relate. Settlements of commodity derivative instruments are included in cash flows from operating activities in our consolidated statement of cash flows.

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

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


				Net Fair Value Asset (Liability) (2)
Period	Type	Volumes	Price	Current			Noncurrent
			$/Unit (1)	($000)			($000)

Oil (Bbl) –Gulf of Mexico
Remainder 2010	Puts	275,000	24.70	$	—		$	—

Remainder 2010	Swaps	1,192,000	77.00		(9,186	)		—
2011	Swaps	1,368,750	78.76		(2,198	)		(6,812	)

Remainder 2010	Swaps (3)	550,000	70.00		(7,540	)		—
2011	Swaps (3)	911,000	78.41		(1,554	)		(2,126	)

Total				$	(20,478	)	$	(8,938	)


Natural Gas (MMBtu)
North Sea
Remainder 2010	Fixed-price physicals	825,000	6.63	$	1,420		$	—

Remainder 2010	Swaps	1,375,000	5.47		765			—
2011	Swaps	450,000	5.47		(307	)		—

Gulf of Mexico
Remainder 2010	Fixed-price physicals	5,475,000	5.57		7,104			—
2011	Fixed-price physicals	900,000	5.42		54			—

Remainder 2010	Collars	4,125,000	4.75-7.95		3,018			—
2011	Collars	1,350,000	4.75-7.95		335			—

Total				$	12,389		$	—


Derivative asset				$	12,389		$	—
Derivative liability					(20,478	)		(8,938	)

Total				$	(8,089	)	$	(8,938	)

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

(2)	None of the derivatives outstanding are designated as hedges for accounting purposes.

(3)	These swaps include call options to allow us to participate in per barrel price increases above $110 and $111 in 2010 and 2011, respectively.

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

At December 31, 2009, we had the following derivative contracts in place:


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

2010	Swaps	733,000	79.76		(2,212	)		—
2011	Swaps	1,095,000	80.17		—			(5,625	)

2010	Swaps (3)	1,273,000	68.29		(13,402	)		—
2011	Swaps (3)	181,000	72.00		—			(1,508	)

Total				$	(15,612	)	$	(7,133	)

Natural Gas (MMBtu)
North Sea
2010	Fixed-price physicals	1,095,000	7.01	$	1,321		$	—

Gulf of Mexico
2010	Fixed-price physicals	4,525,000	5.58		(778	)		—

2010	Collars	4,575,000	4.68-7.86		173			—
2011	Collars	1,350,000	4.75-7.95		—			(512	)

Total				$	716		$	(512	)


Derivative asset				$	1,321		$	—
Derivative liability					(16,216	)		(7,646	)

Total				$	(14,895	)	$	(7,646	)

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

(2)	None of the derivatives outstanding are designated as hedges for accounting purposes.

(3)	These swaps include call options to allow us to participate in per barrel price increases above $99.34 and $115.00 in 2010 and 2011, respectively.

The following AOCI table shows where gains and losses (net of taxes) on cash flow hedge derivatives have been reported (in thousands):


	Three Months Ended March 31,
	2010		2009
AOCI for cash flow hedges - beginning of period	$	—	$	(2,877	)
Derivative gains		—		2,750
Losses reclassified from AOCI to oil and gas revenues		—		147

AOCI for cash flow hedges – end of period	$	—	$	20

During the three months ended March 31, 2010, we paid net cash settlements of $2.0 million of our price hedge derivatives. Our derivative income for the three months ended March 31, 2010 and 2009 is based entirely on nondesignated derivatives and consists of the following (in thousands):


	Three Months Ended March 31,
	2010			2009
Realized gains (losses) from:
Settlements of contracts	$	(2,069	)	$	13,627
Early terminations of contracts		—			2,734
Unrealized gains on open contracts		5,604			(116	)


Derivative income	$	3,535		$	16,245

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

Note 12 — Commitments and Contingencies

The development, production and sale of oil and natural gas in the Gulf of Mexico and in the North Sea are subject to extensive laws and regulations, including environmental laws and regulations. We may be required to make large expenditures to comply with environmental and other governmental regulations. Under these laws and regulations, we could be liable for personal injuries, property damage, oil spills, discharge of hazardous materials, remediation and clean-up costs and other environmental damages. Failure to comply with these laws and regulations also may result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties. Moreover, these laws and regulations could change in ways that substantially increase our costs. 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.

During the term of the Platform Use Agreement governing theATP Innovator, we are obligated to pay to ATP-IP, our consolidated partnership, a per unit fee for all hydrocarbons processed by theATP Innovator, subject to a minimum throughput fee of $53,000 per day. We may also be subject to a minimum fee of $53,000 per day for up to 180 days under certain circumstances, including if we fail to provide the minimum notification period before the Gomez Hub fields ceases production. We are responsible for all of the operating costs and periodic maintenance of theATP Innovator. We could also be required to repurchase the Class A limited partner interest if 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, 2010, the aggregate amount of such contingent commitments related to unmet operational milestones was $9.9 million.

