Form 10-Q

Table of Contents

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10-Q 1 d10q.htm FORM 10-Q Form 10-Q

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, 2007

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE

SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission File Number: 000-32261

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 is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer x Accelerated filer ¨ Non-accelerated filer ¨

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 8, 2007, was 30,287,977.

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

TABLE OF CONTENTS


		Page
PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS (Unaudited)

Consolidated Balance Sheets as of March 31, 2007 and December 31, 2006		3

Consolidated Statements of Operations for the three months ended March 31, 2007 and 2006		4

Consolidated Statements of Cash Flows for the three months ended March 31, 2007 and 2006		5

Consolidated Statements of Comprehensive Income (Loss) for the three months ended March 31, 2007 and 2006		6

Notes to Consolidated Financial Statements		7

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS		13

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK		17

ITEM 4. CONTROLS AND PROCEDURES		18

PART II. OTHER INFORMATION		18

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(In Thousands, Except Share Amounts)

(Unaudited)


	March 31, 2007			December 31, 2006
Assets
Current assets:
Cash and cash equivalents	$	261,749		$	182,592
Restricted cash		27,556			27,497
Accounts receivable (net of allowance of $382 and $409)		91,231			105,030
Deferred tax asset		8,112			1,113
Derivative asset		367			1,170
Other current assets		10,012			9,931

Total current assets		399,027			327,333
Oil and gas properties (using the successful efforts method of accounting)
Proved properties		1,695,626			1,483,163
Unproved properties		96,524			56,189

		1,792,150			1,539,352
Less: Accumulated depletion, impairment and amortization		(497,287	)		(443,707	)

Oil and gas properties, net		1,294,863			1,095,645

Furniture and fixtures (net of accumulated depreciation)		1,096			1,079
Deferred tax asset		1,515			—
Deferred financing costs, net		20,542			13,272
Other assets, net		9,571			9,729

Total assets	$	1,726,614		$	1,447,058

Liabilities and Shareholders’ Equity
Current liabilities:
Accounts payable and accruals	$	220,252		$	195,846
Current maturities of long-term debt		12,737			8,987
Current maturities of long-term capital lease		—			23,699
Asset retirement obligation		20,142			21,297
Other current liabilities		18,465			—

Total current liabilities		271,596			249,829
Long-term debt		1,255,520			1,062,454
Asset retirement obligation		100,738			87,092
Deferred tax liability		27,511			11,765
Other long-term liabilities and deferred obligations		4,765			—

Total liabilities		1,660,130			1,411,140

Commitments and contingencies (Note 11)		—			—

Shareholders’ equity:
Preferred stock: $0.001 par value, 10,000,000 shares authorized; none issued and outstanding at March 31, 2007 and December 31, 2006		—			—
Common stock: $0.001 par value, 100,000,000 shares authorized; 30,343,317 issued and 30,267,477 outstanding at March 31, 2007; 30,272,210 issued and 30,196,370 outstanding at December 31, 2006		30			30
Additional paid-in capital		153,251			151,467
Accumulated deficit		(113,247	)		(140,681	)
Accumulated other comprehensive income (loss)		27,361			26,013
Treasury stock		(911	)		(911	)

Total shareholders’ equity		66,484			35,918

Total liabilities and shareholders’ equity	$	1,726,614		$	1,447,058

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, 2007			March 31, 2006
Revenues:
Oil and gas production	$	144,749		$	45,245
Other revenues		1,598			—

		146,347			45,245

Costs and operating expenses:
Lease operating		21,069			10,693
Exploration		731			141
General and administrative		8,768			7,985
Depreciation, depletion and amortization		53,400			17,270
Accretion		2,960			1,547
Loss on abandonment		77			55

		87,005			37,691

Income from operations		59,342			7,554

Other income (expense):
Interest income		2,068			573
Interest expense		(26,799	)		(11,172	)

		(24,731	)		(10,599	)

Income (loss) before income taxes		34,611			(3,045	)

Income tax expense:
Current		(56	)		—
Deferred		(7,121	)		—

		(7,177	)		—

Net income (loss)		27,434			(3,045	)
Preferred dividends		—			(6,818	)

Net income (loss) available to common shareholders	$	27,434		$	(9,863	)

Income (loss) per common share:
Basic	$	0.92		$	(0.34	)

Diluted	$	0.89		$	(0.34	)

Weighted average number of common shares:
Basic		29,969			29,435

Diluted		30,702			29,435

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, 2007			March 31, 2006
Cash flows from operating activities
Net income (loss)	$	27,434		$	(3,045	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities –
Depreciation, depletion and amortization		53,400			17,270
Accretion		2,960			1,547
Deferred income taxes		7,121			—
Amortization of deferred financing costs		1,175			1,159
Stock-based compensation		1,553			2,229
Ineffectiveness of cash flow hedges		(74	)		(20	)
Other non-cash items		2,587			398
Changes in assets and liabilities –
Accounts receivable and other current assets		15,096			16,933
Accounts payable and accruals		(27,388	)		(6,512	)
Other assets		173			(1,115	)
Other long-term liabilities and deferred obligations		146			—

