Form 10-Q

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

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-Q

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

For the quarterly period ended September 30, 2005

¨	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 an accelerated filer (as defined in Rule 12b-2 of the Exchange Act) Yes x No ¨

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 Registrant’s common stock, par value $0.001, as of November 1, 2005, was 29,255,186.

ATP OIL & GAS CORPORATION

TABLE OF CONTENTS


		Page
PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS (Unaudited)

Consolidated Balance Sheets: September 30, 2005 and December 31, 2004		3
Consolidated Statements of Operations: For the three and nine months ended September 30, 2005 and 2004		4
Consolidated Statements of Cash Flows: For the nine months ended September 30, 2005 and 2004		5
Consolidated Statements of Comprehensive Income (Loss): For the three and nine months ended September 30, 2005 and 2004		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		25

ITEM 4. CONTROLS AND PROCEDURES		26

PART II. OTHER INFORMATION		27

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(In Thousands, Except Share Amounts)

(Unaudited)


	September 30, 2005			December 31, 2004
Assets

Current assets
Cash and cash equivalents	$	167,370		$	102,774
Restricted cash		12,428			—
Accounts receivable (net of allowance of $1,496 and $1,499)		24,741			36,991
Derivative asset		—			791
Other current assets		8,298			3,788

Total current assets		212,837			144,344

Oil and gas properties (using the successful efforts method of accounting)
Proved properties		714,327			439,887
Unproved properties		12,401			10,516

		726,728			450,403
Less: Accumulated depletion, impairment and amortization		(259,141	)		(237,197	)

Oil and gas properties, net		467,587			213,206

Furniture and fixtures (net of accumulated depreciation)		830			741
Other assets, net		22,753			13,856

Total assets	$	704,007		$	372,147

Liabilities and Shareholders’ Equity

Current liabilities
Accounts payable and accruals	$	103,426		$	68,573
Current maturities of long-term debt		3,500			2,200
Asset retirement obligation		3,373			4,925
Derivative liability		181			316

Total current liabilities		110,480			76,014

Long-term debt		337,941			208,109
Asset retirement obligation		31,372			19,998
Deferred revenue		602			741
Other long-term liabilities and deferred obligations		9,077			10,121

Total liabilities		489,472			314,983

Shareholders’ equity
Preferred stock		178,756			—
Common stock: $0.001 par value, 100,000,000 shares authorized; 29,322,526 issued and 29,246,686 outstanding at September 30, 2005; 28,959,701 issued and 28,883,861 outstanding at December 31, 2004		29			29
Additional paid in capital		138,536			140,628
Accumulated deficit		(101,656	)		(88,759	)
Accumulated other comprehensive income		(219	)		6,177
Treasury stock, at cost		(911	)		(911	)

Total shareholders’ equity		214,535			57,164

Total liabilities and shareholders’ equity	$	704,007		$	372,147

See accompanying notes to consolidated financial statements.

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(In Thousands, Except Per Share Amounts)

(Unaudited)


	Three Months Ended September 30,						Nine Months Ended September 30,
	2005			2004			2005			2004
Oil and natural gas revenues	$	26,342		$	26,306		$	96,810		$	83,196

Costs and operating expenses:
Lease operating		4,796			4,176			15,377			13,618
Exploration		3,067			29			5,574			309
General and administrative		3,893			3,285			13,247			11,063
Credit facility and related		—			—			—			1,850
Depreciation, depletion and amortization		12,289			11,697			47,993			37,241
Asset retirement accretion		622			500			1,801			1,474
(Gain) loss on abandonment		248			2			324			(271	)
(Gain) on disposition of properties		—			—			—			(6,011	)

Total costs and operating expenses		24,915			19,689			84,316			59,273

Income from operations		1,427			6,617			12,494			23,923

Other income (expense):
Interest income		1,518			159			3,006			291
Interest expense		(9,760	)		(6,179	)		(24,644	)		(15,938	)
Loss on extinguishment of debt		—			—			—			(3,326	)
Other income (expense)		(6	)		—			2			180

Total other expense		(8,248	)		(6,020	)		(21,636	)		(18,793	)

Income (loss) before income taxes		(6,821	)		597			(9,142	)		5,130
Income tax expense		—			—			—			—

Net income (loss)	$	(6,821	)	$	597		$	(9,142	)	$	5,130

Preferred dividends		(3,756	)		—			(3,756	)		—

Net income (loss) available to common shareholders	$	(10,577	)	$	597		$	(12,898	)	$	5,130

Basic and diluted income (loss) per common share	$	(0.36	)	$	0.02		$	(0.44	)	$	0.21

Weighted average number of common shares:
Basic		29,109			24,572			29,005			24,542

Diluted		29,922			24,900			29,833			24,771

See accompanying notes to consolidated financial statements.

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In Thousands)

(Unaudited)


	Nine Months Ended September 30,
	2005			2004
Cash flows from operating activities
Net income (loss)	$	(9,142	)	$	5,130
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities –
Depreciation, depletion and amortization		47,993			37,241
Gain on disposition of properties		—			(6,011	)
Accretion of asset retirement obligation		1,801			1,474
Dry hole costs		5,164			—
Amortization of deferred financing costs		2,982			1,697
Loss on extinguishment of debt		—			3,326
Ineffectiveness of cash flow hedges		(189	)		206
Other noncash items		1,320			1,046
Noncash interest and credit facility expenses		—			1,709
Changes in assets and liabilities –
Accounts receivable and other assets		7,269			(16,524	)
Derivative liability		—			(166	)
Accounts payable and accruals		4,185			(17,888	)
Other long-term assets		—			(364	)
Other long-term liabilities and deferred obligations		7			(3,327	)