In February 2010, Bison Capital Corporation filed suit against ATP alleging that fees totaling $102 million related to certain financing transactions had not been paid by ATP. We believe we have paid Bison Capital Corporation all amounts due under our 2004 agreement with them. ATP is currently preparing a response to the petition and plans to vigorously defend against these allegations.

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, 2010, either individually or in the aggregate, will have a material adverse effect on our financial condition, results of operations or cash flows.

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

Note 13 — Segment Information

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


For the Three Months Ended –	Gulf of Mexico			North Sea			Total

March 31, 2010:
Revenues	$	87,368		$	5,661		$	93,029
Depreciation, depletion and amortization		30,411			5,590			36,001
Income (loss) from operations		18,258			(1,944	)		16,314
Interest income		38			106			144
Interest expense, net		12,219			—			12,219
Derivative income		2,614			921			3,535
Income tax expense		1,405			—			1,405
Additions to oil and gas properties		280,417			24,871			305,288
Total assets		2,757,773			290,895			3,048,668

March 31, 2009:
Revenues	$	78,721		$	3,199		$	81,920
Depreciation, depletion and amortization		34,063			5,335			39,398
Income (loss) from operations		4,004			(5,071	)		(1,067	)
Interest income		213			—			213
Interest expense, net		12,623			—			12,623
Derivative income		12,167			4,078			16,245
Income tax (expense) benefit		(145	)		1,019			874
Additions to oil and gas properties		158,451			10,405			168,856
Total assets		2,047,377			240,059			2,287,436

Note 14 — Fair Value Measurements

Assets and Liabilities Measured at Fair Value on a Recurring Basis

The fair value of our derivative contracts is based on significant unobservable (or Level 3) 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, 2010 (in thousands):


	Gas Fixed- Price Physicals			Gas Price Collars			Oil Swaps			Oil Swaps⁽¹⁾			Oil Puts			Subtotal U.S.
U.S.

Balance at beginning of period	$	(778	)	$	(339	)	$	(7,837	)	$	(14,910	)	$	2		$	(23,862	)
Derivative income (expense)		8,354			3,692			(11,537	)		2,107			(2	)		2,614
Settlements and terminations		(418	)		—			1,177			1,582			—			2,341


Balance at end of period	$	7,158		$	3,353		$	(18,197	)	$	(11,221	)	$	—		$	(18,907	)


Changes in unrealized gain (loss) included in derivative income (expense) relating to derivatives still held at March 31, 2010	$	7,451		$	3,678		$	(10,507	)	$	(4,063	)	$	(2	)	$	(3,443	)

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)


	Gas Fixed- Price Physicals			Financial Gas Swaps		Subtotal U.K.			Grand Total
U.K.

Balance at beginning of period	$	1,321		$	—	$	1,321		$	(22,541	)
Derivative income		462			459		921			3,535
Settlements and terminations		(363	)		—		(363	)		1,978


Balance at end of period	$	1,420		$	459	$	1,879		$	(17,028	)


Changes in unrealized gain (loss) included in derivative income (expense) relating to derivatives still held at March 31, 2010	$	475		$	459	$	934		$	(2,509	)

(1)	These swaps include call options to allow us to participate in price increases above certain levels.

Assets Measured at Fair Value on a Nonrecurring Basis

Oil and gas property is measured at fair value on a nonrecurring basis upon impairment and when acquired in a nonmonetary property exchange. During the three months ended March 31, 2010, we recorded impairment expense of $7.6 million on proved properties and gain on nonmonetary property exchange of $12.0 related to proved Gulf of Mexico properties. The impairment charges reduce the oil and gas properties’ carrying values to their estimated fair values and are classified as Level 3. Fair value is calculated as the estimated discounted future net cash flows attributable to the assets. The gain on nonmonetary property exchange reflects the difference between the carrying value of the property surrendered and the estimated fair value of the property received, classified as Level 3, and is calculated based on the estimated discounted future net cash flows attributable to that asset.

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

Note 15 — Subsequent Events

Our evaluation has identified the following matter which requires disclosure as an event subsequent to March 31, 2010: we issued the Notes and, with the proceeds, repaid in full the Term Loans and Revolver. See discussion in Note 6 “Long-term Debt.”

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

Item 2.

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

Executive Overview

General

ATP Oil & Gas Corporation is engaged in the acquisition, development and production of oil and natural gas properties in the Gulf of Mexico and the U.K. and Dutch Sectors of 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 exploration-oriented independent oil and gas companies. Occasionally we will acquire properties that are already producing or where previous drilling has encountered reservoirs that appear to contain commercially productive quantities of oil and gas even though the reservoirs do not meet the SEC definition of proved reserves. We believe that our strategy provides assets for us to develop and produce without the risk, cost or time of traditional exploration. Our management team has extensive engineering, geological, geophysical, technical and operational expertise in successfully developing and operating properties in both our current and planned areas of operation.

