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 June 30, 2006

OR

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

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  ¨                Accelerated filer  x                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 August 3, 2006, was 30,138,995.

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

TABLE OF CO NTENTS

		Page
PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS (Unaudited)
	Consolidated Balance Sheets: June 30, 2006 and December 31, 2005	3
	Consolidated Statements of Operations: For the three and six months ended June 30, 2006 and 2005	4
	Consolidated Statements of Cash Flows: For the six months ended June 30, 2006 and 2005	5
	Consolidated Statements of Comprehensive Income (Loss): For the three and six months ended June 30, 2006 and 2005	6
	Notes to Consolidated Financial Statements	7
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS		16
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK		23
ITEM 4. CONTROLS AND PROCEDURES		23
PART II. OTHER INFORMATION		24

2

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)

	June 30, 2006			December 31, 2005
Assets
Current assets:
Cash and cash equivalents	$	202,809		$	65,566
Restricted cash		12,753			12,209
Accounts receivable (net of allowance of $348 and $367)		100,975			83,571
Derivative asset		3,123			—
Other current assets		8,704			4,454
Total current assets		328,364			165,800
Oil and gas properties (using the successful efforts method of accounting)
Proved properties		1,141,895			890,402
Unproved properties		20,509			8,882
		1,162,404			899,284
Less: Accumulated depletion, impairment and amortization		(333,103	)		(271,863	)
Oil and gas properties, net		829,301			627,421
Furniture and fixtures (net of accumulated depreciation)		1,179			1,175
Deferred tax asset		5,004			4,025
Financing costs		26,383			17,922
Other assets, net		11,639			7,420
Total assets	$	1,201,870		$	823,763
Liabilities and Shareholders’ Equity
Current liabilities:
Accounts payable and accruals	$	168,243		$	144,675
Current maturities of long-term debt		5,250			3,500
Current maturities of long-term capital lease		22,247			8,679
Asset retirement obligation		17,082			7,097
Derivative liability		—			1,282
Deferred tax liability		987			—
Total current liabilities		213,809			165,233
Long-term debt		514,182			337,489
Long-term capital lease		—			34,437
Asset retirement obligation		76,296			60,267
Deferred tax liability		2,093			—
Other long-term liabilities and deferred obligations		—			8,826
Total liabilities		806,380			606,252
Shareholders’ equity:
Preferred stock: $0.001 par value, 10,000,000 shares authorized; 325,000 issued and outstanding at June 30, 2006; 175,000 issued and outstanding at December 31, 2005		352,662			184,858
Common stock: $0.001 par value, 100,000,000 shares authorized; 30,206,585 issued and 30,130,745 outstanding at June 30, 2006; 29,668,517 issued and 29,592,677 outstanding at December 31, 2005		30			29
Additional paid-in capital		144,780			149,267
Accumulated deficit		(104,822	)		(101,333	)
Accumulated other comprehensive income (loss)		3,751			(4,693	)
Unearned compensation		—			(9,706	)
Treasury stock		(911	)		(911	)
Total shareholders’ equity		395,490			217,511
Total liabilities and shareholders’ equity	$	1,201,870		$	823,763

See accompanying notes to consolidated financial statements.

3

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(In Thousands, Except Per Share Amounts)

(Unaudited)

	Three Months Ended						Six Months Ended
	June 30, 2006			June 30, 2005			June 30, 2006			June 30, 2005
Revenues:
Oil and gas production	$	108,885		$	33,488		$	154,130		$	70,468
Costs and operating expenses:
Lease operating		21,259			6,007			31,952			10,581
Exploration		367			2,173			508			2,507
General and administrative		4,078			5,163			9,834			9,354
Stock-based compensation		3,297			—			5,526			—
Depreciation, depletion and amortization		43,249			15,201			60,519			35,704
Accretion		1,671			600			3,218			1,179
Loss on abandonment		3,451			76			3,506			76
		77,372			29,220			115,063			59,401
Income from operations		31,513			4,268			39,067			11,067
Other income (expense):
Interest income		1,207			998			1,780			1,488
Interest expense		(12,097	)		(8,595	)		(23,269	)		(14,884	)
Other income		—			7			—			8
		(10,890	)		(7,590	)		(21,489	)		(13,388	)
Income (loss) before income taxes		20,623			(3,322	)		17,578			(2,321	)
Income tax expense:
Current		1,841			—			1,841			—
Deferred		1,422			—			1,422			—
		3,263			—			3,263			—
Net income (loss)		17,360			(3,322	)		14,315			(2,321	)
Preferred stock dividends		(10,986	)		—			(17,804	)		—
Net income (loss) available to common shareholders	$	6,374		$	(3,322	)	$	(3,489	)	$	(2,321	)
Net income (loss) per common share Basic and diluted	$	0.21		$	(0.11	)	$	(0.12	)	$	(0.08	)
Weighted average number of common shares:
Basic		29,715			28,979			29,576			28,952
Diluted		30,396			29,794			30,302			29,788

See accompanying notes to consolidated financial statements.

4

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In Thousands)

(Unaudited)

	Six Months Ended
	June 30, 2006			June 30, 2005
Cash flows from operating activities
Net income (loss)	$	14,315		$	(2,321	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities –
Depreciation, depletion and amortization		60,519			35,704
Accretion		3,218			1,179
Deferred income taxes		1,422			—
Dry hole costs		—			2,107
Loss on abandonment		3,506			76
Amortization of deferred financing costs		2,341			1,792
Stock-based compensation		5,526			—
Ineffectiveness of cash flow hedges		(28	)		(173	)
Other noncash items		295			820
Changes in assets and liabilities –
Accounts receivable and other current assets		(20,779	)		3,361
Accounts payable and accruals		(19,676	)		(3,095	)
Other assets		(4,072	)		(626	)
Other long-term liabilities and deferred obligations		—			(54	)
Net cash provided by operating activities		46,587			38,770
Cash flows from investing activities
Additions and acquisitions of oil and gas properties		(203,445	)		(146,957	)
Additions to furniture and fixtures		(250	)		(182	)
Increase in restricted cash		129			—
Net cash used in investing activities		(203,566	)		(147,139	)
Cash flows from financing activities
Proceeds from long-term debt		178,500			132,113
Payments of long-term debt		(875	)		(1,425	)
Deferred financing costs		(11,116	)		(10,416	)
Issuance of preferred stock, net of issuance costs		145,463			—
Payments of capital lease		(20,869	)		—
Exercise of stock options		4,231			1,039
Other		—			(68	)
Net cash provided by financing activities		295,334			121,243
Effect of exchange rate changes on cash		(1,112	)		(766	)
Increase in cash and cash equivalents		137,243			12,108
Cash and cash equivalents, beginning of period		65,566			102,774
Cash and cash equivalents, end of period	$	202,809		$	114,882
Supplemental disclosures of cash flow information:
Cash paid during the period for interest	$	16,975		$	10,596

See accompanying notes to consolidated financial statements.