Net cash provided by operating activities		61,390			7,549

Cash flows from investing activities
Acquisition and development of oil and gas properties		(272,603	)		(49,365	)
Proceeds from disposition of properties		—			19,200
Additions to furniture and fixtures		(427	)		(320	)
Increase in restricted cash		(12,312	)		—

Net cash used in investing activities		(285,342	)		(30,485	)

Cash flows from financing activities
Proceeds from long-term debt		132,113			262,000
Payments of long-term debt		(2,300	)		(165,680	)
Deferred financing costs		(10,416	)		(13,502	)
Repurchase of warrants		—			(12,311	)
Exercise of stock options		3,536			—
Issuance of preferred stock, net of issuance cost		169,440			—
Other		(68	)		227

Net cash provided by financing activities		292,305			70,734

Effect of exchange rate changes on cash		(3,757	)		(66	)

Net increase in cash and cash equivalents		64,596			47,732
Cash and cash equivalents, beginning of period		102,774			4,564

Cash and cash equivalents, end of period	$	167,370		$	52,296

Supplemental disclosures of cash flow information:
Cash paid during the period for interest	$	20,194		$	14,254

See accompanying notes to consolidated financial statements.

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(In Thousands)

(Unaudited)


	Three Months Ended September 30,						Nine Months Ended September 30,
	2005			2004			2005			2004
Net income (loss)	$	(6,821	)	$	597		$	(9,142	)	$	5,130

Other comprehensive income (loss):
Reclassification adjustment for settled contracts (net of income tax of $0)		297			280			5			381
Change in fair value of outstanding hedge positions (net of income tax of $0)		1,505			(1,089	)		(734	)		(2,443	)
Foreign currency translation adjustment		(2,650	)		(431	)		(5,667	)		342

Other comprehensive loss		(848	)		(1,240	)		(6,396	)		(1,720	)

Comprehensive income (loss)	$	(7,669	)	$	(643	)	$	(15,538	)	$	3,410

See accompanying notes to consolidated financial statements.

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 1 — General

ATP Oil & Gas Corporation (“ATP,” or the “Company”), a Texas corporation, was formed on August 8, 1991 and is engaged in the acquisition, development and production of oil and gas properties in the Gulf of Mexico and the U.K. and Dutch Sectors of the North Sea (the “North Sea”). We primarily focus our efforts on oil and gas properties with proved undeveloped reserves that are economically attractive to us but are not strategic to major or exploration-oriented independent oil and gas companies.

The accompanying unaudited consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”) for interim financial information and reflect all adjustments (consisting of normal recurring adjustments) which are, in the opinion of management, necessary for a fair presentation of the results of operations for the interim periods. All intercompany transactions are eliminated upon consolidation. The interim financial information and notes hereto should be read in conjunction with our 2004 Annual Report on Form 10-K, as amended by Amendment No. 1, filed on April 29, 2005 and Amendment No. 2, filed on October 28, 2005 (collectively, the 2004 Form 10-K, as amended) The results of operations for the nine months ended September 30, 2005 are not necessarily indicative of results to be expected for the entire year.

New Accounting Pronouncements

In October 2005 the Financial Accounting Standards Board (“FASB”) issued Staff Position No. FAS 13-1, “Accounting for Rental Costs Incurred during a Construction Period” (“FSP 13-1”). FSP 13-1 provides additional guidance in applying the provisions of Statement of Accounting Standards (“SFAS”) No. 13, “Accounting for Leases,” and Technical Bulletin 85-3, “Accounting for Operating Leases with Scheduled Rent Increases,” by clarifying that there is no distinction between the right to use a leased asset during the construction period and the right to use the asset after the construction period. Therefore, rental costs associated with ground or building operating leases that are incurred during a construction period shall be recognized as rental expense and the rental cost shall be included in income from continuing operations. FSP 13-1 is effective for the first reporting period beginning after December 15, 2005. A lessee shall cease capitalizing rental costs as of the effective date of FSP 13-1 for operating lease arrangements entered into prior to the effective date. Retrospective application in accordance with SFAS 154, “Accounting Changes and Error Corrections,” is permitted but not required. Accordingly, we will adopt this position effective January 1, 2006 and do not expect a material impact on our consolidated financial position or results of operations.

In March 2005, FASB issued Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations” (“FIN 47”), which clarifies that an entity is required to recognize a liability for the fair value of a conditional asset retirement obligation when the obligation is incurred - generally upon acquisition, construction, or development and/or through the normal operation of the asset, if the fair value of the liability can be reasonably estimated. A conditional asset retirement obligation is a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. Uncertainty about the timing and/or method of settlement is required to be factored into the measurement of the liability when sufficient information exists. We will adopt FIN 47 on December 31, 2005 and do not expect a material impact on our consolidated financial position or results of operations.

In March 2005, the SEC issued Staff Accounting Bulletin No. 107 (“SAB 107”) to express the views of the staff regarding the interaction between SFAS 123R and certain SEC rules and regulations and to provide the staff’s views regarding the valuation of share-based payment arrangements for public companies, including assumptions such as expected volatility and expected term. In August 2005, the FASB issued Staff Position No

FAS 123R-1 “Classification and Measurement of Freestanding Financial Instruments Originally Issued in Exchange for Employee Services under FASB Statement No. 123R”. This statement defers at this time the requirement of SFAS 123R that a freestanding financial instrument originally subject to SFAS 123R becomes subject to the recognition and measurement requirements of other applicable generally acceptable accounting principles (GAAP) when the rights conveyed by the instrument to the holder are no longer dependent on the holder being an employee of the entity. ATP will apply the additional guidance provided by SAB 107 and FSP 123R-1 upon implementation of SFAS 123R.