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

•

significant undeveloped reserves;

•

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.

Our focus is on acquiring properties that are noncore or nonstrategic to their current owners for a variety of reasons. For example, larger oil companies from time to time adjust their capital spending or shift their focus to exploration prospects 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 have an acquisition cost of a property that is less than the total development costs incurred by the previous owner. This strategy, coupled with our expertise in our areas of focus and our ability to develop projects, tend 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.

Since we operate a significant number of the properties in which we acquire a working interest, we are able to significantly influence the plans and timing of a project’s development. In addition, practically all of our properties have 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. Without the exploration time constraint, we focus on developing projects in the shortest time possible between initial significant investment and first revenue generated in order to maximize our rate of return. We may initiate new development projects by simultaneously obtaining the various required components such as the pipeline and the production platform or subsea well completion equipment. We believe this strategy, combined with our strong technical abilities to evaluate and implement a project’s requirements, allows us to efficiently complete the development project and commence production.

In 2003 we made a concerted effort to expand our presence into the deeper water of the Gulf of Mexico. In 2003 we acquired MC Block 711 (now part of our Gomez Hub) in 3,000 feet of water, in 2005 we acquired

MC Block 217 (now part of our Canyon Express Hub) in 7,000 feet of water and in 2006 we acquired MC Block 941, MC Block 942 and Atwater Valley Block 63 (now part of our Telemark Hub) in 4,000 feet of water. With these acquisitions and the subsequent development of these properties, as of December 31, 2009, our proved reserves in the deepwater Gulf of Mexico account for 62% of our total proved reserves. Our proved reserves on the Gulf of Mexico Shelf account for 6% of our total proved reserves with the remaining 32% in the North Sea.

In conjunction with the move to the deeper water of the Gulf of Mexico, we also made the commitment to increase our investment in reusable floating infrastructure. We own interests in two floating production facilities, theATP Innovator and theATP Titan. TheATP Innovator is located in the Gulf of Mexico at our Gomez Hub and theATP Titan is located in the Gulf of Mexico at our Telemark Hub. These floating production facilities are fundamental to our hub strategy and business plan. We believe the presence of these facilities allows us a competitive advantage for additional acquisitions in a large area surrounding each installation. A third floating production facility called an Octabuoy is under construction in China for initial deployment at our Cheviot Hub in the U.K. North Sea during 2012. We operate theATP Innovator and theATP Titan and also expect to operate the Octabuoy when it is placed in service. The floating production facilities have longer useful lives than the underlying reserves and are capable of redeployment to new producing locations upon depletion of the reserves. Accordingly, they are expected eventually to be moved several times over their useful lives.

Risks and Uncertainties

In addition, our estimates of proved oil and natural gas reserves and the estimated future net revenues from such reserves are based upon various assumptions, including assumptions relating to oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. This process requires significant assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir. Therefore, these estimates are inherently imprecise and the quality and reliability of this data can vary. Estimates of our oil and natural gas reserves and the costs and timing associated with developing these reserves are subject to change, which could materially impact the quantities of oil and natural gas that we ultimately produce. As of December 31, 2009, approximately 87% of our total proved reserves are undeveloped. Throughout the year, we intend to continue to develop these reserves, but there can be no assurance we will be successful. Development of these reserves may not yield the expected results, or the development may be delayed or the costs may exceed our estimates, any of which may materially affect our financial position, results of operations, cash flows and our ability to meet the requirements of our financing obligations.

Results of Operations

Three Months Ended March 31, 2010 Compared to Three Months Ended March 31, 2009

For the three months ended March 31, 2010 and 2009 we reported net income (loss) attributable to common shareholders of ($0.9) million and $1.6 million, or ($0.02) and $0.05 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 related to the second quarter 2008 sale of the limited-term overriding royalty interest. We do not reflect any production volumes associated with those revenues.


	Three Months Ended March 31,					% Change from 2009 to 2010
	2010		2009			% Change from 2009 to 2010
Production:
Oil and condensate (MBbl)		872		915		(5	)%
Natural gas (MMcf)		3,751		4,474		(16	)%
Total (MBoe)		1,497		1,661		(10	)%
Gulf of Mexico (MBoe)		1,332		1,562		(15	)%
North Sea (MBoe)		165		99		67	%

Revenues from production (in thousands):
Oil and condensate	$	62,476	$	35,662		75	%
Amortization of deferred revenue		9,102		9,404

Total	$	71,578	$	45,066		59	%


Natural gas	$	19,934	$	21,530		(7	)%
Effects of cash flow hedges		—		(295	)
Amortization of deferred revenue		1,517		1,955