Net cash provided by operating activities		84,183			28,844

Cash flows from investing activities
Additions and acquisitions of oil and gas properties		(169,485	)		(96,077	)
Additions to furniture and fixtures		(154	)		(76	)
Increase in restricted cash		(14	)		(38	)

Net cash used in investing activities		(169,653	)		(96,191	)

Cash flows from financing activities
Proceeds from long-term debt		375,000			—
Payments of long-term debt		(178,184	)		(875	)
Deferred financing costs		(8,445	)		—
Issuance of preferred stock, net of issuance costs		—			145,463
Principal payments of capital lease		(23,950	)		(2,089	)
Exercise of stock options		230			1,200

Net cash provided by financing activities		164,651			143,699

Effect of exchange rate changes on cash		(24	)		(3,852	)

Increase in cash and cash equivalents		79,157			72,500
Cash and cash equivalents, beginning of period		182,592			65,566

Cash and cash equivalents, end of period	$	261,749		$	138,066

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, 2007			March 31, 2006
Net income (loss)	$	27,434		$	(3,045	)

Other comprehensive income (loss):
Reclassification adjustment for settled contracts, net of tax of $0		(1,455	)		(1,282	)
Change in fair value of outstanding hedge positions, net of tax of $0		945			3,550
Foreign currency translation adjustment, net of tax of $0		(838	)		(1,918	)

Other comprehensive income (loss)		(1,348	)		350

Comprehensive income (loss)	$	26,086		$	(2,695	)

See accompanying notes to consolidated financial statements.

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 1 — Organization and Basis of Presentation

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 with proved undeveloped reserves that are economically attractive to us but are not strategic to major or exploration-oriented independent oil and gas companies.

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 presentation of the results of operations for the interim periods. All intercompany transactions are eliminated upon consolidation. The interim financial information and notes hereto should be read in conjunction with our 2006 Annual Report on Form 10-K. The results of operations for the three months ended March 31, 2007 are not necessarily indicative of results to be expected for the entire year. We have reclassified certain amounts applicable to prior periods to conform to the classifications currently followed. Such reclassifications do not affect earnings.

Note 2 — Recently Issued Accounting Pronouncements

In June 2006, the Financial Accounting Standards Board (“FASB”) issued Interpretation No. 48, “Accounting for Uncertainty in Income Taxes-an Interpretation of FASB Statement No. 109,” (“FIN No. 48”) which provides guidance for the recognition and measurement of a tax position taken or expected to be taken in a tax return. We are required to determine whether it is more likely than not that a tax position will be sustained upon examination, including resolution of any related appeals or litigation processes, based on the technical merits of the position. If the tax position meets the “more likely than not” recognition threshold, it is then measured and recorded at the largest amount of benefit that is greater than 50 percent likely of being realized upon ultimate settlement.

We adopted FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes-an Interpretation of FASB Statement No. 109” (“FIN No. 48”), effective January 1, 2007. See Note 3.

During February 2007, the FASB issued Statement of Financial Accounting Standards (“SFAS”) No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities—including an amendment of FASB Statement No. 115.” The new standard permits an entity to make an irrevocable election to measure most financial assets and financial liabilities at fair value. The fair value option may be elected on an instrument-by-instrument basis, with a few exceptions, as long as it is applied to the instrument in its entirety. Changes in fair value would be recorded in income. SFAS No. 159 established presentation and disclosure requirements intended to help financial statement users understand the effect of the entity’s election on earnings. SFAS No. 159 is effective as of the beginning of the first fiscal year beginning after November 15, 2007. Early adoption is permitted. We are evaluating the impact that this guidance will have on our financial statements.

Note 3 — Income Taxes

We compute income taxes using an asset and liability approach which results in the recognition of deferred tax liabilities and assets for the expected future tax consequences of temporary differences between the carrying amounts and the tax basis of those assets and liabilities. We have recorded and continue to carry a valuation allowance to give effect to our judgment that it is more likely than not that some portion or all of our net U.S. deferred tax assets will not be realized at some point in the future. Relevant accounting guidance suggests that cumulative losses in recent years constitute significant negative evidence that such deferred tax assets are not recoverable, and that future expectations about income are overshadowed by such history of losses. As of March 31, 2007, we have a valuation allowance equal to the entire balance of our net U.S. deferred tax asset, and we have no valuation allowance recorded related to our foreign operations as a result of the taxable income generated by those entities. Our effective tax rate in the United Kingdom and in the Netherlands is based upon our expectations of net income for the year and taking into consideration permanent differences primarily related to property basis differences, certain non-deductible interest expense and foreign exchange gains and losses. For the quarter, we recorded taxes resulting in a worldwide effective tax rate of 20.7%.