5

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(In Thousands)

(Unaudited)

	Three Months Ended						Six Months Ended
	June 30, 2006			June 30, 2005			June 30, 2006			June 30, 2005
Net income (loss)	$	17,360		$	(3,322	)	$	14,315		$	(2,321	)
Other comprehensive income (loss), net of tax:
Reclassification adjustment for settled contracts (net of income tax of $0)		727			76			2,009			(292	)
Change in fair value of outstanding hedge positions (net of income tax of $987 and $0 at June 30, 2006 and 2005)		(796	)		(1,772	)		(4,346	)		(2,239	)
Foreign currency translation adjustment		8,864			(2,201	)		10,782			(3,017	)
Other comprehensive income (loss)		8,795			(3,897	)		8,445			(5,548	)
Comprehensive income (loss)	$	26,155		$	(7,219	)	$	22,760		$	(7,869	)

See accompanying notes to consolidated financial statements.

6

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 North Sea. We seek to acquire and develop properties that are economically attractive to us but are not strategic to major or large exploration-oriented independent oil and gas companies. These properties usually contain proved undeveloped reserves (“PUD”) or reservoirs where previous drilling has encountered hydrocarbons 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. Occasionally we will acquire properties that are already producing or where limited low-risk exploration opportunities exist. We believe that our strategy provides assets for us to develop and produce without the risk, cost or time of traditional exploration.

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 2005 Annual Report on Form 10-K, as amended. The results of operations for the six months ended June 30, 2006 are not necessarily indicative of results to be expected for the entire year.

Note 2 — Recent Accounting Pronouncements

On July 13, 2006, the Financial Accounting Standards Board (“FASB”) issued FASB Interpretation No. 48 (“FIN 48”), ”Accounting for Uncertainty in Income Taxes — an interpretation of FAS 109.” FIN 48 clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with FASB Statement No. 109, Accounting for Income Taxes. FIN 48 prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. FIN 48 also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition. FIN 48 is effective for fiscal years beginning after December 15, 2006. We do not expect the implementation of FIN 48 to have a material impact on our financial statements.

Note 3 — Acquisitions

During the second quarter of 2006, ATP acquired 75% of the working interest in Mississippi Canyon (“MC”) Blocks 941 and 943, and 100% of the working interest in MC Block 942. During the first quarter of 2006, ATP acquired 100% of the working interest in Green Canyon Block 37. Three of the properties have logged proved reserves. The properties have been added to ATP’s development plan for 2006.

Note 4 — Asset Retirement Obligations

Following is a reconciliation of the beginning and ending asset retirement obligation for the period ended June 30, 2006 (in thousands):

	Six Months Ended June 30, 2006
Asset retirement obligation at January 1	$	67,364
Liabilities incurred		22,996
Liabilities settled		(857	)
Accretion		3,218
Foreign currency translation		657
Asset retirement obligation at end of period	$	93,378

7

Note 5 — Long-Term Debt

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

	June 30, 2006			December 31, 2005
Term loan, net of unamortized discount of $5,568 and $6,386	$	519,432		$	340,989
Less current maturities		(5,250	)		(3,500	)
Total long-term debt	$	514,182		$	337,489

On June 22, 2006 (the “Restatement Date”), ATP, the Lenders (“Lenders,” as defined in Article 1) and Credit Suisse (as Administrative Agent and Collateral Agent for the Lenders) entered into the Second Amended and Restated Credit Agreement (the “Term Loan Facility”). The Term Loan Facility will mature on April 14, 2010, and will amortize in equal quarterly installments (beginning September 30, 2006) in an aggregate annual amount equal to 1% of the original principal amount of the Facility through March 31, 2009, with the balance payable in equal quarterly installments during the final year of the Facility.

Pursuant to the Restated Credit Agreement, the Company borrowed additional amounts under terms and provisions (after giving effect to the amendments to be made to the existing credit agreement on the Restatement Date) identical to the existing term loans as of the Restatement Date, in an aggregate principal amount of $178.5 million, the proceeds of which will be used by the Company (a) to pay fees and expenses incurred in connection with the Term Loan Facility and (b) from time to time solely for general corporate purposes.

The Restated Credit Agreement amends and restates the existing credit agreement. Pursuant to the Restated Credit Agreement, the existing credit agreement was amended to effect, among other things, the following:

• increase the secured term loan facility from $350.0 million to $525.0 million;

• decrease the interest rate margin on any LIBOR loan from 5.50% to 3.25%;

• decrease the interest rate margin on any base rate loan from 4.50% to 2.25%;

• amend the U.K. and Netherlands subsidiary companies’ guarantees and security agreements (and in the case of the U.K. subsidiary, remove a first mortgage lien) to 65% stock pledges along with agreements not to pledge their assets in conjunction with any other borrowings;

• increase the limit on Capital Lease Obligations and Synthetic Lease Obligations from $50.0 million to $200.0 million at any time;

• increase the limit on Unsecured Indebtedness from $30.0 million to $60.0 million at any time;

• increase the amount of Permitted Business Investments (including Acquisitions) from $75.0 million to the greater of $150.0 million or 7.5% of the PV-10 reserves value in any fiscal year, and permit loans and advances of up to an aggregate $300.0 million at any time to any foreign subsidiary company to fund capital expenditures and other development costs in respect of oil and gas properties in the North Sea;

• allow for limited repurchases of the Company’s outstanding common stock; and,

• allow for the payment of cash dividends on outstanding Preferred Stock.

The Restated Credit Agreement contains the following modifications to financial covenants:

• Minimum Reserve Coverage Ratio (ratio of the aggregate value of proved plus 50% of probable reserves to total Net Debt) is 3.0 to 1.0 (formerly 2.5 to 1.0 without consideration of probable reserves); and,

• the Debt to Reserve Amount test (requirement to maintain Net Debt of less than $2.50 per unit of Proved Developed Reserves) has been eliminated.

8

As of the Restatement Date, the Company increased its aggregate borrowings under the Term Loan Facility by $178.5 million (from the balance outstanding as of March 31, 2006) to an aggregate outstanding principal amount of $525.0 million. From this increase in borrowings, the Company received net proceeds of $167.4 million after deducting $11.1 million for fees and expenses.

The Term Loan Facility bears interest at either the base rate plus a margin of 2.25% or LIBOR plus a margin of 3.25% at the election of ATP. At June 30, 2006, the weighted average rate on outstanding borrowings was approximately 8.92%.

As of June 30, 2006, we were in compliance with all of the financial covenants of our Term Loan Facility. 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 Term Loan Facility.