Total	$	21,451	$	23,190		(7	)%


Oil, condensate and natural gas	$	82,410	$	57,192		44	%
Effects of cash flow hedges		—		(295	)
Amortization of deferred revenue		10,619		11,359

Total	$	93,029	$	68,256		36	%


Average realized sales price:
Oil and condensate average realized price (per Bbl)	$	71.65	$	38.97		84	%

Natural gas (per Mcf)	$	5.31	$	4.81		10	%
Effects of cash flow hedges (per Mcf)		—		(0.07	)

Average realized price (per Mcf)	$	5.31	$	4.74		12	%


GOM (per Mcf)		5.22		4.60
North Sea (per Mcf)		5.59		5.74

Oil, condensate and natural gas (per Boe)	$	55.02	$	34.44		60	%
Effects of cash flow hedges (per Boe)		—		(0.18	)

Average realized price (per Boe)	$	55.02	$	34.26		61	%


GOM (per Boe)		57.62		34.38
North Sea (per Boe)		34.31		32.31

Revenues from production increased in 2010 compared to 2009 due to a 61% increase in average realized sales price, partially offset by a 10% decrease in overall production. The production decrease in the Gulf of Mexico was 15%, which was partially offset by the increase in production in the North Sea of 67%. The higher average realized sales price is due to increased commodity market prices. The lower production is primarily the result of natural production declines in the Gulf of Mexico partially offset by increases in production in the North Sea from drilling and the return to production of an existing well.

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 2009 to 2010
	2010		2009		% Change from 2009 to 2010

Recurring operating expenses	$	18,166	$	15,636	16	%

Workover expenses		11,469		4,578	151	%


Lease operating	$	29,635	$	20,214	46	%


Recurring operating expenses per Boe	$	12.13	$	9.41	29	%
Gulf of Mexico		12.40		8.77	41	%
North Sea		10.01		19.57	(49	)%

Lease operating expense for 2010 increased $9.4 million compared to 2009. The increase in recurring operating expense was primarily due to additional insurance costs. The workover expenses during the first quarter of 2010 were primarily due to hydrate remediation activities on our Canyon Express pipeline which enabled us to commence production at our new well at Kings Peak (MC Block 217) and to re-establish production from two wells at Aconcagua (MC Block 305). The costs for the first quarter of 2009 included Hurricane Ike repairs. The North Sea per unit cost has decreased primarily due to the effect of higher production on fixed costs.

General and Administrative

General and administrative expenses are overhead-related expenses, including employee compensation, legal and accounting fees, insurance (other than that included in lease operating expense) and investor relations expenses. General and administrative expense was as follows:


	Three Months Ended March 31,				% Change from 2009 to 2010
	2010		2009		% Change from 2009 to 2010

General and administrative (in thousands)	$	11,509	$	11,103	4	%
Per Boe		7.69		6.66	15	%

General and administrative expense increased $0.4 million to $11.5 million from the first quarter of 2009. The increase was primarily due to increased regulatory fees and higher legal and accounting fees. These increases were partially offset by decreases in stock-based compensation.

Depreciation, Depletion and Amortization

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


	Three Months Ended March 31,				% Change from 2009 to 2010
	2010		2009		% Change from 2009 to 2010

DD&A (in thousands)	$	36,001	$	39,398	(9	)%
Per Boe		24.05		23.70	1	%
Gulf of Mexico		22.83		21.84	5	%
North Sea		33.88		53.88	(37	)%

DD&A expense for first quarter of 2010 decreased compared to first quarter of 2009 primarily due to decreased production discussed above. The per unit increase in the Gulf of Mexico is primarily a result of higher costs incurred on our new developments relative to some of our older properties. The per unit decrease in the North Sea is primarily due to increases in reserves.

Impairment of Oil and Gas Properties

We recorded impairment of oil and gas properties for the first quarter of 2010 and 2009 of $8.2 million ($7.6 million related to proved properties and $0.6 million related to unproved properties) and $8.0 million, respectively. These amounts represented the remaining carrying costs of those properties, and were primarily due to economic conditions and relinquishment of the unproved leases.

Accretion of Asset Retirement Obligation

Accretion expense of $3.4 million in first quarter 2010 is increased compared to $2.9 million in first quarter 2009 primarily due to the addition of the future retirement obligations associated with our Telemark Hub.

Loss on Abandonment

We recognized aggregate loss on abandonment during first quarter 2010 and first quarter 2009 which were the result of actual abandonment costs exceeding the previously accrued estimates, due to unforeseen circumstances that required additional work or the use of equipment more expensive than anticipated and unanticipated vendor price increases.

Gain (Loss) on Exchange/Disposal of Properties

During January 2010, we consummated a nonmonetary exchange of our 10% nonoperated working interest in MC Block 800, for an incremental 50% working interest in MC Block 754, both proved undeveloped properties. The consolidated financial statements reflect the incremental interest acquired in MC Block 754 at fair value and removal of the carrying costs of MC Block 800, resulting in recognition of a $12.0 million gain.

