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 September 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 November 6, 2006, was 30,143,245.

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

TABLE OF CONTENTS

	Page
PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS (Unaudited)
Consolidated Balance Sheets: September 30, 2006 and December 31, 2005	3
Consolidated Statements of Operations: For the three and nine months ended September 30, 2006 and 2005	4
Consolidated Statements of Cash Flows: For the nine months ended September 30, 2006 and 2005	5
Consolidated Statements of Comprehensive Income (Loss): For the three and nine months ended September 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	17
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	25
ITEM 4. CONTROLS AND PROCEDURES	25
PART II. OTHER INFORMATION	26

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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)

	September 30, 2006			December 31, 2005
Assets
Current assets:
Cash and cash equivalents	$	61,263		$	65,566
Restricted cash		26,298			12,209
Accounts receivable (net of allowance of $308 and $367)		148,714			83,571
Deferred tax asset		4,633			—
Derivative asset		1,272			—
Other current assets		12,464			4,454
Total current assets		254,644			165,800
Oil and gas properties (using the successful efforts method of accounting)
Proved properties		1,348,746			890,402
Unproved properties		33,936			8,882
		1,382,682			899,284
Less: Accumulated depletion, impairment and amortization		(400,646	)		(271,863	)
Oil and gas properties, net		982,036			627,421
Furniture and fixtures (net of accumulated depreciation)		1,136			1,175
Deferred tax asset		1,342			4,025
Derivative asset		177			—
Deferred financing costs, net		24,337			17,922
Other assets, net		11,549			7,420
Total assets	$	1,275,221		$	823,763
Liabilities and Shareholders’ Equity
Current liabilities:
Accounts payable and accruals	$	208,987		$	144,675
Current maturities of long-term debt		5,250			3,500
Current maturities of long-term capital lease		22,962			8,679
Asset retirement obligation		13,201			7,097
Derivative liability		—			1,282
Total current liabilities		250,400			165,233
Long-term debt		513,301			337,489
Long-term capital lease		—			34,437
Asset retirement obligation		87,967			60,267
Deferred tax liability		5,738			—
Other long-term liabilities and deferred obligations		—			8,826
Total liabilities		857,406			606,252
Shareholders’ equity:
Preferred stock: $0.001 par value, 10,000,000 shares authorized; 325,000 issued and outstanding at September 30, 2006; 175,000 issued and outstanding at December 31, 2005		364,198			184,858
Common stock: $0.001 par value, 100,000,000 shares authorized; 30,219,085 issued and 30,143,245 outstanding at September 30, 2006; 29,668,517 issued and 29,592,677 outstanding at December 31, 2005		30			29
Additional paid-in capital		148,125			149,267
Accumulated deficit		(103,649	)		(101,333	)
Accumulated other comprehensive income (loss)		10,022			(4,693	)
Unearned compensation		—			(9,706	)
Treasury stock		(911	)		(911	)
Total shareholders’ equity		417,815			217,511
Total liabilities and shareholders’ equity	$	1,275,221		$	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						Nine Months Ended
	September 30, 2006			September 30, 2005			September 30, 2006			September 30, 2005
Revenues:
Oil and gas production	$	132,822		$	26,342		$	286,952		$	96,810
Costs and operating expenses:
Lease operating		22,848			4,796			54,800			15,377
Exploration		1,660			3,067			2,168			5,574
General and administrative		4,643			3,893			14,477			13,247
Stock-based compensation		3,160			—			8,686			—
Depreciation, depletion and amortization		55,026			12,289			115,545			47,993
Impairment of oil and gas properties		11,760			—			11,760			—
Accretion		2,255			622			5,473			1,801
Loss on abandonment		349			248			3,855			324
		101,701			24,915			216,764			84,316
Income from operations		31,121			1,427			70,188			12,494
Other income (expense):
Interest income		1,377			1,518			3,157			3,006
Interest expense		(14,780	)		(9,760	)		(38,049	)		(24,644	)
Other income (expense)		—			(6	)		—			2
		(13,403	)		(8,248	)		(34,892	)		(21,636	)
Income (loss) before income taxes		17,718			(6,821	)		35,296			(9,142	)
Income tax (expense) benefit:
Current		(2,195	)		—			(4,036	)		—
Deferred		(2,814	)		—			(4,236	)		—
		(5,009	)		—			(8,272	)		—
Net income (loss)		12,709			(6,821	)		27,024			(9,142	)
Preferred stock dividends		(11,536	)		(3,756	)		(29,340	)		(3,756	)
Net income (loss) available to common shareholders	$	1,173		$	(10,577	)	$	(2,316	)	$	(12,898	)
Net income (loss) per common share – basic and diluted	$	0.04		$	(0.36	)	$	(0.08	)	$	(0.44	)
Weighted average number of common shares:
Basic		29,776			29,109			29,643			29,005
Diluted		30,406			29,922			30,342			29,833