The Company must adopt SFAS 123R and related guidance on January 1, 2006 for its outstanding unvested awards as well as for awards granted, modified, repurchased or cancelled on or after that date. The Company is evaluating the potential impact of compensation expense expected to be recognized for unvested stock options outstanding at adoption of this guidance.

Note 2 — Restricted Cash

The Company’s restricted cash represents a time deposit denominated in Pounds Sterling which secures an irrevocable stand-by letter of credit for our future abandonment obligations with respect to the Kilmar field in the North Sea. The Letter of Credit and Reimbursement Agreement was entered into on July 18, 2005 with an initial term of one year, and it extends for successive one-year terms unless thirty days notice is given of the intention not to extend the letter of credit.

Note 3 — Acquisitions

On September 21, 2005, ATP acquired all of BP Exploration & Production Inc.’s (“BP”) interest in four Federal oil and gas leases covering Mississippi Canyon Blocks 173/217 and Desoto Canyon Blocks 133/177, offshore Gulf of Mexico, an oil and gas discovery area named “King’s Peak.” The acquisition also included all of BP’s interest in the Canyon Express Pipeline System. Consideration paid in cash at closing, after closing adjustments, was $18.6 million.

On October 12, 2005, ATP was awarded two blocks relating to its winning bids at the Western Gulf of Mexico Offshore Lease Sale held in New Orleans on August 17, 2005. ATP is the operator and has a 100% working interest in the blocks, Garden Banks 228 and High Island A-391, which were awarded at a total cost of approximately $0.6 million dollars. The Minerals Management Service has not yet awarded a third block to the Company on which it was the apparent high bidder. If successful, the Company will owe an additional $2.2 million.

On October 31, 2005, ATP acquired substantially all of the oil and gas assets of a privately held company. These assets consist of 29 blocks located on the Gulf of Mexico Outer Continental Shelf in less than 600 feet of water. The Company will operate most of the properties, which are currently producing approximately 25 MMcfe per day net to ATP’s interest. The reserves are approximately 80% gas and 20% oil and will be included in our year-end reserve report. Cash paid at closing was $40.0 million, and a contingent payment of an additional $10.0 million is expected to be required upon the attainment of certain cumulative production. The acquisition was effective October 1, 2005, and accordingly, the purchase price will be adjusted in a post-closing settlement expected to occur on January 31, 2006.

Note 4 — Asset Retirement Obligations

The Company provides for estimated asset retirement obligations related to the future abandonment of its offshore natural gas and oil wells and related facilities. The present value of the estimated future asset retirement obligation, as of the date of development or acquisition of each asset, is capitalized to producing properties and recorded as a liability. Until each asset is ultimately sold or abandoned, the Company will recognize: (i) depreciation expense on the additional capitalized costs; (ii) accretion expense as the present value of the future asset retirement obligation increases with the passage of time; and (iii) the impact, if any, of

changes in estimates of the liability. The following table sets forth a reconciliation of the beginning and ending aggregate carrying amount of asset retirement obligations for the nine months ended September 30, 2005 (in thousands):


Asset retirement obligation at January 1, 2005	$	24,923
Liabilities incurred		10,615
Liabilities settled		(2,180	)
Accretion		1,801
Foreign currency translation		(414	)

Asset retirement obligation at September 30, 2005	$	34,745

Note 5 — Long-Term Debt

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


	September 30, 2005			December 31, 2004
Term loan, net of unamortized discount of $6,809 and $8,129	$	341,441		$	210,309
Less current maturities		(3,500	)		(2,200	)

Total long-term debt	$	337,941		$	208,109

At September 30, 2005, we have $348.3 million outstanding on our Senior Secured First Lien Term Loan Facility (“Term Loan”). The Term Loan matures in April 2010. It is secured by substantially all of our oil and gas assets in the Gulf of Mexico and the U.K. Sector North Sea and is guaranteed by our wholly owned subsidiaries ATP Energy, Inc. and ATP Oil & Gas (UK) Limited. The Term Loan bears interest at the base rate plus a margin of 4.50% or LIBOR plus a margin of 5.50% at the election of ATP. At September 30, 2005, the weighted average rate on outstanding borrowings was approximately 9.26%.

In connection with the original issuance of the Term Loan during 2004, we granted warrants to purchase 2,452,336 shares of common stock of ATP for $7.25 per share. The warrants have a term of six years and expire in March 2010. The fair value of the warrants, as determined by use of the Black-Scholes valuation model on March 29, 2004, was approximately $4.2 million and was accounted for as additional paid-in-capital and debt discount. The fair value was calculated with the following weighted-average assumptions: zero dividend yield; risk-free interest rate of 3.0%; volatility of 51.6% and an expected life of 6 years. The value was adjusted for liquidity issues associated with a potential sale of such a large volume of shares in relation to our public float. This amount and the original issue discount of $5.6 million are being accreted over the life of the loan as additional interest expense.

On September 24, 2004, our lender consented to our repurchase of 1,926,837 of the 2,432,336 then outstanding second lien facility warrants for a price not to exceed $11,561,022. The warrants were repurchased on September 24, 2004 for $6.00 per warrant which, in management’s estimation, represented the then current fair value of the unregistered warrants. The $11.6 million partial repurchase was recorded as a decrease to additional paid in capital while the debt discount will continue to be amortized over the life of the loan.

On April 14, 2005, we increased our aggregate borrowings under the Term Loans by $132.1 million (from the balance outstanding as of March 31, 2005) to an aggregate outstanding principal amount of $350.0 million. From this increase in borrowings, we received net proceeds of $117.8 million after deducting $3.6 million for accrued and unpaid interest on the Term Loans up to the Amendment Date and $10.7 million for fees and expenses.