Interest Expense, Net

Interest expense was $12.2 million in the first quarter of 2010 compared to $12.6 million in the first quarter of 2009. In the first quarter of 2010, we capitalized interest of $43.3 million ($40.4 million related to the construction of the Telemark Hub development in the Gulf of Mexico and $2.9 million related to Cheviot in the U.K.) compared to first quarter 2009 capitalized interest of $20.9 million ($19.7 million related to the Telemark Hub development and $1.2 million related to Cheviot). Interest costs excluding capitalized interest were lower in first quarter 2010 compared to 2009 primarily due to lower outstanding Term Loans balances. Production began from the Telemark Hub at the end of the first quarter 2010. Consequently, beginning in the second quarter 2010, we will no longer capitalize interest costs associated with that development project and therefore expect interest expense, net on the consolidated statement of operations to increase.

Derivative Income

Derivative income during the first quarter of 2010 was $3.5 million ($2.6 million and $0.9 million in the Gulf of Mexico and North Sea, respectively). Derivative income during the first quarter of 2009 was $16.2 million ($12.2 million and $4.0 million in the Gulf of Mexico and North Sea, respectively). This income is related to net gains associated with our oil and gas price derivative contracts.

Income Tax (Expense) Benefit

We recorded income tax expense of $1.4 million during the first quarter of 2010 resulting in an overall effective tax rate of 18.1%. In each jurisdiction, the rates were determined based on our expectations of net income or loss for the year, taking into consideration permanent differences. In the comparable quarter of 2009 we recorded income tax benefit of $0.9 million resulting in an overall effective tax rate of (31.6)%. The effective tax rate at March 31, 2010 differs from the statutory rates primarily due to the impact of taxable losses in our UK subsidiary that are not included in net income for book purposes. Our current deferred tax asset at March 31, 2010 is based upon our forecast of taxable income and was reduced by $57.2 million from December 31, 2009 due to the impact of reductions in our forecast of income as a result of our new financing and updated forecasts of operating income for 2010.

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 $4.5 million in the first quarter of 2010 is higher than the first quarter 2009 amount primarily because of the mid-quarter 2009 inception of this arrangement.

Convertible Preferred Stock Dividends

Convertible preferred stock dividends in 2010 represent declared cash amounts due for the three months ended March 31, 2010. The outstanding shares of convertible preferred stock accrue cumulative preferred dividends at the annual rate of 8% of the $140.0 million liquidation value.

Liquidity and Capital Resources

Historically, we have funded our acquisition and development activities through a combination of bank borrowings, proceeds from equity offerings, cash from operations, the sale or conveyance of interests in selected properties and vendor financings. The disarray in the credit markets that began in 2008 has continued into 2010. Capital market transactions are limited and when they can be completed they are more expensive than similar transactions in the past three years. Despite this, so far in 2010, we have refinanced the Term Loans and obtained additional financing from other transactions, all of which are discussed below.

During the first three months of 2010, we sold overriding royalty interests (primarily limited term) in future production from the Gomez Hub properties for cash proceeds of $138.0 million, net of costs. The dollar-denominated overriding royalty interests obligate us to deliver proceeds from the future sale of hydrocarbons from the specified properties equal to the purchasers’ original investment plus an overall rate of return. The percentage of property revenues available to satisfy this obligation is dependent upon certain conditions specified in the agreement. Upon payment of the agreed dollar amounts, the ownership of the dollar-denominated interests reverts to us. Also during the first three months of 2010, we granted dollar-denominated overriding royalty interests in the form of net profits interests in certain of our oil and gas properties in and around the Telemark Hub and Gomez Hub and received cash proceeds of $49.5 million net of costs.

We anticipate our 2010 cash capital expenditures (including abandonment) will be between $400 and $500 million, which is the level that we expect can be funded with cash on hand, cash flows from operations and completed monetizations. As operator of most of our projects under development, we have the ability to control the timing and extent of most of our capital expenditures should future market conditions warrant. Coupled with that control, we believe we have sufficient liquidity to enable us to meet our future capital and debt service requirements.

We desire to monetize selected assets during the remainder of 2010, and the ability of potential buyers to access the credit markets and the commodity price outlook may be important factors to our success in doing so. For example, we are actively in discussions to monetize a portion of our interest in theATP Titan. Still, we believe that we will be able to monetize more selected assets, providing us with additional capital for development activities. In the near term, our revenues, profitability and cash flows are highly dependent upon many factors, particularly our ability to bring other major development projects at Telemark on production, performance of other properties and the price of oil and natural gas. To mitigate future price volatility, we may continue to hedge the sales price of a portion of our future production.

For the longer term, we will continue to deploy the same or similar strategies. Operating our properties has always been a significant focus of our strategy. As stated previously, we believe operating our properties provides us the ability to control expenditures and adjust development timing and programs where needed. We do not expect to see a significant change in this focus over the next several years.