Note 6 — Preferred Stock

The Company’s preferred stock, par value $0.001 per share, consisted of the following (in thousands):

	June 30, 2006		December 31, 2005
Series A 13 1/2% cumulative perpetual preferred stock; 175,000 shares issued and outstanding at June 30, 2006 and December 31, 2005; liquidation preference at June 30, 2006 and December 31, 2005 of $1,128 and $1,056 per share, respectively	$	197,449	$	184,858
Series B 12 1/2% cumulative perpetual preferred stock; 150,000 shares issued and outstanding at June 30, 2006; liquidation preference of $1,035 per share		155,213		—
Junior participating preferred stock pursuant to the Shareholders Rights Plan; none issued		—		—

Series A Preferred

On August 2, 2005, ATP entered into a Subscription Agreement for the private placement of 175,000 shares of its 13.5% Series A cumulative perpetual preferred stock, par value, $0.001 per share (the “Series A Preferred Stock”), at a price of $1,000.00 per share. The Series A Preferred Stock is not convertible into the Company’s common stock. Aggregate gross proceeds to the Company were $175.0 million and the Company paid $5.25 million in placement agent commissions. The issuance of the Series A Preferred Stock was exempt from the registration requirements of the Securities Act of 1933, as amended, and was offered and issued only to institutional accredited investors.

The Subscription Agreement for the Series A Preferred Stock provides for: (1) an initial liquidation preference of $1,000.00 per share; (2) cumulative quarterly dividends at an initial rate of 13.5%, subject to escalation in the applicable dividend rate under certain conditions; (3) no voting rights (except as required by law or after the occurrence of various extraordinary events); (4) special provisions in the event of a fundamental change in the Company or the satisfaction of the Company’s currently outstanding debt; (5) limitations on incurrence of additional debt; and (6) restrictions on transfer or sale of the Series A Preferred Stock.

The Company has the right to redeem the Series A Preferred Stock at its option at any time after a fundamental change or the later of February 3, 2006 or the specified debt satisfaction date at a premium that declines until February 3, 2009, at which time the Series A Preferred Stock may be redeemed at 100% of the liquidation preference plus accrued and unpaid dividends.

In the event of a fundamental change in the Company or the repayment of the currently outstanding debt, the Company must notify the preferred stockholders whether it will offer to redeem the Series A Preferred Stock. If the Company chooses not to offer to redeem the Series A Preferred Stock, then it will be deemed a fundamental change offer default or a debt satisfaction offer default, as the case may be, and the applicable dividend rate will escalate by 5% per quarter, to a maximum of 25%. Such escalation will continue until either of such defaults is cured, unless the Company has previously exercised its optional redemption right with respect to all of the shares of Series A Preferred Stock then outstanding. The Company is under no obligation to offer to redeem the Series A Preferred Stock under any circumstances.

9

Series B Preferred

On March 20, 2006, ATP entered into a Subscription Agreement for the private placement of 150,000 shares of its 12.5% Series B cumulative perpetual preferred stock, par value, $0.001 per share (the “Series B Preferred Stock”), at a price of $1,000.00 per share. The Series B Preferred Stock is not convertible into the Company’s common stock. Aggregate gross proceeds to the Company were $150.0 million and the Company paid $4.5 million in placement agent commissions. The issuance of the Series B Preferred Stock was exempt from the registration requirements of the Securities Act of 1933, as amended, and was offered and issued only to institutional accredited investors.

The Statement of Resolutions establishing the Series B Preferred Stock provides for: (1) an initial liquidation preference of $1,000.00 per share; (2) cumulative quarterly dividends at an initial annual rate of 12.5%, subject to escalation in the applicable annual dividend rate under certain conditions; (3) no voting rights (except as required by law or after the occurrence of various extraordinary events); (4) special provisions in the event of a fundamental change in the Company or the satisfaction of the Company’s currently outstanding debt; (5) limitations on incurrence of additional debt; and (6) restrictions on transfer or sale of the Preferred Stock.

The Company has the right to redeem the Series B Preferred Stock at its option at any time at a premium that declines until February 3, 2009, at which time the preferred stock may be redeemed at 100% of the liquidation preference plus accrued and unpaid dividends.

In the event of a fundamental change in the Company or the repayment of the currently outstanding debt, the Company must notify the preferred stockholders whether it will offer to redeem the Series B Preferred Stock. If the Company chooses not to offer to redeem the Series B Preferred Stock, then it will be deemed a fundamental change offer default or a debt satisfaction offer default, as the case may be, and the applicable dividend rate will escalate by 5% per quarter, to a maximum of 25%. Such escalation will continue until either of such defaults is cured, unless the Company has previously exercised its optional redemption right with respect to all of the shares of Series B Preferred Stock then outstanding. The Company is under no obligation to offer to redeem the Series B Preferred Stock under any circumstances.

As of June 30, 2006, noncash preferred dividends were accrued for the Series A Preferred Stock and the Series B Preferred Stock in the amount of $22.4 million and $5.2 million, respectively. Such dividends may be paid in cash under the terms of each series of preferred stock upon the earlier to occur of full repayment of our existing Term Loan or April 15, 2011.

Note 7 — Stock–Based Compensation

Effective January 1, 2006, we adopted Statement of Financial Accounting Standards (“SFAS”) No. 123(R), “Accounting for Share-Based Payment,” as amended, using the modified prospective transition method which requires, among other things, current recognition of compensation expense for share-based compensation granted after January 1, 2006, and for that portion of prior period share-based compensation for which the requisite service has not been rendered that was outstanding as of January 1, 2006. We recognized stock option compensation expense of approximately $755,000 and $968,000 for the three months and six months ended June 30, 2006, respectively.

For periods prior to January 1, 2006, we applied to our stock-based compensation awards the intrinsic method of accounting as set forth in Accounting Principles Board (“APB”) Opinion No. 25, “Accounting for Stock Issued to Employees,” and related interpretations. The following table illustrates the effect on net income (loss) and earnings per share if we had applied the fair value recognition provisions of SFAS 123(R) to stock-based employee compensation during 2005 (in thousands, except for per-share data):

	Three Months Ended June 30, 2005			Six Months Ended June 30, 2005
Net loss available to common shareholders, as reported	$	(3,322	)	$	(2,321	)
Total stock based employee compensation benefit determined under fair value for all awards, net of related tax effects		(111	)		(222	)
Pro forma net loss	$	(3,433	)	$	(2,543	)
Earnings per share:
Basic and diluted earnings per share – as reported	$	(0.11	)	$	(0.08	)
Basic and diluted earnings per share – pro forma		(0.11	)		(0.08	)

10

The fair values of options granted during the three months and six months ended June 30, 2006 and 2005 were estimated at the date of grant using a Black-Scholes option-pricing model assuming no dividends and with the following weighted average assumptions for grants in 2006 and 2005:

	Three Months Ended				Six Months Ended
	June 30, 2006		June 30, 2005		June 30, 2006		June 30, 2005
Weighted average volatility	55	%	47	%	51	%	47	%
Expected term (in years)	4.3		4.0		4.3		4.0
Risk-free rate	4.9	%	3.6	%	4.6	%	3.7	%

Volatilities are based on the historical volatility of our closing common stock price. Expected term of options granted is derived from output of the option valuation model and represents the period of time that options granted are expected to be outstanding. The risk-free rate for periods within the contractual life of the options is based on the comparable U.S. Treasury rates in effect at the time of each grant. The weighted average grant-date fair value of options granted during the three months ended June 30, 2006 and 2005 was $16.67 and $6.44, respectively. The total intrinsic value of options exercised during the three months ended June 30, 2006 and 2005 was $8.3 million and $0.9 million, respectively.