The terms of the Term Loan, as amended April 14, 2005, require us to maintain certain covenants. Capitalized terms are defined in the credit agreement for the Term Loan. The covenants include:

•

Current Ratio of 1.0/1.0;

•

Consolidated Net Debt to EBITDAX coverage ratio of not greater than 3.0/1.0 at the end of each quarter;

•

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

•

Pre-tax PV-10 of our Total Proved Developed Producing Oil and Gas Reserves to Net Debt of at least 0.5/1.0 at June 30 and December 31 of any fiscal year;

•

Pre-tax PV-10 of our Total Proved Oil and Gas Reserves to Net Debt of at least 2.5/1.0 at June 30 and December 31 of any fiscal year;

•

the requirement to maintain hedges on no less than 40% of the next twelve months of forecasted production attributable to our proved producing reserves;

•

the requirement to maintain a Maximum Leverage Ratio of no more than 3.0 to 1.0 at the end of any fiscal quarter beginning April 14, 2005 through June 30, 2005, 3.5 to 1.0 from July 1, 2005 through December 31, 2005 and 3.0 to 1.0 thereafter;

•

the requirement to maintain a Debt to Reserve Amount of no greater than $2.50 through maturity; provided, however, that if such amount is exceeded at the end of the fiscal year ending on December 31, 2005, any Default arising therefrom shall be waived and disregarded, and such amount shall be retested at June 30, 2006, and

•

an increase in the amount of Permitted Business Investments from $25.0 million to $75.0 million during any fiscal year.

As of September 30, 2005, we were in compliance with all of the financial covenants of our Term Loan. 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.

Note 6 — Preferred Stock

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 “Preferred Stock”), at a price of $1,000.00 per share. The 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 Preferred Stock is 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 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; (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 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 preferred stock may be redeemed at 100% of the liquidation preference plus accrued and unpaid dividends.

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 preferred stock under any circumstances.

Through September 30, 2005, noncash preferred dividends aggregating $3.8 million were due in-kind. No cash dividends are required under the Preferred Stock Subscription Agreement until the earlier of full repayment of our existing Term Loan or April 15, 2011.

On October 1, 2005, the Board of Directors of ATP authorized the issuance of one preferred share purchase right (a “Right”) with respect to each outstanding share of common stock, par value $.001 per share (the “Common Shares”), of the Company (the “Shareholder Rights Plan”). The rights were issued on October 17, 2005 to the holders of record of Common Shares on that date. Each Right entitles the registered holder to purchase from the Company one one-hundredth (1/100) of a share of Junior Participating Preferred Stock, par value $.001 per share (the “Preferred Shares”), of the Company at a price of $150.00 per one one-hundredth of a Preferred Share, subject to adjustment. The description and terms of the Rights are set forth in a Rights Agreement dated as of October 11, 2005 between the Company and American Stock Transfer & Trust Company, as Rights Agent.

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


	September 30, 2005		December 31, 2004
Series A 13.5% cumulative perpetual preferred stock; liquidation preference of $1,021 per share; 175,000 shares issued and outstanding at September 30, 2005	$	178,756	—

Junior participating preferred stock pursuant to the Shareholders Rights Plan; none issued at September 30, 2005		—	—

Note 7 — Stock –Based Compensation

SFAS 123, “Accounting for Stock-Based Compensation,” as amended by SFAS No. 148, “Accounting for Stock-Based Compensation – Transition and Disclosure,” (“SFAS 148”) outlines a fair value based method of accounting for stock options or similar equity instruments. Until we implement the fair value based method described in SFAS 123, we have continued using the intrinsic value based method under Accounting Principles Board (“APB”) Opinion 25, as allowed by SFAS 123, to measure compensation cost for our stock option plans. We will implement the fair value based method of accounting for such options in January 2006, as required by SFAS 123R, described above.

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 to stock-based employee compensation (in thousands):


	Three Months Ended September 30,					Nine Months Ended September 30,
	2005			2004		2005			2004
Net income (loss) available to common shareholders, as reported	$	(10,577	)	$	597	$	(12,898	)	$	5,130
Deduct: Total stock-based compensation expense determined under fair value of all awards, net of related tax effects		(125	)		5		(375	)		15

Net income (loss) available to common shareholders, Pro forma	$	(10,702	)	$	602	$	(13,273	)	$	5,145


Earnings per share:
Basic and diluted – as reported	$	(0.36	)	$	0.02	$	(0.44	)	$	0.21
Basic and diluted – pro forma	$	(0.37	)	$	0.02	$	(0.46	)	$	0.21

Note 8 — Earnings Per Share

Basic earnings per share is computed by dividing net income (loss) available to common shareholders by the weighted average number of common shares outstanding during the period. Diluted earnings per share is determined on the assumption that outstanding stock options have been exercised using the average share price for the period. For purposes of computing earnings per share in a loss period, potential common shares have been excluded from the computation of weighted average common shares outstanding because their effect is 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 September 30,					Nine Months Ended September 30,
	2005			2004		2005			2004
Net income (loss) available to common shareholders	$	(10,577	)	$	597	$	(12,898	)	$	5,130

Weighted average shares outstanding – basic		29,109			24,572		29,005			24,542
Effect of dilutive securities – stock options		414			207		463			189
Effect of dilutive securities – warrants		399			121		365			40

Weighted average shares outstanding – diluted		29,922			24,900		29,833			24,771

Basic and diluted net income (loss) per share	$	(0.36	)	$	0.02	$	(0.44	)	$	0.21

Note 9 — Derivative Instruments and Price Risk Management Activities

Derivative financial instruments, utilized to manage or reduce commodity price risk related to our production are accounted for under the provisions of SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (“SFAS 133”) and related interpretations. Under this standard, 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 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.