In June 2006, the FASB issued FIN No. 48, which provides guidance for the recognition and measurement of a tax position taken or expected to be taken in a tax return. We are required to determine whether it is more likely than not that a tax position will be sustained upon examination, including resolution of any related appeals or litigation processes, based on the technical merits of the position. If the tax position meets the “more likely than not” recognition threshold, it is then measured and recorded at the largest amount of benefit that is greater than 50 percent likely of being realized upon ultimate settlement.

The adoption of FIN No. 48 had no material effect on our consolidated financial position or results of operations. The Company and its subsidiaries file income tax returns in the United States federal jurisdiction, two states and in the United Kingdom and the Netherlands. Our open tax years in our major jurisdictions are from 2001 to current. We will record interest and penalties, if any, related to unrecognized tax benefits to the income tax provision.

We have provided for an uncertainty that relates to a disagreement with the Dutch taxing authority in regard to the timing of the recognition of taxable income on certain cash receipts in 2002. As of March 31, 2007, the amount of the uncertain tax position is $3.6 million, which is the difference between the tax filing position and the amounts provided for in the financial statements. If the tax filing position is sustained, there would be no expected impact to the effective tax rate. We expect this uncertainty to be resolved in the next twelve months.

Note 4 — Asset Retirement Obligations

Following is a reconciliation of the beginning and ending asset retirement obligation for the period ending March 31, 2007 and 2006 (in thousands):


	Three Months Ended
	March 31, 2007			March 31, 2006
Asset retirement obligation at beginning of period	$	108,389		$	67,364
Liabilities incurred		12,231			2,539
Liabilities settled		(2,780	)		(619	)
Accretion		2,960			1,547
Foreign currency translation		80			138

Asset retirement obligation at end of period	$	120,880		$	70,969

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 5 — Supplemental Disclosures of Cash Flow Information

Supplemental disclosures of cash flow information (in thousands):

During the three months ended March 31, 2007, we acquired two oil and gas properties, a significant portion of the consideration for which was noncash. See Note 7.

Note 6 — Long-Term Debt

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


	March 31,			December 31,
	2007			2006
First Lien Term Loans	$	1,268,257		$	896,441
Second Lien Term Loans		—			175,000

Total		1,268,257			1,071,441
Less current maturities		(12,737	)		(8,987	)

Total long-term debt	$	1,255,520		$	1,062,454

On March 23, 2007 (the “Amendment Date”) ATP, Credit Suisse (as Administrative Agent and Collateral Agent for the lenders) and the lenders named therein entered into Amendment No. 1 and Agreement (the “Amendment”) amending the Third Amended and Restated Credit Agreement dated as of December 28, 2006 (as so amended, the “Existing Credit Agreement” or “Term Loans”).

As of the Amendment Date, the Company increased its aggregate borrowings by a net $200.0 million (from the aggregate balance outstanding as of December 31, 2006) to $1.268 billion. The Company borrowed additional amounts under terms and provisions (after giving effect to the amendments made to the Existing Credit Agreement on the Amendment Date) identical in all material respects to the existing first lien term loans as of the Amendment Date, in an aggregate principal amount of $375.0 million, all of the proceeds of which were or will be used by the Company (a) to pay fees and expenses incurred in connection with the Existing Credit Agreement in an aggregate amount of $8.4 million, (b) to repay in full all outstanding borrowings under the Second Lien Term Loan Facility, which had an original face amount of $175.0 million and bore interest at a rate of LIBOR plus 4.75%, and (c) from time to time solely for general corporate purposes, predominantly the development of the properties acquired to-date in 2007. Net cash proceeds to the Company were $191.5 million. The interest rate on outstanding borrowings is based on LIBOR plus 3.5%, and at March 31, 2007 was approximately 9.81%.

Under the Existing Credit Agreement, we have a $50.0 million revolving credit facility (“Revolver”), all of which was available as of March 31, 2007.

As of March 31, 2007, we were in compliance with all of the financial covenants of our Existing Credit Agreement. Significant adverse changes in our expected production levels, commodity prices and reserves or material delays or cost overruns could have a material adverse affect on our financial condition and results of operations and result in our non-compliance with these covenants. An event of non-compliance with any of the required covenants could result in a material mandatory repayment under the Existing Credit Agreement.

Note 7 — Property Acquisitions

On January 8, 2007, we completed the acquisition of a 50% working interest in Mississippi Canyon (“MC”) Block 305 (“Aconcagua”), a 16.67% working interest in MC Block 348 (“Camden Hills”), and an additional interest

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

in the Canyon Express Pipeline Common System (“Canyon Express”). Both Aconcagua and Camden Hills, along with MC 217 (“King’s Peak”) produce through Canyon Express, in which we now own a 45.084% working interest as a result of this acquisition. ATP is the operator of Canyon Express. On January 23, 2007, we completed the acquisition of a 100% working interest in the northwest quarter of MC Block 755 (“Anduin”), a 50% working interest in MC Block 754 (“Anduin West”), and a 25% working interest in MC Block 800 (“Gladden”). These properties are located in the vicinity of the MC Block 711 (“Gomez”) development and are expected to produce through the ATP Innovator floating production facility. The aggregate net acquisition price for these properties was $27.2 million. A portion of the acquisition price of one property was financed by granting an interest in the future net profits, discounted to $23.1 million as of March 31, 2007.