See accompanying notes to consolidated financial statements.

4

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In Thousands)

(Unaudited)

	Nine Months Ended
	September 30, 2006			September 30, 2005
Cash flows from operating activities
Net income (loss)	$	27,024		$	(9,142	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities –
Depreciation, depletion and amortization		115,545			47,993
Impairment of oil and gas properties		11,760			—
Accretion		5,473			1,801
Deferred income taxes		4,236			—
Dry hole costs		—			5,164
Amortization of deferred financing costs		4,387			2,982
Stock-based compensation		8,686			—
Ineffectiveness of cash flow hedges		45			(189	)
Other noncash items		4,424			1,320
Changes in assets and liabilities –
Accounts receivable and other current assets		(81,935	)		7,269
Accounts payable and accruals		9,955			4,185
Other assets		(1,146	)		—
Other long-term liabilities and deferred obligations		(3,108	)		7
Net cash provided by operating activities		105,346			61,390
Cash flows from investing activities
Additions and acquisitions of oil and gas properties		(390,916	)		(272,603	)
Additions to furniture and fixtures		(331	)		(427	)
Increase in restricted cash		(13,296	)		(12,312	)
Net cash used in investing activities		(404,543	)		(285,342	)
Cash flows from financing activities
Proceeds from long-term debt		178,500			132,113
Payments of long-term debt		(2,188	)		(2,300	)
Deferred financing costs		(11,116	)		(10,416	)
Issuance of preferred stock, net of issuance costs		145,463			169,440
Payments of capital lease		(20,869	)		—
Exercise of stock options		4,416			3,536
Other		—			(68	)
Net cash provided by financing activities		294,206			292,305
Effect of exchange rate changes on cash		688			(3,757	)
Increase (decrease) in cash and cash equivalents		(4,303	)		64,596
Cash and cash equivalents, beginning of period		65,566			102,774
Cash and cash equivalents, end of period	$	61,263		$	167,370
Supplemental disclosures of cash flow information:
Cash paid during the period for interest	$	26,717		$	20,194

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					Nine Months Ended
	September 30, 2006		September 30, 2005			September 30, 2006			September 30, 2005
Net income (loss) available to common shareholders	$	1,173	$	(10,577	)	$	(2,316	)	$	(12,898	)
Other comprehensive income (loss), net of tax:
Reclassification adjustment for settled contracts (net of income tax of $0)		1,429		297			3,439			5
Change in fair value of outstanding hedge positions (net of income tax of $0)		514		1,505			(3,832	)		(734	)
Foreign currency translation adjustment		4,327		(2,650	)		15,108			(5,667	)
Other comprehensive income (loss)		6,270		(848	)		14,715			(6,396	)
Comprehensive income (loss)	$	7,443	$	(11,425	)	$	12,399		$	(19,294	)

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 nine months ended September 30, 2006 are not necessarily indicative of results to be expected for the entire year.

Note 2 — Recent Accounting Pronouncements

In September 2006, the Securities and Exchange Commission (“SEC”) issued Staff Accounting Bulletin (“SAB”) No. 108. This Bulletin provides the Staff’s views on the consideration of the effects of prior year misstatements in quantifying current year misstatements for the purpose of a materiality assessment. The guidance in SAB No. 108 is effective for financial statements of fiscal years ending after November 15, 2006. Adoption of this guidance is not expected to materially impact our financial statements.

In September 2006, the Financial Accounting Standards Board (“FASB”) issued FASB Statement of Accounting Standards (“SFAS”) No. 157. This Statement defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles, and expands disclosures about fair value measurements. This Statement applies under other accounting pronouncements that require or permit fair value measurements, where fair value has been determined to be the relevant measurement attribute. This statement is effective for financial statements of fiscal years beginning after November 15, 2007. Adoption of this standard is not expected to materially impact our financial statements.