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 allows us to recover from our counterparty the shortfall, if any, of the floating market price from the put contract price. The costs to purchase put options, which represent the fair market value of the options at the contract date, are amortized over the option period.

At September 30, 2005, Accumulated Other Comprehensive Income included $0.2 million of unrealized net losses 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. All of this deferred loss will be reversed during the period in which the forecasted transactions actually occur.

At September 30, 2005, we had natural gas derivatives that qualified as cash flow hedges with respect to our future natural gas production as follows:

Area

Period

Type

Volumes

Average

Price

Floor Price

Net Fair Value
Asset (Liability)

(MMBtu)

($ per MMBtu)

($ in thousands)

North Sea

2006

Swaps

540,000

11.30

—

(181)

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. Paragraph 10(b) of SFAS 133 provides guidance for the normal purchases and normal sales exceptions. If it is no longer probable that a contract will not settle net and result in physical delivery, it generally no longer qualifies for the paragraph 10(b) exception. Although our production levels have temporarily declined due to hurricanes Katrina and Rita, we expect that we will be able to physically deliver our contracted volumes.

At September 30, 2005, we had fixed-price contracts in place for the following natural gas and oil volumes:


Period	Volumes	Average Fixed Price (1)
Natural gas (MMBtu):
2005	2,239,000	$	6.54
2006	4,922,000	$	8.26

Oil (Bbl):
2005	92,000	$	41.99
2006	300,500	$	47.96

(1)	Includes the effect of basis differentials.

Note 10 — Commitments and Contingencies

Contingencies

In December 2004, our Board of Directors approved and we announced ambitious Company targets coupled with a unique incentive program applicable to our employees. If the Company targets under the ATP Employee Volvo Challenge Plan (the “Plan”) are met, we will award each employee other than our President, a 2006 Volvo S60. Following the end of each fiscal quarter, we will evaluate our performance with respect to the stated targets and accrue the earned future cost of any expected benefits pursuant to the Plan.

In 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 cost. Upon achievement of the second threshold for the one property, the remaining contingent consideration was paid and capitalized at that time. Future development is planned on the other two properties and when they reach their respective thresholds, the appropriate consideration obligation 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 that participates on behalf of the Dutch government. During 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 September 30, 2005 and December 31, 2004, this obligation was reflected as a long-term liability of $9.0 million and $10.2 million, respectively, in the consolidated balance sheets. We are currently developing this property and expect to achieve commercial production prior to expiration of the 60-month period.

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 suggested that receipt of the payment may have been a taxable event at the time of receipt and taxes may be currently due on this payment in the amount of approximately €1.5 million ($1.8 million). We do not agree with the position that has been suggested and, if necessary, we will defend our position vigorously.

Hurricanes Rita and Katrina caused minimal direct damage to most of the Company’s platforms with some platforms, primarily in the Western Gulf, sustaining no damage. In addition the company lost potential revenues due to shut-in production resulting from the storms. The company maintains property casualty insurance for such physical damages and loss of production insurance to replace lost cash flows resulting from downtime in excess of sixty days after the event. The company is assessing the insured damages and any potential recoveries under the loss of production policy. We have not yet determined the amount of recovery, if any, we expect to receive resulting from these losses. We have not included any receivable in the financial statements for any potential recovery.

On October 19, 2005, ATP agreed to acquire the Rowan Midland mobile offshore drilling unit (“Vessel”) from Rowandrill, Inc. (“Rowan”) for modification for use as a floating offshore production unit at the Company’s Mississippi Canyon 711 development. The net purchase price of $50 million, after payment of $10.0 million at closing on October 19, 2005, is payable over the succeeding 15 month period (the “Interim Period”) in payments of $1,050,000 per month, with the remaining balance due to Rowan on January 31, 2007. At any time prior to January 31, 2007, the Company has the right, without penalty, to pay the remaining balance of the net purchase price. During the Interim Period, the Vessel is chartered to the Company for use in its production operations in the Gulf of Mexico.

Litigation

From time to time we are involved, in the ordinary course of business, as either a claimant or defendant in various legal proceedings. Based on consultation with counsel, our management does not believe that the outcome of these legal proceedings individually, or in the aggregate, will have a material adverse effect on our financial condition, results of operations or cash flows.

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 accounting policies of the reportable segments are the same as those described in Note 2 to the Consolidated Financial Statements. The Company evaluates the segments based on operating income (loss). Segment activity for the three and nine months ended September 30, 2005 and 2004 is as follows (in thousands):


	Three Months Ended September 30, 2005
	Gulf of Mexico		North Sea			Total
Oil and natural gas revenues	$	26,342	$	—		$	26,342
Depreciation, depletion and amortization		12,252		37			12,289
Income (loss) from operations		3,423		(1,996	)		1,427
Acquisition and development of oil and gas properties		64,439		61,207			125,646

	Three Months Ended September 30, 2004
	Gulf of Mexico		North Sea			Total
Oil and natural gas revenues	$	22,930	$	3,376		$	26,306
Depreciation, depletion and amortization		8,848		2,849			11,697
Income (loss) from operations		7,850		(1,233	)		6,617
Acquisition and development of oil and gas properties		16,218		400			16,618

	Nine Months Ended September 30, 2005
	Gulf of Mexico		North Sea			Total
Oil and natural gas revenues	$	90,475	$	6,335		$	96,810
Depreciation, depletion and amortization		44,370		3,623			47,993
Income (loss) from operations		14,931		(2,437	)		12,494
Acquisition and development of oil and gas properties		169,016		103,587			272,603

	Nine Months Ended September 30, 2004
	Gulf of Mexico		North Sea			Total
Oil and natural gas revenues	$	70,038	$	13,158		$	83,196
Depreciation, depletion and amortization		26,646		10,595			37,241
Income (loss) from operations		26,967		(3,044	)		23,923
Acquisition and development of oil and gas properties		44,849		4,516			49,365