The weighted average grant-date fair value of options granted during the six months ended June 30, 2006 and 2005 was $16.30 and $6.51, respectively. The total intrinsic value of options exercised during the six months ended June 30, 2006 and 2005 was $14.2 million and $3.7 million, respectively. The following table sets forth a summary of option transactions for the six-month period ended June 30, 2006:

	Number of Options		Weighted Average Grant Price		Aggregate Intrinsic Value ($000) (1)		Weighted Average Remaining Contractual Life
							(in years)
Outstanding at January 1	1,016,361		$	14.38
Granted	210,250			38.26
Exercised	(440,252	)		9.63
Forfeited	(25,715	)		13.58
Outstanding at end of period	760,644			23.76	$	13,931	3.89
Vested and expected to vest	702,835			23.66		12,844	3.82
Options exercisable at end of period	37,087			7.02		1,295	2.24

(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.

A summary of the status of ATP’s nonvested stock options as of June 30, 2006 and changes during the six months ended June 30, 2006 is presented below:

	Number of Options		Weighted Average Grant-date Fair Value
Nonvested at January 1	540,864		$	6.28
Granted	210,250			11.69
Vested	(17,557	)		3.32
Forfeited	(10,000	)		8.82
Nonvested at end of period	723,557			7.89

11

At June 30, 2006, 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 3.1 years.

On June 14, 2006, we granted 21,816 shares of restricted stock with a weighted average grant date fair value of $36.68 per share to our non-employee directors. Such restricted stock grants vest over a three-year period. On April 4, 2006, we granted 31,500 shares of restricted stock with a weighted average grant date fair value of $44.63 per share to our non-employee directors. Such restricted stock grants vest on January 15, 2007. On February 9, 2006, we granted 44,500 shares of restricted stock with a weighted average grant date fair value of $37.82 per share to employees. Such restricted stock grants vest over a three-year period. Each of the above restricted stock grants is subject to forfeiture, and cannot be sold, transferred or disposed of during the restriction period. The holders of the shares have voting and dividend rights with respect to such shares. We will recognize compensation expense over the vesting period of these shares. During the three months and six months ended June 30, 2006, we recognized aggregate compensation expense of $2.5 million and $4.6 million, respectively, related to outstanding restricted stock grants.

The following table sets forth the restricted stock transactions for the six months ended June 30, 2006:

	Number of Shares	Weighted Average Grant Date Fair Value		Aggregate Intrinsic Value ($000) (2)
Outstanding at January 1	265,363	$	36.79
Granted (1)	97,816		39.76
Outstanding at end of period	363,179		37.59	$	15,228

(1) The weighted average grant date fair value of restricted stock granted for the six months ended June 30, 2006 was $39.76. No restricted stock grants were outstanding at June 30, 2005.

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

At June 30, 2006, unrecognized compensation expense related to restricted stock totaled $9.1 million. Such unrecognized expense will be recognized as vesting occurs over a weighted average period of 2.3 years.

Note 8 — 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. In the table below, approximately 726,000 potential common stock equivalents have been excluded from the calculation for the six months ended June 30, 2006 because their effect would be antidilutive. Approximately 815,000 and 836,000 potential common stock equivalents have been excluded from the calculations for the three months and six months ended June 30, 2005, respectively, because their effect would be 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						Six Months Ended
	June 30, 2006			June 30, 2005			June 30, 2006			June 30, 2005
Income
Net income (loss)	$	17,360		$	(3,322	)	$	14,315		$	(2,321	)
Less preferred dividends		(10,986	)		—			(17,804	)		—
Net income (loss) available to common shareholders	$	6,374		$	(3,322	)	$	(3,489	)	$	(2,321	)
Shares outstanding
Weighted average shares outstanding - basic		29,715			28,979			29,576			28,952
Effect of potentially dilutive securities - stock options and warrants		565			815			639			836
Unvested restricted stock		116			—			87			—
Weighted average shares outstanding - diluted		30,396			29,794			30,302			29,788
Net income (loss) available to common shareholders per share:
Basic and diluted	$	0.21		$	(0.11	)	$	(0.12	)	$	(0.08	)

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Note 9 — Derivative Instruments and Price Risk Management Activities

Derivative financial instruments are utilized from time to time to manage or reduce commodity price risk related to our production. All derivatives are carried on the balance sheet at fair value. If the derivative is designated as a fair value hedge, the changes in the fair value of the derivative and of the hedged item attributable to the hedged risk are recognized in earnings. If the derivative is designated as a cash flow hedge, the effective portions of changes in the fair value of the derivative are recorded in other comprehensive income and are recognized in the consolidated statement of operations when the hedged item affects earnings. Ineffective portions of changes in the fair value of cash flow hedges are recognized in current earnings. Derivative contracts that do not qualify for hedge accounting, if any, are recorded at fair value on our consolidated balance sheet and the associated unrealized gains and losses are recorded as a component of revenues in the current period. As of June 30, 2006, all of our derivatives qualified for hedge accounting treatment.

We occasionally use derivative instruments with respect to a portion of our oil and gas production to manage our exposure to price volatility and to maintain compliance with our debt covenants. These instruments may take the form of futures contracts, swaps or options. A put option requires us to pay the counterparty the fair value of the option at the purchase date and receive from the counterparty the excess, if any, of the fixed floor price over the floating market price. The costs to purchase put options are amortized over the option period.

At June 30, 2006 and December 31, 2005, Accumulated Other Comprehensive Income (Loss) included $4.3 million of unrealized losses and $1.3 million of unrealized gains, respectively, on our cash flow hedges. Gains and losses are reclassified from Accumulated Other Comprehensive Income to the consolidated statement 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. These deferrals will be reversed during the period in which the forecasted transactions actually occur.

At June 30, 2006, 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	Average Price		Floor Price		Net Fair Value Asset (Liability)
				$/MMBtu		$/Bbl		($000)
Natural Gas (MMBtu)
North Sea	2006	Swaps	1,106,000	$	15.07		—	$	2,364
North Sea	2007	Swaps	1,040,000		15.04		—		103
Oil (Bbls)
Gulf of Mexico	2006	Puts	1,012,000		—	$	57.50		136
Gulf of Mexico	2007	Puts	860,000		—		58.56		893

(1) The price and net fair value liability of our cash flow hedges of our U.K. production have been translated at the June 30, 2006 translation rate of $1.8163 to £1.0.