Note 8 — Stock–Based Compensation

The fair values of options granted during the three months ended March 31, 2007 and 2006 were estimated at the date of grant using a Black-Scholes option-pricing model with the following weighted average assumptions for grants in 2007 and 2006: stock price volatility of 38.1% and 50.5%, respectively; risk free interest rate of 4.5% and 4.6%, respectively; zero dividend yield; and an expected life 3.8 and 3.8 years, respectively. The weighted average grant-date fair value of options granted during the three months ended March 31, 2007 and 2006 was $13.70 and $16.28, respectively. For the three months ended March 31, 2007, we recognized compensation expense of approximately $0.3 million related to stock option compensation. The following table sets forth the option transactions for the three-month period ended March 31, 2007:


	Number of Options		Weighted Average Grant Price		Aggregate Intrinsic Value ($000)(1)		Weighted Average Remaining Contractual Life
							(in years)
Outstanding at beginning of period	693,851		$	24.76
Granted	500			39.40
Exercised	(12,900	)		17.87
Forfeited	(20,251	)		29.49

Outstanding at end of period	661,200		$	24.76	$	8,634	3.28

Options vested or expected to vest	611,201		$	24.77	$	7,978	3.21

Options exercisable at end of period	154,085		$	23.66	$	2,164	3.13

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

At March 31, 2007, unrecognized compensation expense related to non-vested stock option grants totaled $2.0 million. This unrecognized expense will be amortized on a straight-line basis over a weighted average remaining life of 2.4 years.

During the three months ended March 31, 2007, we recognized aggregate compensation expense of $1.2 million related to all of our outstanding restricted stock grants. The following table sets forth the restricted stock transactions for the three-month period ended March 31, 2007:


	Number of Shares		Weighted Average Grant Date Fair Value		Aggregate Intrinsic Value ($000) (1)
Nonvested at beginning of period	233,502		$	38.03
Granted	58,207			41.13
Vested	(53,750	)		41.81

Nonvested at end of period	237,959		$	37.94	$	8,947

(1)	Based on the closing market price of the common stock on the last trading date of the quarter.

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

At March 31, 2007, unrecognized compensation expense related to restricted stock totaled $5.2 million. Such unrecognized expense will be recognized as shares vest over a weighted average period of 2.0 years.

Note 9 — Earnings Per Share

Basic earnings per share is computed by dividing net income or loss by the weighted average number of shares of common stock (other than unvested restricted stock) outstanding during the period. Diluted earnings per share is determined on the assumption that outstanding stock options and warrants have been converted using the average price for the period. For purposes of computing earnings per share in a loss year, potential common shares are excluded from the computation of weighted average common shares outstanding if their effect is antidilutive. For the quarter ended March 31, 2007 and 2006, stock-based awards for 20,000 and 1.4 million average shares, respectively, of common stock were excluded from the diluted EPS calculation because their inclusion would have been antidilutive.

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,		March 31,
	2007		2006
Income
Net income (loss)	$	27,434	$	(3,045	)
Less preferred dividends		—		(6,818	)

Net income (loss) available to common shareholders	$	27,434	$	(9,863	)

Shares outstanding
Weighted average shares outstanding—basic		29,969		29,435
Effect of potentially dilutive securities—stock options and warrants		450		—
Unvested restricted stock		283		—

Weighted average shares outstanding—diluted		30,702		29,435

Net income (loss) available to common shareholders per share:
Basic	$	0.92	$	(0.34	)
Diluted	$	0.89	$	(0.34	)

Note 10 — Derivative Instruments and Price Risk Management Activities

At March 31, 2007 and 2006, Accumulated Other Comprehensive Income included $0.5 million and $3.6 million of unrealized losses on our cash flow hedges, respectively. Gains and losses are reclassified from Accumulated Other Comprehensive Income to the consolidated statements of operations as a component of oil and gas revenues in the period the hedged production occurs. If any ineffectiveness occurs, amounts are recorded directly to the consolidated statement of operations as a component of oil and gas revenues. All of this deferred loss will be reversed during the period in which the forecasted transactions actually occur.