	At September 30, 2005
	Gulf of Mexico		North Sea			Total
Identifiable assets	$	521,581	$	182,426		$	704,007

	At December 31, 2004
	Gulf of Mexico		North Sea			Total
Identifiable assets	$	317,043	$	55,104		$	372,147

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, incorporated in Texas in 1991, is engaged in the acquisition, development and production of natural gas and oil properties in the Gulf of Mexico and the North Sea. We primarily focus our efforts on oil and natural gas properties where previous drilling has encountered reservoirs that appear to contain commercially productive quantities of oil and natural gas. Many of these properties contain proved reserves, primarily undeveloped but occasionally containing producing reserves, that are economically attractive to us but are not strategic to major or exploration-oriented independent oil and natural gas companies. Our management team has extensive engineering, geological, geophysical, technical and operational expertise in successfully developing and operating properties in our current and planned areas of operations.

We believe that our strategy of acquiring properties where previous activities have indicated the presence of hydrocarbons 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 primarily through the acquisition and subsequent development of oil and gas reserves in areas that have:

•

significant undeveloped reserves;

•

close proximity to developed markets for oil and gas;

•

existing infrastructure of oil and gas pipelines and production / processing platforms, and

•

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

Source of Revenue

We derive our revenues from the sale of oil and natural gas that is produced from our properties. Revenues are a function of both the volume produced and the prevailing market price at the time of sale. Production volumes, while somewhat predictable after wells have begun producing, can be impacted for various reasons. The recent hurricanes Katrina and Rita are an example of how production volumes can be impacted to defer volumes from the current period to future periods. The price of oil and natural gas is a primary factor affecting our revenues. Again, the recent hurricanes have been a contributing factor to the recent near-term rise in oil and gas prices. 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 portion of our oil and natural gas production. While the derivative instruments may protect downward price fluctuation, the use of certain types of derivative instruments may prevent us from realizing the full benefit of upward price movements.

2005 Highlights

Our acquisition, development, financial and operating performance for the third quarter 2005 included the following highlights:

Acquisitions:

•

Acquired a 55% working interest in the producing property King’s Peak, which consists of Mississippi Canyon blocks 173 and 217 and Desoto Canyon blocks 133 and 177;

•

Submitted the apparent high bids on three blocks at the Western Gulf of Mexico Lease Sale; Two of the leases have been subsequently awarded;

•

Acquired a package of properties in a private transaction with current production of 25 MMcfe/d.

Developments:

•

Resumed development operations at Mississippi Canyon 711 following a more than two-month delay caused by Hurricanes Rita and Katrina. Approximately 50 days of well operations and facility hookup remain;

•

Reached agreement to acquire the Rowan-Midland, which will initially be utilized as a floating production platform at Mississippi Canyon 711;

•

Completed platform and pipeline installation at the Tors in the U.K. Sector North Sea and commenced well operations with the ENSCO 70 rig;

•

Tested L-06d in the Dutch Sector North Sea at 53 MMcf/d, completed the well, installed the pipeline, and currently performing platform tie-in work at the host platform.

Operations and Finance

•

Achieved production of 14.5 Bcfe during the first three quarters of the year and 3.8 Bcfe during the third quarter;

•

Recorded quarterly revenues of $26.3 million, cash flows from operating activities of $22.6 million, and a net loss to common stockholders of $10.6 million; and

•

Recorded year-to-date revenues of $96.8 million, cash flows from operating activities of $61.4 million, and a net loss to common stockholders of $12.9 million.

•

Issued $175.0 million in non-convertible perpetual preferred stock.

Review and Outlook

Since the latter part of 2004, ATP has focused a substantial portion of its financial and personnel resources on oil and gas development projects that we believe will result in a significant increase in production in late 2005 and early 2006. Mississippi Canyon 711 (Gomez) in the Gulf of Mexico, even though delayed by the hurricanes, is currently scheduled to begin production late in the fourth quarter of 2005. L-06d in the Dutch Sector North Sea is on track for first production in the fourth quarter of 2005. Tors in the U.K. Sector North Sea was recently added to the 2005 development program and is currently scheduled to begin production in late 2005 or early 2006. Additionally, ATP placed five wells on production in the Gulf of Mexico in the first nine months of 2005 and has another well that is completed awaiting pipeline installation. The Company has averaged production of 53 MMcfe per day for the first nine months of 2005, despite offshore decline rates, hurricane impacts and a seasonal shut-in at our Helvellyn property in the U.K. Sector North Sea.

To fund its development plans in 2005, the Company has utilized internally generated cash flow and financings. ATP has completed two financings, adding a total of $287.3 million in new liquidity. The first transaction, completed in April 2005, provided a net $117.8 million by expanding our term loan, reducing its interest rate, extending its maturity and providing more flexible covenants. The second transaction, completed in August 2005, provided a net $169.5 million of new equity in the form of non-convertible, perpetual preferred stock.

During the first three quarters of 2005, ATP paid $272.6 million for acquisition and development of oil and gas properties, primarily at Mississippi Canyon 711, L-06d, Tors and Kings Peak. We believe the areas of focus for our 2005 capital expenditure program will be the foundation for substantial production, revenue, cash flow, and earnings growth in the fourth quarter of 2005, in 2006 and beyond.

A more complete overview and discussion of our operations can be found in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our 2004 Form 10-K, as amended.

Results of Operations

Three Months Ended September 30, 2005 Compared to Three Months Ended September 30, 2004

For the three months ended September 30, 2005, we reported a net loss available to common shareholders of $10.6 million, or $0.36 per share on total revenue of $26.3 million, as compared with net income available to common shareholders of $0.6 million, or $0.02 per share, on total revenue of $26.3 million for the three months ended September 30, 2004.