Cash Flows


	Three Months Ended March 31,
	2010			2009
Cash provided by (used in) (in thousands):
Operating activities	$	5,469		$	22,885
Investing activities		(190,773	)		(248,040	)
Financing activities		173,661			114,939

We had working capital deficits of approximately $79.8 million and $26.4 million as of March 31, 2010 and December 31, 2009, respectively. Our Term Loans covenants specify a minimum liquidity ratio whereby we include the availability under our revolving credit facility, and exclude current maturities of Term Loans, the current portion of derivative assets and liabilities and the current portion of asset retirement obligations. We were in compliance with all of the covenants under our Term Loans at March 31, 2010.

Cash provided by operating activities during first quarter 2010 and 2009 was $5.5 million and $22.9 million, respectively. Cash flow from operations decreased primarily due to increased lease operating expenses and decreased derivative income discussed above.

Cash used in investing activities was $190.8 million and $248.0 million during first quarter 2010 and 2009, respectively. Cash expended in the Gulf of Mexico and North Sea for additions to oil and gas properties was approximately $148.9 million and $8.4 million, respectively, in first quarter 2010. Cash expended in the Gulf of Mexico and North Sea for additions to oil and gas properties was approximately $201.4 million and $33.1 million, respectively, in first quarter 2009.

Cash provided by financing activities was $173.7 million and $114.9 million during first quarter 2010 and 2009, respectively. The amount in first quarter 2010 is primarily related to $170.6 million proceeds net of costs from sales of limited term overriding royalty interests and net profit interests discussed in Note 7 “Other Long-term Obligations” to the Consolidated Financial Statements, $46.0 million proceeds from the Term Loans, partially offset by principal payments of Term Loans and other long-term obligations. The amount in first quarter 2009 is from $148.8 million sale of a noncontrolling interest in our limited partnership partially offset by $33.8 million of debt repayments.

Long-term Debt

Term Loans consisted of the following (in thousands):


	March 31, 2010		December 31, 2009
Term Loans and revolving credit facility - net of unamortized discount of $32,343 and $28,266, respectively	$	1,245,299	$	1,216,685
Less current maturities		—		(16,838	)

Term Loans – noncurrent	$	1,245,299	$	1,199,847

amount of $1.5 billion due May 1, 2015 (collectively, the “Borrowings”). The Borrowings are currently collateralized by substantially all of our oil and gas properties in the Gulf of Mexico and a pledge of 65% of the common stock of our wholly owned subsidiary, ATP Oil & Gas (UK) Limited. We used proceeds from the Notes to repay the entire amount outstanding under the Term Loans.

Contractual Obligations

The following table summarizes certain contractual obligations at March 31, 2010 (in thousands):


Contractual Obligations	Total		Less than 1 year		1 – 3 years		3 – 5 years		More than 5 years
Term Loans (1)	$	1,277,642	$	166,517	$	21,000	$	1,090,125	$	—
Interest on Term Loans (1) (2)		451,776		151,092		212,569		88,115		—
Other long-term obligations (3)		208,767		43,120		127,314		20,000		18,333
Other trade commitments		23,700		21,450		2,250		—		—
Noncancelable operating leases		1,486		823		663		—		—

Total contractual obligations	$	1,963,371	$	383,002	$	363,796	$	1,198,240	$	18,333

(1)

In April 2010, we entered into a first lien revolving credit facility with an initial borrowing base of $100.0 million, and issued senior second lien notes in an aggregate principal amount of $1.5 billion. We used proceeds from the Notes to repay the entire amount outstanding under the Term Loans. The Notes are due May 1, 2015 and bear interest at 11.785% per annum payable each May 1 and November 1. ATP has no amounts outstanding under the revolving credit facility, which bears interest at a variable rate and expires April 23, 2013.

(2)	Interest is based on rates and principal repayment requirements in effect at March 31, 2010.

(3)

Omitted from other long-term obligations in this table are $269.4 million of net profits interests payable and overriding royalty interest of $124.7 million as of March 31, 2010 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. Included in the table above are $56.5 million of contractual commitments that are expected to be paid that are not yet incurred.

Our liabilities include asset retirement obligations (“ARO”) ($45.0 million current and $108.3 million long-term) that represent our estimate of the amount at March 31, 2010 of our obligations with respect to the retirement/plugging and abandonment of our oil and gas properties. The ultimate settlement amounts and the timing of the settlements of such obligations are uncertain because they are subject to, among other things, federal, state and local regulation, economic and operational factors. Consequently, ARO is not reflected in the table above.