Subsequent to June 30, 2006, we have hedged an additional 576,500 Bbl of oil for 2007 and 2008 with fixed forward contracts at prices ranging from $76.55 per Bbl to $80.10 per Bbl.

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 under SFAS 133, as amended. This exemption permits, at our option, the use of the accrual basis of accounting as

13

opposed to fair value accounting for the contracts. At June 30, 2006, we had fixed-price contracts in place for the following natural gas and oil volumes:

Period	Volumes	Average Fixed Price (1)
Natural gas (MMBtu)
Gulf of Mexico:
2006	2,434,000	$	9.07
2007	1,350,000		10.83
North Sea:
2006	460,000	$	15.80
2007	450,000		15.80
Oil (Bbl) – Gulf of Mexico:
2006	588,800	$	65.21
2007	1,223,500		69.17

(1) Includes the effect of basis differentials.

Note 10 — Commitments and Contingencies

Contingencies

The hurricane season of 2005 resulted in significant delays in our development activities, additional costs to these developments, repairs to existing producing properties and production losses and deferments in 2005 and 2006 at many of our producing properties. Most of the physical damage to our assets was covered by our insurance. At June 30, 2006 and December 31, 2005, we had a receivable for approximately $14.8 million and $13.5 million, respectively (net of $0.5 million in deductibles for hurricanes Katrina and Rita) for our expected insurance recovery of damage assessment costs and repairs which were made during the periods. In addition, we expect to recover amounts under our loss of production insurance policy, however due to the uncertainty of the ultimate amount no receivable has been recorded for that expected recovery.

During 2005, we purchased additional interest in the Tors property in the U.K. sector of the North Sea, and agreed to pay the seller contingent consideration of £2.0 million 180 days after first production, interest on such amount if the payment date meets certain criteria, and a second and third contingent payment of £1.0 million each after certain cumulative production amounts have been achieved from the property. During the three months ended June 30, 2006, we recorded a liability for $3.6 million (£2.0 million) for the initial obligation.

During 2001, we purchased three properties in the U.K. Sector—North Sea. In accordance with the purchase agreement, we also committed to pay future consideration contingent upon the successful development and operation of the properties. The contingent consideration for each property includes amounts to be paid upon achieving first commercial production and upon achieving designated cumulative production levels. The first threshold of initial commercial production was achieved in 2004 on one property and such related contingent consideration was paid and capitalized as acquisition costs. Upon achievement of the second threshold for the one property, the remaining contingent consideration will be accrued and capitalized at that time. Future development has commenced on the other two properties and when they reach their respective thresholds, the appropriate consideration will be recorded.

In February 2003, we acquired a 50% working interest in a block located in the Dutch Sector—North Sea. The remaining 50% interest is owned by a Dutch company who participates on behalf of the Dutch state. In April 2003, we received €7.4 million from the partner related to development costs on this block. We agreed to develop the property within 60 months from receipt of the funds or return the funds with interest if commercial production is not achieved at the expiration of such time. At December 31, 2005, the amount is reflected as a long-term liability of $8.8 million in the accompanying financial statements. The property was developed during 2005 and commenced production in February 2006, at which time we reclassified this liability as a reduction in the basis of our oil and gas properties since our obligation under the agreement has now been fulfilled.

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At the time of receipt, we determined the payment was not taxable at that time due to the obligation for substantial future performance. During a recent tax audit of our Dutch subsidiary, the tax authorities have concluded that receipt of the payment was a taxable event at the time of receipt and taxes and interest are currently due on this payment in the amount of approximately €3.4 million ($4.3 million). Accordingly, we have provided for this contingency and recorded a current liability in the amount of the taxes and interest. We recorded a deferred tax asset for this contingency, however we have not recorded a valuation allowance against this deferred tax asset as it resulted from a timing difference on the revenue recognition of the receipt of the payment. We do not agree with the position that has been taken by the Dutch tax authorities and, if necessary, we will defend our position vigorously.

Litigation

We are, in the ordinary course of business, a claimant and/or defendant in various legal proceedings. Management does not believe that the outcome of these legal proceedings, individually, and in the aggregate will have a materially adverse effect on our financial condition, results of operations or cash flows.

Note 11 — 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 and six months ended June 30, 2006 and 2005 is as follows (in thousands):

	Gulf of Mexico		North Sea			Total
For the Three Months Ended –
June 30, 2006:
Revenues	$	86,111	$	22,774		$	108,885
Depreciation, depletion and amortization		31,478		11,771			43,249
Income from operations		26,140		5,373			31,513
Additions to oil and gas properties		108,167		58,876			167,043
June 30, 2005:
Revenues	$	31,461	$	2,027		$	33,488
Depreciation, depletion and amortization		13,799		1,402			15,201
Income from operations		5,058		(790	)		4,268
Additions to oil and gas properties		60,687		40,005			100,692
For the Six Months Ended –
June 30, 2006:
Revenues	$	125,584	$	28,546		$	154,130
Depreciation, depletion and amortization		46,518		14,001			60,519
Income from operations		32,515		6,552			39,067
Total assets		901,218		300,652			1,201,870
Additions to oil and gas properties		171,018		92,102			263,120
June 30, 2005:
Revenues	$	64,131	$	6,337		$	70,468
Depreciation, depletion and amortization		32,123		3,580			35,704
Income from operations		11,508		(441	)		11,067
Total assets		388,436		102,357			490,793
Additions to oil and gas properties		104,577		42,380			146,957

15

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 that are economically attractive to us but are not strategic to major or large exploration-oriented independent oil and gas companies. These properties usually contain proved undeveloped reserves (“PUD”) or reservoirs where previous drilling has encountered hydrocarbons 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. Occasionally we will acquire properties that are already producing or where limited low-risk exploration opportunities exist. 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 properties 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 undeveloped reserves and reservoirs, 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 practically all 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 project and commence production.

To enhance the economics and return on investment of a project, we sometimes develop the project to a value creation point and either sell an interest or bring in partners on a promoted basis during the high capital development phase. For example, in 2005 we sold a 15% interest on a promoted basis in our Tors project in the U.K. Sector of the North Sea after the field development plan was obtained.

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 the 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. The use of certain types of derivative instruments may prevent us from realizing the full benefit of upward price movements.