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 80% and 46% of our natural gas production was sold under these contracts for the three months ended September 30, 2005 and 2004, respectively. Approximately 63% and 51% 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 from 2004 to 2005
	2005			2004		% Change from 2004 to 2005
Production:
Natural gas (MMcf)		2,718			4,251	(36	)%
Oil and condensate (MBbls)		181			166	9	%
Total (MMcfe)		3,807			5,245	(27	)%

Revenues from production (in thousands):
Natural gas	$	18,981		$	20,966	(9	)%
Effects of cash flow hedges		(117	)		2	(100	)%

Total	$	18,864		$	20,968	(10	)%

Oil and condensate	$	7,463		$	5,493	36	%
Effects of cash flow hedges		—			—	—

Total	$	7,463		$	5,493	36	%

Natural gas, oil and condensate	$	26,444		$	26,459	0	%
Effects of cash flow hedges		(117	)		2	(100	)%

Total revenues from production	$	26,327		$	26,461	(1	)%

Average sales price per unit:
Natural gas (per Mcf)	$	6.98		$	4.93	42	%
Effects of cash flow hedges (per Mcf)		(0.04	)		—	0	%

Total (per Mcf)	$	6.94		$	4.93	41	%

Oil and condensate (per Bbl)	$	41.16		$	33.15	24	%
Effects of cash flow hedges (per Bbl)		—			—	—

Total (per Bbl)	$	41.16		$	33.15	24	%

Natural gas, oil and condensate (per Mcfe)	$	6.95		$	5.04	38	%
Effects of cash flow hedges (per Mcfe)		(0.03	)		—	0	%

Total (per Mcfe)	$	6.92		$	5.04	37	%

Revenues from production decreased 1% in the third quarter of 2005 compared to the same period in 2004. During the current period our production declined from the comparable period in 2004 due to natural decline

which was not offset by significant new production as well as hurricanes Katrina and Rita. We expect the wells that were shut-in due to the hurricanes and the 2005 projects we are developing to begin contributing significantly to our production by the end of the fourth quarter of 2005. Revenues were impacted favorably by a 37% increase in our sales price per unit.

Lease Operating. Lease operating expenses for the third quarter of 2005 increased to $4.8 million ($1.26 per Mcfe) from $4.2 million ($0.80 per Mcfe) in the third quarter of 2004. The increase per Mcfe was primarily attributable to the aforementioned decrease in production while certain costs remained fixed. Included in the 2005 lease operating expense was $0.4 million related to various platform repairs performed on our oil and gas properties in the Gulf of Mexico during the period, compared to $0.1 million incurred during the same period of 2004.

Exploration. During the third quarter 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 expense of approximately $3.1 million in the third quarter of 2005.

General and Administrative. General and administrative expense increased to $3.9 million for the third quarter of 2005 compared to $3.3 million for the same period of 2004 primarily due to an increase in compensation related costs including accrued costs related to the ATP Employee Volvo Challenge Plan.

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization (“DD&A”) expense increased $0.6 million (5%) during the third quarter of 2005 to $12.3 million from $11.7 million for the same period in 2004. The average DD&A rate was $3.23 per Mcfe in the third quarter of 2005 compared to $2.23 per Mcfe in the same quarter of 2004. The average DD&A expense per Mcfe increase was mainly due to the increase in development costs on properties in the third quarter of 2005 compared to the same period in 2004 and to the downward revision of reserves on six of our properties at December 31, 2004.

Interest Income. Interest income varies directly with the amount of temporary cash investments. The increase in interest income from period to period is the result of the increase in cash on hand from the Company’s aforementioned funding activities.

Interest Expense. Interest expense increased as a result of the increase of available borrowings under the Term Loan on April 14, 2005 to $350.0 million.

Income Taxes. In the third quarter of 2005, we recorded income tax benefit of $2.0 million which was completely offset by an increase in the valuation allowance recorded against our deferred tax assets. The balance of our deferred tax assets will remain fully reserved until management determines that the recognition criteria for realization have been met.

Preferred dividends. The Company recognized $3.8 million of dividends in-kind related to its Series A 13.5% cumulative perpetual preferred stock in the third quarter of 2005.

Nine Months Ended September 30, 2005 Compared to Nine Months Ended September 30, 2004

For the nine months ended September 30, 2005, we reported net loss available to common shareholders of $12.9 million, or $0.44 per share, on total revenue of $96.8 million as compared to net income available to common shareholders of $5.1 million, or $0.21 per share, on total revenue of $83.2 million for the nine months ended September 30, 2004.

Oil and Natural Gas Revenues

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 57% and 43% of our natural gas production was sold under these contracts for the nine months ended September 30, 2005 and 2004, respectively. Approximately 59% and 41%, 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 from 2004 to 2005
	2005		2004			% Change from 2004 to 2005
Production:
Natural gas (MMcf)		11,033		13,302		(17	)%
Oil and condensate (MBbls)		584		537		9	%
Total (MMcfe)		14,537		16,521		(12	)%

Revenues from production (in thousands):
Natural gas	$	72,245	$	66,128		9	%
Effects of cash flow hedges		40		(228	)	100	%

Total	$	72,285	$	65,900		10	%

Oil and condensate	$	24,337	$	17,265		41	%
Effects of cash flow hedges		—		—		—

Total	$	24,337	$	17,265		41	%

Natural gas, oil and condensate	$	96,582	$	83,393		16	%
Effects of cash flow hedges		40		(228	)	100	%

Total revenues from production	$	96,622	$	83,165		16	%

Average sales price per unit:
Natural gas (per Mcf)	$	6.55	$	4.97		32	%
Effects of cash flow hedges (per Mcf)		—		(0.02	)	100	%

Total (per Mcf)	$	6.55	$	4.95		32	%

Oil and condensate (per Bbl)	$	41.67	$	32.18		29	%
Effects of cash flow hedges (per Bbl)		—		—		—

Total (per Bbl)	$	41.67	$	32.18		29	%

Natural gas, oil and condensate (per Mcfe)	$	6.64	$	5.05		31	%
Effects of cash flow hedges (per Mcfe)		—		(0.01	)	0	%

Total (per Mcfe)	$	6.65	$	5.04		32	%

Revenues from production increased 16% in the first nine months of 2005 compared to the same period in 2004. This increase was due primarily to a 32% increase in our sales price per Mcfe in 2005 as compared to 2004, partially offset by the decrease in production in the third quarter of 2005 as a result of hurricanes Katrina and Rita.