Commitments and Contingencies

Management is periodically faced with uncertainties, the outcomes of which are not within its control and will not be known for a long time. We are involved in actions from time to time, which if determined adversely, could have a material negative impact on our financial position, results of operations and cash flows. Management, with the assistance of counsel makes estimates, if determinable, of our probable liabilities and records such amounts in the consolidated financial statements. Such estimates may be the minimum amount of a range of probable loss when no single best estimate is determinable. Disclosure is made, when determinable, of any additional possible amount of loss on these claims, or if such estimate cannot be made, that fact is disclosed. Along with our counsel, we monitor developments related to these legal matters and, when appropriate, we make adjustments to recorded liabilities to reflect current facts and circumstances. Although it is difficult to predict the ultimate outcome of these matters, management is not aware of any amounts that need to be recorded and believes that the recorded amounts, if any, are reasonable. See Note 12, “Commitments and Contingencies” to Consolidated Financials Statement in Item 1 for additional discussion.

Accounting Pronouncements

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

Critical Accounting Policies

Our discussion and analysis of our financial condition and results of operations are based on consolidated financial statements which have been prepared in accordance with generally accepted accounting principles in the United States. The preparation of these financial statements requires us to make estimates and judgments that affect the reported amounts or assets, liabilities, revenues and expenses. We believe that certain accounting policies affect our more significant judgments and estimates used in the preparation of our consolidated financial statements. Critical accounting policies have not changed materially from those disclosed on our 2009 Annual Report on Form 10-K.

Item 3.

Quantitative and Qualitative Disclosures about Market Risks

Interest Rate Risk

We were exposed to changes in interest rates on our Term Loans as described in Management’s Discussion and Analysis of Financial Condition and Results of Operations: Liquidity and Capital Resources, and on the earnings from cash and cash equivalents. See the presentation of our Term Loans in Note 6, “Long-term Debt” to Consolidated Financial Statements in Item 1. Additionally, amounts borrowed in the future under our new revolving credit facility will be exposed to changes in interest rates. However, the interest rate on the Notes is fixed and therefore presents no interest rate exposure for us.

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 and operations due to fluctuations in the value of the local currency relative to the U.S. dollar arising from the process of re-measuring the local currency in U.S. dollars.

Commodity Price Risk

Our revenues, profitability and future growth depend substantially on prevailing prices for oil and natural gas. Prices also affect the amount of cash flow available for capital expenditures and our ability to borrow and raise additional capital. Lower prices may also reduce the amount of oil and natural gas that we can

economically produce. We currently sell a portion of our oil and natural gas production under market price contracts. We periodically use derivative instruments to hedge our commodity price risk. We hedge a portion of our projected oil and natural gas production through a variety of financial and physical arrangements intended to support oil and natural gas prices at targeted levels and to manage our exposure to price fluctuations. We may use futures contracts, swaps, put options, price collars and fixed-price physical forward contracts to hedge our commodity prices. See Note 11, “Derivative Instruments and Risk Management Activities” to Consolidated Financial Statements in Item 1.

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

Item 4.

Controls and Procedures

Evaluation of Disclosure Controls and Procedures

Our management, under the supervision of and with the participation of our chief executive officer and chief financial officer has evaluated the effectiveness of our disclosure controls and procedures, as defined in Exchange Act Rules 13a-15(e) and 15d-15(e), as of March 31, 2010 (the “Evaluation Date”). Based on this evaluation, the chief executive officer and chief financial officer have concluded that ATP’s disclosure controls and procedures were not effective as of the Evaluation Date due to the material weakness in internal control over financial reporting described below. Disclosure controls and procedures are those controls and procedures designed to provide reasonable assurance that information that is required to be disclosed by ATP in the reports it files or submits under the Exchange Act is (i) recorded, processed, summarized and reported, within the time periods specified in the Securities and Exchange Commission’s rules and forms and (ii) accumulated and communicated to ATP’s management, including our chief executive officer and chief financial officer, as appropriate to allow timely decisions regarding required disclosure.

In preparing our Exchange Act filings, including this Quarterly Report on Form 10-Q, we implemented additional processes and procedures to provide reasonable assurance that the identified material weakness in our internal control over financial reporting was mitigated with respect to the information that we are required to disclose. As a result, we believe the Company’s consolidated financial statements included in this Quarterly Report on Form 10-Q present fairly, in all material respects, the Company’s financial position, results of operations and cash flows for the periods presented.

Material Weakness in Internal Control over Financial Reporting

A material weakness is a deficiency, or combination of deficiencies, such that there is a reasonable possibility that a material misstatement of the annual or interim financial statements will not be prevented or detected on a timely basis. At December 31, 2009, we identified the following material weakness which continues to exist as of the evaluation date:

We did not maintain effective controls over accounting for outstanding liabilities. Specifically, our procedures were not adequate to ensure proper cut-off associated with goods received or services rendered by our vendors and that liabilities were recorded in the appropriate periods.

Changes in Internal Control Over Financial Reporting

As discussed in the remediation section below, during the three months ended March 31, 2010, we have made changes to our internal controls over financial reporting that has materially affected, or is reasonably likely to materially affect, our internal controls over financial reporting.