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Second Quarter 2006 Highlights

Our financial and operating performance for the second quarter of 2006 included the following highlights:

• Achieved quarterly production of 13.5 Bcfe, an increase of 128% over first quarter 2006 production of 5.9 Bcfe;

• Recorded quarterly revenue of $108.9 million and net income available to common shareholders of $6.4 million;

• Improved the financial strength of our Term Loan by reducing the interest rate from LIBOR plus 5.50% to LIBOR plus 3.25% and increasing the size from $350.0 million to $525.0 million;

• Added new production in the second quarter from Tors and South Marsh Island 166, bringing to five the number of wells placed on production in the first half of 2006;

• Acquired four deepwater properties, three of which have logged hydrocarbons – Mirage, Morgus, Oasis, and Telemark – bringing to five the number of deepwater blocks acquired in 2006; and

• Finalizing completion of the third well at Mississippi Canyon 711 – well tie-in early 2007.

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 2005 Annual Report on Form 10-K, as amended.

Results of Operations

Three Months Ended June 30, 2006 Compared to Three Months Ended June 30, 2005

For the three months ended June 30, 2006, we reported net income available to common shareholders of $6.4 million, or $0.21 per basic and diluted share on total revenue of $108.9 million, as compared with a net loss available to common shareholders of $3.3 million, or $0.11 per basic and diluted share, on total revenue of $33.5 million for the three months ended June 30, 2005.

Oil and Natural Gas Revenues. Revenues presented in the table and in the discussion below represent revenues from sales of our oil and natural gas production volumes, and exclude the impact, if any, of hedging ineffectiveness and revenues from ATP Energy, Inc., a wholly owned subsidiary. 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 25% and 58% of our natural gas production was sold under these contracts for the three months ended June 30, 2006 and 2005, respectively. Approximately 13% and 58% of our oil 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 June 30,					% Change in 2006 from 2005
	2006			2005
Production:
Natural gas (MMcf)		8,621			3,721		132	%
Oil and condensate (MBbls)		816			205		298	%
Total (MMcfe)		13,518			4,951		173	%
Revenues from production (in thousands):
Natural gas	$	61,738		$	24,627		151	%
Effects of cash flow hedges		(879	)		(255	)	(245	)%
Total	$	60,859		$	24,372		150	%
Oil and condensate	$	48,018		$	8,944		437	%
Effects of cash flow hedges		—			—		—
Total	$	48,018		$	8,944		437	%
Natural gas, oil and condensate	$	109,756		$	33,571		227	%
Effects of cash flow hedges		(879	)		(255	)	(245	)%
Total	$	108,877		$	33,316		227	%
Average sales price per unit:
Natural gas (per Mcf)	$	7.16		$	6.62		8	%
Effects of cash flow hedges (per Mcf)		(0.10	)		(0.07	)	(43	)%
Total (per Mcf)	$	7.06		$	6.55		8	%
Oil and condensate (per Bbl)	$	58.85		$	43.57		35	%
Effects of cash flow hedges (per Bbl)		—			—		—
Total (per Bbl)	$	58.85		$	43.57		35	%
Natural gas, oil and condensate (per Mcfe)	$	8.12		$	6.78		20	%
Effects of cash flow hedges (per Mcfe)		(0.07	)		(0.05	)	(40	)%
Total (per Mcfe)	$	8.05		$	6.73		20	%

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Revenues from production increased 227% in the second quarter of 2006 compared to the same period in 2005. During the second quarter of 2006, our production increased 173% from the comparative period in 2005 due to significant production from our new developments at L-06 in the Dutch Sector North Sea, Tors in the UK sector North Sea and Mississippi Canyon 711 (Gomez) in the Gulf of Mexico. The comparable revenues were impacted favorably by a 20% increase in our average sales price per unit.

Lease Operating. Lease operating expenses for the second quarter of 2006 increased to $21.3 million ($1.57 per Mcfe) from $6.0 million ($1.21 per Mcfe) in the second quarter of 2005. The increase was primarily attributable to the aforementioned increase in production, and the increase per unit of production was partly attributable to second quarter 2006 lease operating expense related to uninsured hurricane repairs performed on certain of our oil and gas properties in the Gulf of Mexico during the period.

Exploration. Exploration expense for the periods included geological and geophysical costs incurred in connection with evaluating oil and gas properties. Additionally, during the second quarter of 2005, exploration expense included costs related to an exploratory, step-out well at our producing Eugene Island 30/71 complex. This well found non-commercial quantities of hydrocarbons, resulting in exploration expense of approximately $2.2 million in the second quarter of 2005.

General and Administrative. General and administrative expense decreased to $4.1 million for the second quarter of 2006 compared to $5.2 million for the same period of 2005 primarily due to compensation related to the ATP Employee Volvo Challenge Plan which was charged to expense during 2005 and the first quarter of 2006. The plan was satisfied in the first quarter of 2006 and no such provision was necessary in the second quarter of 2006.

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization (“DD&A”) expense increased $28.0 million (185%) during the second quarter of 2006 to $43.2 million from $15.2 million for the same period in 2005. The overall DD&A expense increase was mainly due to increased production from our newly developed properties in 2006. The average DD&A rate was $3.20 per Mcfe in the second quarter of 2006 compared to $3.07 per Mcfe in the same quarter of 2005.

Accretion. Accretion expense increased to $1.7 million for the second quarter of 2006 compared to $0.6 million for the same period of 2005 primarily due to the accretion associated with the new abandonment liabilities incurred late in 2005 and early 2006.

Loss on Abandonment. During the second quarter of 2006 we recorded a $3.5 million loss on abandonment as we were unexpectedly required to abandon a Gulf of Mexico well with a drilling rig instead of the intended lower cost method originally estimated.

Income Taxes. We recorded a tax provision of $3.3 million during the quarter ended June 30, 2006, related to our foreign jurisdictions, based on the expected 2006 effective tax rate of each jurisdiction. The rates were determined based on the projected results of operations for the year, the valuation allowance released and permanent differences affecting the overall tax rate in each foreign jurisdiction. In the U.S., the tax provision recorded on our book income was offset by a release of valuation allowance. In the comparable quarter of 2005 we recorded a tax benefit based on our losses, which was offset by a valuation allowance.

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Six Months Ended June 30, 2006 Compared to Six Months Ended June 30, 2005

For the six months ended June 30, 2006, we reported net loss available to common shareholders of $3.5 million, or $0.12 per basic and diluted share on total revenue of $154.1 million as compared with a net loss available to common shareholders of $2.3 million, or $0.08 per share, on total revenue of $70.5 million for the six months ended June 30, 2005.

Oil and Natural Gas Revenues. Revenues presented in the table and in the discussion below represent revenues from sales of our oil and natural gas production volumes, and exclude the impact, if any, of hedging ineffectiveness and revenues from ATP Energy, Inc., a wholly owned subsidiary. 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 30% and 50% of our natural gas production was sold under these contracts for the six months ended June 30, 2006 and 2005, respectively. Approximately 22% and 58%, respectively, of our oil 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.