At March 31, 2007, we had oil and natural gas derivatives that qualified as cash flow hedges with respect to our future production as follows:


Area	Period	Type	Volumes	Floor Price	Net Fair Value Asset (Liability)
				$/Bbl	($000)
Oil (Bbls)
Gulf of Mexico	2007	Puts	275,000	60.00	367
Gas (MMbtu)
North Sea	2008	Swaps	460,000	9.11	194
North Sea	2009	Swaps	450,000	9.11	(340	)

We also manage our exposure to oil and gas price risks by periodically entering into fixed-price delivery contracts. These physical contracts qualified and have been designated for the normal purchase and sale exemption

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

under SFAS 133, as amended. This exemption permits, at our option, the use of the accrual basis of accounting as opposed to fair value accounting for the contracts. At March 31, 2007, we had fixed-price contracts in place for the following natural gas and oil volumes:


	Volumes	Average Fixed Price (1)
Gulf of Mexico

Natural gas (MMBtu):
2007	9,563,000	$	8.31
2008	13,188,000		8.30
2009	8,175,000		8.04

Oil (Bbl):
2007	1,137,000	$	70.86
2008	1,098,000		70.76
2009	730,000		66.23

North Sea

Natural gas (MMBtu):
2007	7,350,000	$	8.74
2008	16,460,000		7.76
2009	2,700,000		7.99

(1)

Includes the effect of basis differentials.

During April 2007, we entered into put contracts for 2.5 million barrels of oil in 2008 with floor prices ranging from $54.00 to $56.30 per Bbl, and 1.5 million barrels of oil in 2009 with a floor price of $54.00 per Bbl. We paid an aggregate premium of $8.5 million for these contracts.

Note 11 — Commitments and Contingencies

Contingencies

We maintain property casualty insurance for physical damages and, on certain properties, loss of production insurance to replace lost cash flows resulting from downtime in excess of ninety days after an insured event. We have submitted claims for the insured damages and any recoveries available under the loss of production income (“LOPI”) insurance policy for the 2005 storms, Hurricanes Rita and Katrina. At March 31, 2007, we had a receivable for expected recovery of repair costs incurred related to the 2005 storms in the amount of $12.4 million, net of $4.4 million already received through that date. Additionally, we recorded other revenues during the first quarter of 2007 in the amount of $1.6 million realized under the LOPI insurance policy. We expect to receive additional amounts related to LOPI insurance; however no such amounts will be recorded to the financial statements until they are realized.

In the normal course of business, we occasionally acquire properties with little or no upfront costs, but a commitment to make payments out of future production, if any. As initial production or designated production levels are achieved, the contingent consideration is accrued and capitalized to the appropriate property. At March 31, 2007, our aggregate exposure under such arrangements totaled approximately $37.8 million, and included net profits interests payable, including accrued interest, of approximately $23.1 million, representing the present value of amounts expected ultimately to be paid from future production from the properties.

Litigation

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

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 12 — Segment Information

The Company’s operations are focused in the Gulf of Mexico and in the U.K. and Dutch sectors of the North Sea. Management reviews and evaluates the operations separately of its Gulf of Mexico segment and its North Sea segment. Each segment is an aggregation of operations subject to similar economic and regulatory conditions such that they are likely to have similar long-term prospects for financial performance. The operations of both segments include natural gas and liquid hydrocarbon production and sales. The Company evaluates the segments based on income (loss) from operations. Segment activity for the three months ended March 31, 2007 and 2006 is as follows (in thousands):


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

March 31, 2007:
Revenues	$	108,123	$	38,224	$	—		$	146,347
Depreciation, depletion and amortization		37,818		15,582		—			53,400
Income from operations		43,879		15,463		—			59,342
Interest income		4,653		509		(3,094	)		2,068
Interest expense		26,798		3,095		(3,094	)		26,799
Income tax expense (benefit)		—		7,177		—			7,177
Total assets		1,223,609		503,005		—			1,726,614
Additions to oil and gas properties		194,003		58,795		—			252,798

March 31, 2006:
Revenues	$	39,473	$	5,772	$	—		$	45,245
Depreciation, depletion and amortization		15,040		2,230		—			17,270
Income from operations		6,375		1,179		—			7,554
Interest income		452		158		(38	)		572
Interest expense		11,172		38		(38	)		11,172
Income tax expense (benefit)		—		—		—			—
Total assets		727,586		214,120		—			941,706
Additions to oil and gas properties		62,851		33,226		—			96,077

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Executive Overview

General

ATP Oil & Gas Corporation is engaged in the acquisition, development and production of oil and natural gas properties in the Gulf of Mexico and the North Sea. We seek to acquire and develop properties with proved undeveloped reserves (“PUD”) that are economically attractive to us but may not be 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 us to contain commercially productive quantities of oil and gas even though the reservoirs do not meet the SEC definition of proved reserves. We believe that our strategy provides assets for us to develop and produce without the risk, cost or time of traditional exploration.

We seek to create value and reduce operating risks through the acquisition and development of proved oil and natural gas reserves in areas that have:

•

significant undeveloped reserves and reservoirs;

•

close proximity to developed markets for oil and natural gas;

•

existing infrastructure of oil and natural gas pipelines and production / processing platforms; and

•

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

Our focus is on acquiring properties that have become non-core or non-strategic to their original owners for a variety of reasons. For example, larger oil companies from time to time adjust their capital spending or shift their focus to exploration prospects which they believe offer greater reserve potential. Some projects provide lower economic returns to a company due to its cost structure within that company. Also, due to timing or budget constraints, a company may be unwilling or unable to develop a property before the expiration of the lease. Because of our cost structure, expertise in our areas of focus and ability to develop projects, the properties may be more financially attractive to us than the seller. Given our strategy of acquiring properties that contain proved reserves, our operations typically are lower risk than exploration-focused Gulf of Mexico and North Sea operators.