In July 2006, the FASB issued 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 are still evaluating the potential impact that implementing FIN 48 may have on our financial statements.

Note 3 — Oil and Gas Properties

During the third quarter of 2006, ATP acquired 100% of the working interest in Atwater Valley Block 63 and the remaining 25% working interest not previously acquired in Mississippi Canyon (“MC”) Blocks 941 and 943. During the second quarter of 2006, ATP acquired 75% of the working interest in MC Blocks 941 and 943, and

7

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. The total cash consideration paid for acquisitions during the nine months ended September 30, 2006 was $33.3 million.

During October 2005, ATP acquired substantially all of the oil and gas assets of a privately held company, consisting of 19 blocks located on the Gulf of Mexico Outer Continental Shelf. The final adjustments to the purchase price were recorded during the three months ended September 30, 2006. The final adjusted purchase price was $41.7 million in cash, plus net liabilities assumed totaling an estimated $28.9 million for future property abandonment operations. The purchase price was allocated $65.6 million to proved oil and gas property and $5.0 million to unproved property.

In accordance with SFAS No. 144, “Accounting for the Impairments or Disposal of Long-Lived Assets,” we review our oil and gas properties for impairment. During the three and nine months ended September 30, 2006, we recorded an impairment of certain of our oil and gas properties totaling $11.8 million, representing the excess carrying costs over the discounted present values of the estimated future production from those properties.

Note 4 — Asset Retirement Obligations

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

	Nine Months Ended September 30, 2006
Asset retirement obligation at January 1	$	67,364
Liabilities incurred		32,203
Liabilities settled		(3,537	)
Changes in estimates		(1,567	)
Accretion		5,473
Foreign currency translation		1,232
Asset retirement obligation at end of period	$	101,168

Note 5 — Long-Term Debt

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

	September 30, 2006			December 31, 2005
Term loan, net of unamortized discount of $5,137 and $6,386	$	518,551		$	340,989
Less current maturities		(5,250	)		(3,500	)
Total long-term debt	$	513,301		$	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

8

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.

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 September 30, 2006, the weighted average rate on outstanding borrowings was approximately 8.73%.

As of September 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):

	September 30, 2006		December 31, 2005
Series A 13 1/2% cumulative perpetual preferred stock; 175,000 shares issued and outstanding at September 30, 2006 and December 31, 2005; liquidation preference at September 30, 2006 and December 31, 2005 of $1,166 and $1,056 per share, respectively	$	204,125	$	184,858
Series B 12 1/2% cumulative perpetual preferred stock; 150,000 shares issued and outstanding at September 30, 2006; liquidation preference of $1,067 per share		160,073		—
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 Statement of Resolutions establishing 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

9

after the occurrence of various extraordinary events); (4) special provisions in the event of a Fundamental Change (as defined in the Statement of Resolutions) 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.

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 September 30, 2006, noncash preferred dividends were accrued for the Series A Preferred Stock and the Series B Preferred Stock in the amount of $29.1 million and $10.1 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

10

has not been rendered that was outstanding as of January 1, 2006. We recognized stock option compensation expense of approximately $0.4 million and $1.4 million for the three months and nine months ended September 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 September 30, 2005			Nine Months Ended September 30, 2005
Net loss available to common shareholders, as reported	$	(10,577	)	$	(12,898	)
Total stock based employee compensation benefit determined under fair value for all awards, net of related tax effects		(125	)		(375	)
Pro forma net loss	$	(10,702	)	$	(13,273	)
Earnings per share:
Basic and diluted earnings per share – as reported	$	(0.36	)	$	(0.44	)
Basic and diluted earnings per share – pro forma		(0.37	)		(0.46	)

The fair values of options granted during the three months and nine months ended September 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				Nine Months Ended
	September 30, 2006		September 30, 2005		September 30, 2006		September 30, 2005
Weighted average volatility	52	%	46	%	51	%	47	%
Expected term (in years)	4.3		4.5		4.3		4.5
Risk-free rate	4.8	%	4.1	%	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 September 30, 2006 and 2005 was $13.80 and $10.28, respectively. The total intrinsic value of options exercised during the three months ended September 30, 2006 and 2005 was $0.2 million and $5.7 million, respectively.