	Six Months Ended June 30,					% Change in 2006 from 2005
	2006			2005
Production:
Natural gas (MMcf)		13,654			8,315	64	%
Oil and condensate (MBbls)		966			403	140	%
Total (MMcfe)		19,452			10,730	81	%
Revenues from production (in thousands):
Natural gas	$	100,694		$	53,264	89	%
Effects of cash flow hedges		(1,329	)		157	(946	)%
Total	$	99,365		$	53,421	86	%
Oil and condensate	$	54,737		$	16,874	224	%
Effects of cash flow hedges		—			—	—
Total	$	54,737		$	16,874	224	%
Natural gas, oil and condensate	$	155,431		$	70,138	122	%
Effects of cash flow hedges		(1,329	)		157	(946	)%
Total	$	154,102		$	70,295	119	%
Average sales price per unit:
Natural gas (per Mcf)	$	7.37		$	6.41	15	%
Effects of cash flow hedges (per Mcf)		(0.10	)		0.02	(600	)%
Total (per Mcf)	$	7.28		$	6.43	13	%
Oil and condensate (per Bbl)	$	56.64		$	41.87	35	%
Effects of cash flow hedges (per Bbl)		—			—	—
Total (per Bbl)	$	56.64		$	41.87	35	%
Natural gas, oil and condensate (per Mcfe)	$	7.99		$	6.54	22	%
Effects of cash flow hedges (per Mcfe)		(0.07	)		0.01	(800	)%
Total (per Mcfe)	$	7.92		$	6.55	21	%

Revenues from production increased 119% in the first half of 2006 compared to the same period in 2005. During the current period our production increased 81% from the comparative period in 2005 due to significant production from our new developments at L-06 in the Dutch Sector North Sea, Tors in the UK sector North Sea and Mississippi Canyon 711 (Gomez) in the Gulf of Mexico. The comparable revenues were impacted favorably by a 21% increase in our average sales price per unit.

Lease Operating. Lease operating expenses for the first half of 2006 increased to $32.0 million ($1.64 per Mcfe) from $10.6 million ($0.99 per Mcfe) in the first half of 2005. The increase was primarily attributable to the aforementioned increase in production, and the increase per unit of production was partly attributable to first half 2006 lease operating expense related to uninsured hurricane repairs performed on our oil and gas properties in the Gulf of Mexico, whereas in 2005 we did not incur such expenditures.

19

Exploration. During the first half of 2005, exploration expense includes one exploratory, step-out well at our producing Eugene Island 30/71 complex. This well found non-commercial quantities of hydrocarbons, resulting in exploration and dry hole expense of approximately $2.2 million in the first half of 2005.

General and Administrative. General and administrative expense increased to $9.8 million for the first half of 2006 compared to $9.4 million for the same period of 2005. The increase was primarily attributable to an increase in professional and consulting fees related to development activity incurred in the first half of 2006. The increase was partially offset by a decrease in compensation expense due to compensation related to the ATP Employee Volvo Challenge Plan which was charged to expense in the first two quarters of 2005 versus only the first quarter in 2006. The plan was satisfied in the first quarter of 2006 and no such provision was necessary in the second quarter of 2006.

Depreciation, Depletion and Amortization. DD&A expense increased $24.8 million (70%) during the first half of 2006 to $60.5 million from $35.7 million for the same period in 2005. The overall DD&A expense increase was mainly due to increased production from our newly developed properties in 2006. The average DD&A rate was $3.11 per Mcfe in the first half of 2006 compared to $3.33 per Mcfe in the first half of 2005.

Accretion. Accretion expense increased to $3.2 million for the first half of 2006 compared to $1.2 million for the same period of 2005 primarily due to the accretion associated with the new abandonment liabilities incurred late in 2005 and early 2006.

Loss on Abandonment. During the second quarter of 2006 we recorded a $3.5 million loss on abandonment as we were unexpectedly required to abandon a Gulf of Mexico well with a drilling rig instead of the intended lower cost method originally estimated.

Income Taxes. We recorded a tax provision of $3.3 million during the six months ended June 30, 2006, related to our foreign jurisdictions, based on the expected 2006 effective tax rate of each jurisdiction. The rates were determined based on the projected results of operations for the year, the valuation allowance released and permanent differences affecting the overall tax rate in each foreign jurisdiction. In the U.S., the tax provision recorded on our book income was offset by a release of valuation allowance. In the comparable period of 2005 we recorded a tax benefit based on our losses, which was offset by a valuation allowance.

Liquidity and Capital Resources

At June 30, 2006, we had working capital of approximately $114.6 million, an increase of approximately $114.0 million from December 31, 2005.

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 and debt 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	Six Months Ended
	June 30, 2006		June 30, 2005
Cash provided by (used in):
Operating activities	46,587		38,770
Investing activities	(203,566	)	(147,139	)
Financing activities	295,334		121,243

Cash provided by operating activities during the six months ended June 30, 2006 and 2005 was $46.6 million and $38.8 million, respectively. Cash flow from operations increased due to higher oil and gas production revenues during the first half of 2006 compared to the first quarter of 2005. The increase in sales revenue was attributable to

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higher oil and gas production and higher average oil and gas prices during the first half of 2006. The increase in cash flows as a result of the increased revenues was offset by the higher lease operating expense associated with that production and by the timing of payments and receipts in our payables and receivables.

Cash used in investing activities was $203.6 million and $147.1 million during the six months ended June 30, 2006 and 2005, respectively. Cash expended in the Gulf of Mexico and North Sea was approximately $130.8 million and $72.6 million in the first half of 2006. Additions to oil and gas properties in the Gulf of Mexico and North Sea were approximately $104.6 million and $42.4 million in the first half of 2005.

Cash provided by financing activities was $295.3 million and $121.2 million during the six months ended June 30, 2006 and 2005, respectively. Such amount for the 2006 period was primarily due to the increase in our Term Loan Facility of $167.4 million (net of issuance costs) and the issuance of 12.5% Series B Cumulative Preferred Stock for $145.5 million (net of issuance costs), partially offset by capital lease and debt payments.

Term Loan

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

	June 30, 2006			December 31, 2005
Term loan, net of unamortized discount of $5,568 and $6,386	$	519,432		$	340,989
Less current maturities		(5,250	)		(3,500	)
Total long-term debt	$	514,182		$	337,489

On June 22, 2006 (the “Restatement Date”), ATP, the Lenders (“Lenders,” as defined in Article 1) and Credit Suisse (as Administrative Agent and Collateral Agent for the Lenders) entered into the Second Amended and Restated Credit Agreement (the “Term Loan Facility”). The Term Loan Facility will mature on April 14, 2010, and will amortize in equal quarterly installments (beginning September 30, 2006) in an aggregate annual amount equal to 1% of the original principal amount of the Facility through March 31, 2009, with the balance payable in equal quarterly installments during the final year of the Facility.