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. Since we operate a significant number of the properties in which we acquire a working interest, we are able to significantly influence the development concept and timing of a project’s development. We typically 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.

Source of Revenue

We derive our revenues from the sale of oil and natural gas that is produced from our properties. Revenues are a function of the volume produced and the prevailing market price at the time of sale. The price of oil and natural gas is a primary factor affecting our revenues. To achieve more predictable cash flows and to reduce our exposure to downward price fluctuations, we utilize derivative instruments to hedge future sales prices on a significant portion of our oil and natural gas production. While the use of certain types of derivative instruments assure a more predictable realized price, they may prevent us from realizing the full benefit of upward price movements.

First Quarter 2007 Highlights

Our financial and operating performance for the first quarter of 2007 included the following highlights:

•

Achieved quarterly record net income of $0.92 per basic share and $0.89 per diluted share;

•

Achieved quarterly record revenue of $146.3 million;

•

Expanded the Canyon Express Hub;

•

Expanded the Gomez Hub;

•

Expanded the Tors Hub;

•

Lowered cost of capital by refinancing second lien debt at Libor plus 4.75% with additional first lien debt at Libor plus 3.5% and improved financial strength by adding $191.5 million in liquidity.

A more complete overview and discussion of full year expectations can be found in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our 2006 Annual Report on Form 10-K.

Results of Operations

Three Months Ended March 31, 2007 Compared to Three Months Ended March 31, 2006

For the three months ended March 31, 2007, we reported net income of $27.4 million, or $0.89 per diluted share on revenues of $146.3 million, as compared with net loss available to common shareholders of $9.9 million, or $0.34 per share on total revenue of $45.2 million for the three months ended March 31, 2006. The results from the first quarter of 2007 were positively impacted by our major development activities, which resulted in significantly increased production, revenues and operating expenses. Results from the first quarter 2006 were impacted by the destructive aftermath of hurricanes Katrina and Rita, and the resultant industry rush to complete repairs and rehabilitation efforts in an atmosphere of scarce resources and ever increasing costs due to the demand for such services.

Oil and Gas Revenues

Revenues presented in the table and in the discussion below represent revenues from sales of our oil and natural gas production volumes. Production sold under fixed price delivery contracts, which have been designated for the normal purchase and sale exemption under SFAS 133, are also included in these amounts. Approximately 31% and 72% of our oil production was sold under these contracts for the three months ended March 31, 2007 and 2006, respectively. Approximately 23% and 41% of our natural gas production was sold under these contracts for the comparable periods. The realized prices below may differ from the market prices in effect during the periods depending on when the fixed price delivery contract was executed.


	Three Months Ended March 31,						% Change in 2007
		2007			2006		from 2006

Production:
Natural gas (MMcf)		9,825			5,033		95	%
Oil and condensate (MBbls)		1,012			150		575	%
Total (MMcfe)		15,896			5,935		168	%
Revenues from production (in thousands):
Natural gas	$	89,933		$	38,956		131	%
Effects of cash flow hedges		—			(450	)	100	%

Total	$	89,933		$	38,506		134	%

Oil and condensate	$	55,603		$	6,719		728	%
Effects of cash flow hedges		(862	)		—		—

Total	$	54,741		$	6,719		715	%

Natural gas, oil and condensate	$	145,536		$	45,675		219	%
Effects of cash flow hedges		(862	)		(450	)	(92	)%

Total	$	144,674		$	45,225		220	%

Average sales price per unit:
Natural gas (per Mcf)	$	9.15		$	7.74		18	%
Effects of cash flow hedges (per Mcf)		—			(0.09	)	100	%

Total (per Mcf)	$	9.15		$	7.65		20	%

Oil and condensate (per Bbl)	$	54.95		$	44.72		23	%
Effects of cash flow hedges (per Bbl)		(0.86	)		—		—

Total (per Bbl)	$	54.09		$	44.72		21	%

Natural gas, oil and condensate (per Mcfe)	$	9.16		$	7.70		19	%
Effects of cash flow hedges (per Mcfe)		(0.05	)		(0.08	)	38	%

Total (per Mcfe)	$	9.11		$	7.62		20	%

Oil and gas revenue. Oil and gas revenue increased 220% in the first quarter of 2007 compared to the same period in 2006 primarily as a result of a 168% increase in average sales volumes and a 20% increase in average realized prices in 2007 as compared to 2006.

Lease Operating. Lease operating expenses for the first quarter of 2007 increased to $21.1 million ($1.33 per Mcfe) from $10.7 million ($1.80 per Mcfe) in the first quarter of 2006. The decrease per Mcfe was primarily attributable to higher production levels, and the additional first quarter 2006 costs related to the 2005 hurricanes.