The weighted average grant-date fair value of options granted during the nine months ended September 30, 2006 and 2005 was $16.21 and $6.51, respectively. The total intrinsic value of options exercised during the nine months ended September 30, 2006 and 2005 was $12.2 million and $8.4 million, respectively. The following table sets forth a summary of option transactions for the nine-month period ended September 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	218,250			38.32
Exercised	(449,752	)		9.82
Canceled	(22,418	)		31.38
Expired	(15,715	)		8.90
Outstanding at end of period	746,726			23.73	$	10,148	3.66
Vested and expected to vest	690,203			23.74		9,376	3.58
Options exercisable at end of period	155,212			15.33		3,355	3.02

11

(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 September 30, 2006 and changes during the nine months ended September 30, 2006 is presented below:

	Number of Options		Weighted Average Grant-date Fair Value
Nonvested at January 1	540,864		$	6.28
Granted	209,750			11.76
Vested	(145,182	)		5.74
Forfeited	(13,918	)		8.36
Nonvested at end of period	591,514			8.31

At September 30, 2006, unrecognized compensation expense related to nonvested stock option grants totaled $2.9 million. Such unrecognized expense will be recognized as vesting occurs over a weighted average period of 2.9 years.

On September 25, 2006, we granted 3,000 shares of restricted stock with a weighted average grant date fair value of $36.61 per share to an employee. 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 nine months ended September 30, 2006, we recognized aggregate compensation expense of $2.7 million and $7.3 million, respectively, related to outstanding restricted stock grants.

The following table sets forth the restricted stock transactions for the nine months ended September 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)	100,816		39.67
Outstanding at end of period	366,179		37.58	$	13,527

(1) The weighted average grant date fair value of restricted stock granted for the nine months ended September 30, 2006 was $39.67. No restricted stock grants were outstanding at September 30, 2005.

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

At September 30, 2006, unrecognized compensation expense related to restricted stock totaled $6.4 million. Such unrecognized expense will be recognized as vesting occurs over a weighted average period of 2.0 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

12

table below, approximately 813,000 and 828,000 potential common stock equivalents have been excluded from the calculations for the three months and nine months ended September 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						Nine Months Ended
	September 30, 2006			September 30, 2005			September 30, 2006			September 30, 2005
Income
Net income (loss)	$	12,709		$	(6,821	)	$	27,024		$	(9,142	)
Less preferred dividends		(11,536	)		(3,756	)		(29,340	)		(3,756	)
Net income (loss) available to common shareholders	$	1,173		$	(10,577	)	$	(2,316	)	$	(12,898	)
Shares outstanding
Weighted average shares outstanding - basic		29,776			29,109			29,643			29,005
Effect of potentially dilutive securities - stock options and warrants		471			813			565			828
Unvested restricted stock		159			–			134			–
Weighted average shares outstanding - diluted		30,406			29,922			30,342			29,833
Net income (loss) available to common shareholders per share – basic and diluted	$	0.04		$	(0.36	)	$	(0.08	)	$	(0.44	)

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 September 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 September 30, 2006 and December 31, 2005, Accumulated Other Comprehensive Income (Loss) included $1.7 million 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.

At September 30, 2006, we had oil and natural gas derivatives that qualified as cash flow hedges with respect to our future production as follows:

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Area	Period	Type	Volumes	Average Price	Floor Price		Net Fair Value Asset (Liability)
				$/MMBtu	$/Bbl		($000)
Oil (Bbls)
Gulf of Mexico	2006	Puts	506,000	—	$	57.50	188
Gulf of Mexico	2007	Puts	860,000	—		58.56	1,262

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 opposed to fair value accounting for the contracts. At September 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	1,073,000	$	9.76
2007	1,350,000		10.83
North Sea:
2006	1,070,000	$	13.39
2007	3,180,000		10.23
Oil (Bbl) – Gulf of Mexico:
2006	294,400	$	65.21
2007	1,434,000		70.60
2008	366,000		76.55

(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 September 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 June 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

14

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.