Remediation Plan

We believe that the material weakness was attributable to factors caused by the substantial activity at year-end 2009 focused on the completion of our major development project at our Telemark Hub. During the quarter ended March 31, 2010, we enhanced our processes to address such changes in activity by implementing new procedures to seek out additional information from major vendors at each balance sheet date to ensure that we have adequate information to ensure proper cut-off when preparing capital accruals. We believe those process changes have adequately improved our controls over accounting for outstanding liabilities but will perform additional tests in future periods to ensure the controls around this area are operating effectively. After performing additional tests, we will evaluate the effectiveness of those controls in order to conclude if the material weakness has been remediated.

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 2009 Annual Report on Form 10-K.

PART II. OTHER INFORMATION

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

Item 1.

Legal Proceedings.

No material changes in any legal proceeding have occurred since our last report.

Item 1A.

Risk Factors.

No material changes in our risk factors have occurred since our last report.

Item 6.

Exhibits


3.1		Amended and Restated Articles of Incorporation, incorporated by reference to Exhibit 3.1 of Registration Statement No. 333-46034 on Form S-1 of ATP Oil & Gas Corporation (“ATP”).

3.2		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		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		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.

4.2		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.

4.3		Form of Stock Certificate for 8.00% Convertible Perpetual Preferred Stock, incorporated by reference to Exhibit 4.1 of ATP’s Form 8-K dated September 29, 2009.

10.1		Credit Agreement dated as of April 23, 2010 among the Company, JPMorgan Chase Bank, N.A., as administrative agent (“JPM”), Credit Suisse Securities (USA) LLC, as syndication agent, NATIXIS, as documentation agent, and the lenders thereto, incorporated by reference to Exhibit 10.1 to ATP’s Current Report on Form 8-K dated April 29, 2010.

10.2		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.

10.3		Intercreditor Agreement dated as of April 23, 2010 among the Company, the Trustee and JPM, incorporated by reference to Exhibit 10.3 to ATP’s Current Report on Form 8-K dated April 29, 2010.

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

10.5		Sale and Purchase Agreement between ATP Oil & Gas (UK) Limited and EDF Production UK Ltd., as amended and restated on October 23, 2008, incorporated by reference to Exhibit 10.1 to ATP’s Report on Form 10-Q for the quarter ended September 30, 2008.

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


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

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

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

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

†10.11		Employment Agreement between ATP and Albert L. Reese, Jr., dated December 29, 2005, incorporated by reference to Exhibit 10.7 to ATP’s Form 8-K dated December 30, 2005.

†10.12		Employment Agreement between ATP and Isabel M. Plume, dated December 29, 2005, incorporated by reference to Exhibit 10.8 to ATP’s Form 8-K dated December 30, 2005.

†10.13		Employment Agreement between ATP and Scott D. Heflin, dated December 29, 2005, incorporated by reference to Exhibit 10.9 to ATP’s Form 8-K dated December 30, 2005.

†10.14		Employment Agreement between ATP and Keith R. Godwin, dated December 29, 2005, incorporated by reference to Exhibit 10.10 to ATP’s Form 8-K dated December 30, 2005.

†10.15		Employment Agreement between ATP and George Ross Frazer, dated December 29, 2005, incorporated by reference to Exhibit 10.11 to ATP’s Form 8-K dated December 30, 2005.

†10.16		Employment Agreement between ATP and T. Paul Bulmahn, dated December 29, 2005, incorporated by reference to Exhibit 10.12 to ATP’s Form 8-K dated December 30, 2005.

†10.17		Employment Agreement between ATP and George R. Morris, dated May 27, 2008, incorporated by reference to Exhibit 99.1 to ATP’s Form 8-K dated May 21, 2008.

†10.18		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.

†10.19		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.

10.20		Purchase Agreement dated September 23, 2009 among the Company, J.P. Morgan Securities Inc. and Credit Suisse Securities (USA) LLC, as representatives of the several Initial Purchasers named therein, incorporated by reference to Exhibit 10.1 of ATP’s Form 8-K dated September 29, 2009.

21.1		Subsidiaries of ATP, incorporated by reference to Exhibit 21.1 to ATP’s Report on Form 10-Q for the quarter ended March 31, 2009.

*31.1		Certification of Principal Executive Officer pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934, the “Act.”

*31.2		Certification of Principal Financial Officer pursuant to Rule 13a-14(a) of the Act

*32.1		Certification of Principal Executive Officer pursuant to 18 U.S.C. Section 1350

*32.2		Certification of Principal Financial Officer pursuant to 18 U.S.C. Section 1350

†	Management contract or compensatory plan or arrangement

*	Filed herewith

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, 2010	By:	/S/ ALBERT L. REESE JR.
			Albert L. Reese Jr.
			Chief Financial Officer

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

Large accelerated filer

Accelerated filer

Non-accelerated filer

Smaller reporting company