Exploration. Exploration expense for the first quarter of 2007 increased to $0.7 million from $0.1 million in the first quarter of 2006. During 2007, exploration expense includes the costs of geological and geophysical studies on certain of our unproved properties. During the second quarter of 2007, we expect to record exploration expense of approximately $10.0 million related to a well that was drilled in the second quarter which targeted an extension opportunity that encountered an insufficient amount of hydrocarbons and has been deemed non-commercial.

General and Administrative. General and administrative expense increased $0.8 million to $8.8 million from the first quarter of 2006. The increase was primarily due to increased employee compensation and higher legal, professional and accounting fees. General and administrative expense for the first quarter 2006 includes a charge of $0.3 million for the earned compensation related to the ATP Employee Volvo Challenge which was successfully achieved and fully accrued for in that period.

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization expense increased $36.1 million (209%) during the first quarter of 2007 to $53.4 million from $17.3 million for the same period in 2006. The average DD&A rate was $3.36 per Mcfe in the first quarter of 2007 compared to $2.91 per Mcfe in the same quarter of 2006.

Income Taxes. During the first quarter of 2007 we recognized current tax expense of $0.06 million primarily due to our Netherlands operations. We recognized $7.1 million of deferred tax expense related to our U.K. and Netherlands operations. See Note 3 to the Consolidated Financial Statements.

Liquidity and Capital Resources

At March 31, 2007, we had working capital of approximately $127.4 million, an increase of approximately $49.9 million from December 31, 2006.

We have financed our acquisition and development activities through a combination of bank borrowings and proceeds from our equity offerings, as well as cash from operations and the sale on a promoted basis of interests in selected properties. We intend to finance our near-term development projects in the Gulf of Mexico and North Sea through available cash flows, remaining proceeds from our preferred stock proceeds and potentially by selling a portion of our interests in the development projects. As operator of all of our projects in development, we have the ability to significantly control the timing of most of our capital expenditures. We believe the cash flows from operating activities combined with our ability to control the timing of substantially all of our future development and acquisition requirements will provide us with the flexibility and liquidity to meet our future planned capital requirements.

Cash Flows


	Three Months Ended
	March 31, 2007		March 31, 2006
Cash provided by (used in):
Operating activities	84,183		28,844
Investing activities	(169,653	)	(96,191	)
Financing activities	164,651		143,699

Cash provided by operating activities in the first quarter of 2007 and 2006 was $84.2 million and $28.8 million, respectively. Cash flow from operations increased primarily due to higher natural gas and oil revenues during the first quarter of 2007 compared to the first quarter of 2006. Gas sales increased by $51.4 million, or 134%, due to higher average realized prices and volumes, and oil sales increased by $48.0 million, or 715%, primarily due to increased volumes.

Cash used in investing activities was $169.7 million and $96.2 million in the first quarter of 2007 and 2006, respectively. Cash expended in the Gulf of Mexico and North Sea was approximately $117.3 million and $52.2 million in first quarter of 2007. Cash expended in the Gulf of Mexico and North Sea was approximately $62.8 million and $33.2 million in first quarter of 2006.

Cash provided by financing activities was $164.7 million and $143.7 million in the first quarter of 2007 and 2006, respectively. During the first quarter of 2007 we borrowed additional amounts under our First Lien Term

Loans and repaid our Second Lien Term Loans and the balance of our capital lease obligation for the ATP Innovator. Such amount for the 2006 period was primarily due to the issuance of our 12.5% Series B Cumulative Preferred Stock for $145.5 million (net of issuance costs).

Term Loans

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


	March 31, 2007			December 31, 2006
First Lien Term Loans	$	1,268,257		$	896,441
Second Lien Term Loan		—			175,000

Total		1,268,257			1,071,441
Less current maturities		(12,737	)		(8,987	)

Total long-term debt	$	1,255,520		$	1,062,454

Under the Existing Credit Agreement, we have a $50.0 million revolving credit facility (“Revolver”), all of which was available as of March 31, 2007.

The terms of the Existing Credit Agreement require us to maintain certain covenants. Capitalized terms are defined in the Existing Credit Agreement. The covenants include:

•

Minimum Current Ratio of 1.0 to 1.0;

•

Ratio of Total Net Debt to Consolidated EBITDAX of not greater than 3.0 to 1.0 at the end of each quarter;

•

Ratio of Consolidated EBITDAX to Consolidated Interest Expense of not less than 2.5 to 1.0 for any four consecutive fiscal quarters;

•

Ratio of pre-tax PV-10 of our total Proved Developed Producing oil and gas reserves to Net Debt of at least 0.5 to 1.0 at June 30 and December 31 of any fiscal year;

•

Ratio of pre-tax PV-10 of our Total Proved oil and gas reserves plus 50% of our pre-tax probable oil and gas reserves, both adjusted for current oil and gas price estimates, to Net Debt of at least 3.0 to 1.0 at June 30 or December 31 of any fiscal year;

•

Commodity Hedging Agreements, based on forecasted production attributable to our proved producing reserves and calculated on a twelve rolling month basis, of (i) not less than 60% during the year subsequent to measurement, and (ii) not less than 40% during the second year subsequent to measurement;

•

limit during any fiscal year Permitted Business Investments, as defined, to $150.0 million or 7.5% of PV-10 value of our total proved reserves.