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 nine months ended September 30, 2006 and 2005 is as follows (in thousands):

	Gulf of Mexico		North Sea			Total
For the Three Months Ended –
September 30, 2006:
Revenues	$	102,963	$	29,859		$	132,822
Depreciation, depletion and amortization		41,475		13,551			55,026
Impairment of oil and gas properties		11,760		—			11,760
Income from operations		22,489		8,632			31,121
Additions to oil and gas properties		137,855		82,423			220,278
September 30, 2005:
Revenues	$	26,342	$	—		$	26,342
Depreciation, depletion and amortization		12,252		37			12,289
Income from operations		3,423		(1,996	)		1,427
Additions to oil and gas properties		64,439		61,207			125,646

For the Nine Months Ended –
September 30, 2006:
Revenues	$	228,547	$	58,405		$	286,952
Depreciation, depletion and amortization		87,993		27,552			115,545
Impairment of oil and gas properties		11,760		—			11,760
Income from operations		55,004		15,184			70,188
Total assets		874,947		400,274			1,275,221
Additions to oil and gas properties		308,873		174,525			483,398
September 30, 2005:
Revenues	$	90,475	$	6,335		$	96,810
Depreciation, depletion and amortization		44,370		3,623			47,993
Income from operations		14,931		(2,437	)		12,494
Total assets		521,581		182,426			704,007
Additions to oil and gas properties		169,016		103,587			272,603

Note 12 — Subsequent Event

During the fourth quarter of 2006, the Company expects to receive approximately $7.3 million of Loss of Production Income insurance proceeds related to the impact of the 2005 hurricanes. These amounts have not been recognized in prior periods due to uncertainties as to amount and timing, and therefore will be recognized as income during the period as realized.

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ATP OIL & GAS CORPORATION AND SUBSIDIARIES

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Executive Overview

General

ATP Oil & Gas Corporation is engaged 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 current owners for a variety of reasons. For example, larger oil companies from time to time adjust their capital spending or shift their focus to exploration prospects 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.

Third Quarter 2006 Highlights

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

• Achieved a second consecutive quarter of record production with an average rate of 174.1 MMcfe/d;

• Recorded quarterly revenue of $132.8 million and net income available to common shareholders of $1.2 million;

• Added six wells to production during the first nine months of 2006, with nine additional near-term wells scheduled to come online, three in the fourth quarter 2006 and six in the first half 2007;

• Acquired seven blocks in the Gulf of Mexico in 2006 and executed the contract to build a MinDOC floating production platform, which will service the company’s deepwater properties – Mirage, Morgus, and Telemark.

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

For the three months ended September 30, 2006, we reported net income available to common shareholders of $1.2 million, or $0.04 per basic and diluted share on total revenue of $132.8 million, as compared with a net loss available to common shareholders of $10.6 million, or $0.36 per basic and diluted share, on total revenue of $26.3 million for the three months ended September 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. 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 16% and 80% of our natural gas production was sold under these contracts for the three months ended September 30, 2006 and 2005, respectively. Approximately 66% and 63% 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 September 30,						% Change in 2006 from 2005
	2006			2005
Production:
Natural gas (MMcf)		8,726			2,718		221	%
Oil and condensate (MBbls)		1,215			181		571	%
Total (MMcfe)		16,017			3,807		321	%
Revenues from production (in thousands):
Natural gas	$	60,045		$	18,981		216	%
Effects of cash flow hedges		2,934			(117	)	2,607	%
Total	$	62,979		$	18,864		234	%
Oil and condensate	$	71,056		$	7,463		852	%
Effects of cash flow hedges		(1,140	)		—		—
Total	$	69,916		$	7,463		837	%
Natural gas, oil and condensate	$	131,101		$	26,444		396	%
Effects of cash flow hedges		1,794			(117	)	1,633	%
Total	$	132,895		$	26,327		405	%

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Average sales price per unit:
Natural gas (per Mcf)	$	6.88		$	6.98		(1	)%
Effects of cash flow hedges (per Mcf)		0.34			(0.04	)	950	%
Total (per Mcf)	$	7.22		$	6.94		4	%
Oil and condensate (per Bbl)	$	58.46		$	41.16		42	%
Effects of cash flow hedges (per Bbl)		(0.94	)		—		—
Total (per Bbl)	$	57.52		$	41.16		40	%
Natural gas, oil and condensate (per Mcfe)	$	8.19		$	6.95		18	%
Effects of cash flow hedges (per Mcfe)		0.11			(0.03	)	467	%
Total (per Mcfe)	$	8.30		$	6.92		20	%

Revenues from production increased 405% in the third quarter of 2006 compared to the same period in 2005. During the third quarter of 2006, our production increased 321% 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 third quarter of 2006 increased to $22.8 million ($1.43 per Mcfe) from $4.8 million ($1.26 per Mcfe) in the third quarter of 2005. The increase was primarily attributable to the aforementioned increase in production as well as increases in insurance costs and the expenses attributable to uninsured hurricane repairs. The increase per unit of production was primarily attributable to the increase in insurance and other operating costs and the uninsured hurricane repairs.