Pursuant to the Restated Credit Agreement, the Company borrowed additional amounts under terms and provisions (after giving effect to the amendments to be made to the existing credit agreement on the Restatement Date) identical to the existing term loans as of the Restatement Date, in an aggregate principal amount of $178.5 million, the proceeds of which will be used by the Company (a) to pay fees and expenses incurred in connection with the Term Loan Facility and (b) from time to time solely for general corporate purposes.

The Restated Credit Agreement amends and restates the existing credit agreement. Pursuant to the Restated Credit Agreement, the existing credit agreement was amended to effect, among other things, the following:

• increase the secured term loan facility from $350.0 million to $525.0 million;

• decrease the interest rate margin on any LIBOR loan from 5.50% to 3.25%;

• decrease the interest rate margin on any base rate loan from 4.50% to 2.25%;

• amend the U.K. and Netherlands subsidiary companies’ guarantees and security agreements (and in the case of the U.K. subsidiary, remove a first mortgage lien) to 65% stock pledges along with agreements not to pledge their assets in conjunction with any other borrowings;

• increase the limit on Capital Lease Obligations and Synthetic Lease Obligations from $50.0 million to $200.0 million at any time;

• increase the limit on Unsecured Indebtedness from $30.0 million to $60.0 million at any time;

• increase the amount of Permitted Business Investments (including Acquisitions) from $75.0 million to the greater of $150.0 million or 7.5% of the PV-10 reserves value in any fiscal year, and permit loans and advances of up to an aggregate $300.0 million at any time to any foreign subsidiary company to fund capital expenditures and other development costs in respect of oil and gas properties in the North Sea;

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• allow for limited repurchases of the Company’s outstanding common stock; and,

• allow for the payment of cash dividends on outstanding Preferred Stock.

The Restated Credit Agreement contains the following modifications to financial covenants:

• Minimum Reserve Coverage Ratio (ratio of the aggregate value of proved plus 50% of probable reserves to total Net Debt) is 3.0 to 1.0 (formerly 2.5 to 1.0 without consideration of probable reserves); and,

• the Debt to Reserve Amount test (requirement to maintain Net Debt of less than $2.50 per unit of Proved Developed Reserves) has been eliminated.

As of the Restatement Date, the Company increased its aggregate borrowings under the Term Loan Facility by $178.5 million (from the balance outstanding as of March 31, 2006) to an aggregate outstanding principal amount of $525.0 million. From this increase in borrowings, the Company received net proceeds of $167.4 million after deducting $11.1 million for fees and expenses.

The Term Loan Facility bears interest at either the base rate plus a margin of 2.25% or LIBOR plus a margin of 3.25% at the election of ATP. At June 30, 2006, the weighted average rate on outstanding borrowings was approximately 8.92%.

As of June 30, 2006, we were in compliance with all of the financial covenants of our Term Loan Facility. 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 Term Loan Facility.

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 10 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.

Accounting Pronouncements

See Note 2 to our Consolidated Financial Statements 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. Our 2005 Annual Report on Form 10-K, as amended, includes a discussion of our critical accounting policies.

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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 5 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 9 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 the 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 June 30, 2006. Based on that evaluation, such officers have concluded that, as of June 30, 2006, 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.

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Changes in Internal Control Over Financial Reporting

During the three months ended June 30, 2006, we have made no change to our internal controls over financial reporting that has materially affected, or is reasonably likely to materially affect, our internal controls over financial reporting.

Forward-Looking Statements and Associated Risks

This Quarterly Report contains projections and other forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934. These projections and statements reflect the Company’s current views with respect to future events and financial performance. No assurances can be given, however, that these events will occur or that these projections will be achieved and actual results could differ materially from those projected as a result of certain factors. A discussion of these factors is included in the Company’s 2005 Form 10-K, as amended.

PART II. OTHER INFORMATION

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

Item 4. Submission of Matters to a Vote of Security Holders

The following items were presented for approval to stockholders of record on April 17, 2006 at the Company’s annual meeting of stockholders which was held on June 14, 2006 in Houston, Texas:

	For	Against	Withheld or Abstained
(i) Election of Directors:
Arthur H. Dilly	25,998,668	—	488,967
Robert C. Thomas	26,020,546	—	467,089
Burt A. Adams	26,261,946	—	225,689
George R. Edwards	26,259,206	—	228,429
Robert J. Karow	26,262,306	—	225,329
(ii) Ratification of Deloitte & Touche LLP, independent certified public accountants, as auditors of the Company’s 2006 financial statements	26,451,578	28,341	7,716

All matters received the required number of votes for approval.

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.

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SIGNATURES

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

	ATP Oil & Gas Corporation
Date: August 8, 2006	By:	/s/ Albert L. Reese, Jr.
		Albert L. Reese, Jr.
		Chief Financial Officer

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EX-31.1

EXHIBIT 31.1

ATP OIL & GAS CORPORATION

Section 302 Certification of Principal Executive Officer

I, T. Paul Bulmahn, Chief Executive Officer and President (Principal Executive Officer) certify that:

1. I have reviewed this Form 10-Q for the quarterly period ended June 30, 2006 of ATP Oil & Gas Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:	August 8, 2006	/s/ T. Paul Bulmahn
		Chairman and President

EX-31.2

EXHIBIT 31.2

ATP OIL & GAS CORPORATION

Section 302 Certification of Principal Financial Officer

I, Albert L. Reese, Jr., Chief Financial Officer (Principal Financial Officer) certify that:

1. I have reviewed this Form 10-Q for the quarterly period ended June 30, 2006 of ATP Oil & Gas Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:	August 8, 2006	/s/ Albert L. Reese
		Chief Financial Officer

EX-32.1

Exhibit 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

I, T. Paul Bulmahn, Chairman and Chief Executive Officer of ATP Oil & Gas Corporation (the “Company”), do hereby certify that the Quarterly Report on Form 10-Q (the “Report”) for the quarterly period ended March 31, 2006, filed with the Securities Exchange Commission on the date hereof:

1) fully complies with the requirements of section 13 (a) or 15 (d) of the Securities Exchange Act of 1934; and

2) the information contained in the Report fairly represents, in all material respects, the financial condition and the results of operations of the Company.

Date: August 8, 2006	By:	/s/ T. Paul Bulmahn
		T. Paul Bulmahn
		Chairman and President

EX-32.2

Exhibit 32.2

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

I, Albert L. Reese, Jr., Chief Financial Officer of ATP Oil & Gas Corporation (the “Company”), do hereby certify that the Quarterly Report on Form 10-Q (the “Report”) for the quarterly period ended March 31, 2006, filed with the Securities Exchange Commission on the date hereof:

1) fully complies with the requirements of section 13 (a) or 15 (d) of the Securities Exchange Act of 1934; and

2) the information contained in the Report fairly represents, in all material respects, the financial condition and the results of operations of the Company.

August 8, 2006	By:	/s/ Albert L. Reese, Jr.
		Albert L. Reese, Jr.
		Chief Financial Officer