The foregoing description of the Existing Credit Agreement does not purport to be complete and is qualified in its entirety by reference to Amendment No. 1 filed as an exhibit to our annual current report on Form 8-K, dated March 23, 2007, and incorporated by reference herein. In addition, capitalized terms used but not defined in the foregoing description have the respective meanings assigned to such terms in the Existing Credit Agreement.

As of March 31, 2007, we were in compliance with all of the financial covenants of the Existing Credit Agreement. Significant adverse changes in our expected production levels, commodity prices and reserves or material delays or cost overruns could have a material adverse affect on our financial condition and results of operations and result in our non-compliance with these covenants. An event of non-compliance with any of the required covenants could result in a material mandatory repayment under the Existing Credit Agreement.

Commitments and Contingencies

In preparing financial statements at any point in time, management is periodically faced with uncertainties, the outcomes of which are not within its control and will not be known for prolonged periods of time. As discussed in Note 11 to the Consolidated Financial Statements, 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 ATP’s 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.

Critical Accounting Policies

Our discussion and analysis of our financial condition and results of operations are based on consolidated financial statements which have been prepared in accordance with generally accepted accounting principles in the United States. The preparation of these financial statements requires us to make estimates and judgments that affect the reported amounts or assets, liabilities, revenues and expenses. We believe that certain accounting policies affect our more significant judgments and estimates used in the preparation of our consolidated financial statements. Our 2006 Annual Report on Form 10-K, includes a discussion of our critical accounting policies.

Item 3. Quantitative and Qualitative Disclosures about Market Risks

Interest Rate Risk

We are exposed to changes in interest rates. Changes in interest rates affect the interest earned on our cash and cash equivalents and the interest rate paid on borrowings under the Term Loan. See the discussion of our Term Loan in Note 6 to the consolidated financial statements. Under our current policies, we do not use interest rate derivative instruments to manage exposure to interest rate changes.

Foreign Currency Risk.

The net assets, net earnings and cash flows from our wholly owned subsidiaries in the U.K. and the Netherlands are based on the U.S. dollar equivalent of such amounts measured in the applicable functional currency. These foreign operations have the potential to impact our financial position due to fluctuations in the local currency arising from the process of re-measuring the local currency in U.S. dollars. We have not utilized derivatives or other financial instruments to hedge the risk associated with the movement in foreign currencies relative to the U.S. dollar.

Commodity Price Risk

Our revenues, profitability and future growth depend substantially on prevailing prices for oil and 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 gas that we can economically produce. We currently sell a portion of our oil and gas production under price sensitive or market price contracts. We periodically use derivative instruments to hedge our commodity price risk. We hedge a portion of our projected oil and gas production through a variety of financial and physical arrangements intended to support oil and gas prices at targeted levels and to manage our exposure to price fluctuations. We may use futures contracts, swaps and fixed price

physical contracts to hedge our commodity prices. Realized gains and losses from our price risk management activities are recognized in oil and gas sales when the associated production occurs. For derivatives designated as cash flow hedges, the unrecognized gains and losses are included as a component of other comprehensive income (loss) to the extent the hedge is effective. See Note 10 to the Consolidated Financial Statements for additional information. We do not hold or issue derivative instruments for speculative purposes.

Our internal hedging policy provides that we examine the economic effect of entering into a commodity contract with respect to the properties that we acquire. We generally acquire properties at prices that are below management’s estimated value of the estimated proved reserves at the then current oil and gas prices. 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.

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

In order to ensure that the information we must disclose in our filings with the Securities and Exchange Commission is recorded, processed, summarized, and reported on a timely basis, we have formalized our disclosure controls and procedures. Our principal executive officer and principal financial officer have reviewed and evaluated the effectiveness of our disclosure controls and procedures, as defined in Exchange Act Rules 13a-15(e) and 15d-15(e), as of March 31, 2007. Based on that evaluation, such officers have concluded that, as of March 31, 2007, our disclosure controls and procedures were effective in timely alerting them to material information relating to us (and our consolidated subsidiaries) required to be included in our periodic SEC filings.

Changes in Internal Control Over Financial Reporting

During the three months ended March 31, 2007, we have made no change to our internal controls over financial reporting that has materially affected, or is reasonably likely to materially affect, our internal controls over financial reporting.

Item 4T is not applicable and has been omitted.

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 2006 Form 10-K.

PART II. OTHER INFORMATION

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

Item 6. Exhibits


Exhibits

31.1		Certification of Chief Executive Officer pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934.

31.2		Certification of Chief Financial Officer pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934.

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

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

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.

March 31,
2007

March 31,
2006

Cash paid during the period for interest

Cash paid during the period for income taxes