Exploration. Exploration expense for the periods included geological and geophysical costs incurred in connection with evaluating oil and gas properties. Additionally, during the third quarter of 2005, exploration expense included approximately $3.1 million related to an exploratory, step-out well at our producing Eugene Island 30/71 complex.

General and Administrative. General and administrative expense increased to $4.6 million for the third quarter of 2006 compared to $3.9 million for the same period of 2005 primarily due to increases in legal, professional and consulting fees, partially offset by the prior year provision for the ATP Employee Volvo Challenge Plan.

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization (“DD&A”) expense increased $42.7 million (348%) during the third quarter of 2006 to $55.0 million from $12.3 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 $3.44 per Mcfe in the third quarter of 2006 compared to $3.23 per Mcfe in the same quarter of 2005.

Impairment of oil and gas properties. We recorded an impairment of oil and gas properties for the third quarter of 2006 totaling $11.8 million related to certain producing properties acquired during 2005. This amount represents the excess carrying costs over the discounted present values of the estimated future production from those properties.

Accretion. Accretion expense increased to $2.3 million for the third 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.

Income Taxes. We recorded a tax provision of $5.0 million during the quarter ended September 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.

Nine Months Ended September 30, 2006 Compared to Nine Months Ended September 30, 2005

19

For the nine months ended September 30, 2006, we reported net loss available to common shareholders of $2.3 million, or $0.08 per basic and diluted share on total revenue of $287.0 million as compared with a net loss available to common shareholders of $12.9 million, or $0.44 per share, on total revenue of $96.8 million for the nine months ended September 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. 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 22% and 57% of our natural gas production was sold under these contracts for the nine months ended September 30, 2006 and 2005, respectively. Approximately 63% and 59%, 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.

	Nine Months Ended September 30,					% Change in 2006 from 2005
	2006			2005
Production:
Natural gas (MMcf)		22,380			11,033	103	%
Oil and condensate (MBbls)		2,181			584	273	%
Total (MMcfe)		35,469			14,537	144	%
Revenues from production (in thousands):
Natural gas	$	160,739		$	72,245	122	%
Effects of cash flow hedges		2,479			40	6,098	%
Total	$	163,218		$	72,285	126	%
Oil and condensate	$	125,793		$	24,337	417	%
Effects of cash flow hedges		(2,014	)		—	—
Total	$	123,779		$	24,337	409	%
Natural gas, oil and condensate	$	286,532		$	96,582	197	%
Effects of cash flow hedges		465			40	1,063	%
Total	$	286,997		$	96,622	197	%
Average sales price per unit:
Natural gas (per Mcf)	$	7.18		$	6.55	10	%
Effects of cash flow hedges (per Mcf)		0.11			—	—
Total (per Mcf)	$	7.29		$	6.55	11	%
Oil and condensate (per Bbl)	$	57.66		$	41.67	38	%
Effects of cash flow hedges (per Bbl)		(0.92	)		—	—
Total (per Bbl)	$	56.74		$	41.67	36	%
Natural gas, oil and condensate (per Mcfe)	$	8.08		$	6.64	22	%
Effects of cash flow hedges (per Mcfe)		0.01			—	—
Total (per Mcfe)	$	8.09		$	6.65	22	%

Revenues from production increased 197% in the nine months ended September 30, 2006 compared to the same period in 2005. During the 2006 period our production increased 144% 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 22% increase in our average sales price per unit.

Lease Operating. Lease operating expenses for the nine months ended September 30, 2006 increased to $54.8 million ($1.55 per Mcfe) from $15.4 million ($1.06 per Mcfe) in the same period of 2005. The increase was primarily attributable to the aforementioned increase in production as well as increases in insurance costs and the expenses attributable to repair of uninsured hurricane repairs. The increase per unit of production was primarily attributable to the increase in insurance and other operating costs and the uninsured hurricane repairs.

20

Exploration. During the nine months ended September 30, 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 $5.6 million.

General and Administrative. General and administrative expense increased to $14.5 million for the nine months ended September 30, 2006 compared to $13.2 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 nine month period, 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 three quarters of 2005 versus only the first quarter in 2006. No significant charges were made under the Plan subsequent to the first quarter of 2006.

Depreciation, Depletion and Amortization. DD&A expense increased $67.5 million (141%) during the nine months ended September 30, 2006 to $115.5 million from $48.0 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 $3.26 per Mcfe in the nine months ended September 30, 2006 compared to $3.30 per Mcfe in the comparable period of 2005.

Impairment of oil and gas properties. We recorded an impairment of oil and gas properties for the nine months ended September 30, 2006 totaling $11.8 million related to certain producing properties acquired during 2005. This amount represents the excess carrying costs over the discounted present values of the estimated future production from those properties.

Accretion. Accretion expense increased to $5.5 million for the nine months ended September 30, 2006 compared to $1.8 million for the comparable 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 nine months ended September 30, 2006 we recorded a $3.9 million loss on abandonment primarily because 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 $8.3 million during the nine months ended September 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 September 30, 2006, we had working capital of approximately $4.2 million, an increase of approximately $3.7 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.

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Cash Flows	Nine Months Ended
	September 30, 2006		September 30, 2005
Cash provided by (used in):
Operating activities	105,346		61,390
Investing activities	(404,543	)	(285,342	)
Financing activities	294,206		292,305

Cash provided by operating activities during the nine months ended September 30, 2006 and 2005 was $105.3 million and $61.4 million, respectively. Cash flow from operations increased due to higher oil and gas production revenues during the nine months ended September 30, 2006 from the comparable period of 2005. The increase in sales revenue was attributable to higher oil and gas production and higher average oil and gas prices during the nine months ended September 30, 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 $404.5 million and $285.3 million during the nine months ended September 30, 2006 and 2005, respectively. Cash expended in the Gulf of Mexico and North Sea was approximately $257.9 million and $133.0 million in the nine months ended September 30, 2006. Cash expended in the Gulf of Mexico and North Sea was approximately $169.0 million and $103.6 million in the comparable period of 2005.

Cash provided by financing activities was $294.2 million and $292.3 million during the nine months ended September 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):

	September 30, 2006			December 31, 2005
Term loan, net of unamortized discount of $5,137 and $6,386	$	518,551		$	340,989
Less current maturities		(5,250	)		(3,500	)
Total long-term debt	$	513,301		$	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%;

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• 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.

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 September 30, 2006, the weighted average rate on outstanding borrowings was approximately 8.73%.

As of September 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

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See Note 2 to our Consolidated Financial Statements for a discussion of recently issued accounting pronouncements.

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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.

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-

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15(e), as of September 30, 2006. Based on that evaluation, such officers have concluded that, as of September 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.

Changes in Internal Control Over Financial Reporting

During the three months ended September 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 & 4 are not applicable and have been omitted.

Item 5. — Other Information

Amendments to Bylaws

On November 1, 2006, the Board of Directors of ATP adopted resolutions to amend Article II, Section 12(a)(2) and Article III, Section 1(c) of the Company’s Bylaws. The first amendment deletes from the Notice of Shareholder Business and Nominations: Annual Meeting of Shareholders bylaw a reference to Rule 14a-11 under the Securities Exchange Act of 1934, which rule was previously repealed by the Securities and Exchange Commission. The second amendment revises the bylaw governing the filling of newly created director positions through an increase in the number of directors to limit such increases to two director positions between successive annual meetings of the Company, as required by applicable law. Previously, Article III, Section 1(c) set no limit on the number of directors who could be appointed to newly created director positions between successive annual meetings of the Company.

A copy of ATP’s complete bylaws, as amended effective November 1, 2006, is attached to this Current Report on Form 10-Q as Exhibit 3.1.

Item 6. Exhibits

Exhibits

3.1	Amended and Restated Bylaws of ATP Oil & Gas Corporation.
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: November 7, 2006	By:	/s/ Albert L. Reese, Jr.
		Albert L. Reese, Jr.
		Chief Financial Officer

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