Lease Operating. Lease operating expenses for the first nine months of 2005 increased to $15.4 million ($1.06 per Mcfe) from $13.6 million ($0.83 per Mcfe) in the first nine months of 2004. The increase per Mcfe was primarily attributable to the decrease in production while certain costs remained fixed. Included in the 2005 lease operating expense was $2.1 million related to various platform repairs performed on our oil and gas properties in the Gulf of Mexico during the period, compared to $0.6 million incurred during the same period of 2004.

Exploration. During the first nine months 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 $5.6 million in the first nine months of 2005.

General and Administrative. General and administrative expense increased to $13.2 million for the first nine months of 2005 compared to $11.1 million for the same period of 2004 primarily due higher compensation related costs and professional fees. Compensation related costs during the 2005 period included accrued costs related to the ATP Employee Volvo Challenge Plan.

Credit Facility and Related. In the first quarter of 2004, we incurred substantial non-recurring costs of $1.9 million to maintain compliance with the requirements of our previous lender. These costs primarily consisted of legal and professional fees of $1.6 million.

Depreciation, Depletion and Amortization. DD&A expense increased $10.8 million (29%) during the first nine months of 2005 to $48.0 million from $37.2 million for the same period in 2004. The average DD&A rate was $3.30 per Mcfe in the first nine months of 2005 compared to $2.25 per Mcfe in the same period of 2004. The average DD&A expense per Mcfe increase was mainly due to the increase in development costs on properties in the first nine months of 2005 compared to the same period in 2004 and to the downward revision of reserves on six of our properties at December 31, 2004.

Gain on Disposition of Properties. In the first half of 2004, we recognized a gain of $6.0 million on the sale of interests in certain Gulf of Mexico properties.

Interest Expense. Interest expense increased as a result of the increase of available borrowings under the Term Loan on April 14, 2005 to $350.0 million.

Loss on Extinguishment of Debt. In the first quarter of 2004, we recognized a noncash loss of $3.3 million on the extinguishment of debt related to our prior credit facility agreement.

Income Taxes. In the first nine months of 2005, we recorded income tax benefit of $1.8 million which was completely offset by a reduction in the valuation allowance recorded against our deferred tax assets. The balance of our deferred tax assets will remain fully reserved until management determines that the recognition criteria for realization have been met.

Preferred dividends. The Company recognized $3.8 million of dividends in-kind related to its Series A 13.5% cumulative perpetual preferred stock for the nine months ended September 30, 2005.

Liquidity and Capital Resources

At September 30, 2005, we had working capital of approximately $102.4 million, an increase of approximately $34.1 million from December 31, 2004.

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 preferred stock. If the Company chooses not to offer to redeem the 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 preferred stock under any circumstances.

Historically, 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 by the sell-down of a portion of our interests in selected development projects. We are developing several major projects which will require significant capital expenditures through the end of 2005. In order to fund the expected 2005 development costs, we expanded the borrowings under our Term Loan in April 2005 and in August 2005 we completed the preferred stock offering. We expect that we will utilize a significant portion of our cash on our consolidated balance sheet as of September 30, 2005 to complete the 2005 development plans and to accelerate certain projects into 2005 in order to take advantage of the currently existing high commodity prices. We expect these development activities to significantly increase production by the end of 2005 and into 2006.

Cash Flows


	Nine Months Ended, September 30,
	2005			2004
	(in thousands)
Cash provided by (used in):
Operating activities	$	61,390		$	7,549
Investing activities		(285,342	)		(30,485	)
Financing activities		292,305			70,734

Cash provided by operating activities was $61.4 million and $7.5 million in the first nine months of 2005 and 2004, respectively. Cash flow from operations increased primarily due to the timing of settlements of operating receivables and payables and higher oil and gas revenues during the first nine months of 2005 compared to the first nine months of 2004. Gas sales increased by $6.4 million, or 10%, and oil sales increased by $7.1 million, or 41%. The increase in sales revenue was attributable to higher average oil and gas prices during the first half of 2005.

Cash used in investing activities in the first nine months of 2005 and 2004 was $285.3 million and $30.5 million, respectively. Acquisition and development expenditures of oil and natural gas properties in the Gulf of

Mexico and North Sea totaled approximately $169.0 million and $103.6 million, respectively, in first nine months of 2005. Such expenditures in the Gulf of Mexico and North Sea were approximately $44.9 million and $4.5 million, respectively, in first nine months of 2004, offset by the receipt of $19.2 million in proceeds for the sale of certain interests in seven of our properties.

Cash provided by financing activities in the first nine months of 2005 consisted primarily of net proceeds of $121.7 million related to our amendment to the Term Loan, after deducting deferred financing costs of approximately $10.4 million related to the amendment and accrued interest and $169.4 million from the issuance of preferred stock, net of issuance costs. Cash provided by financing activities in the first nine months of 2004 consisted of net payments of $165.7 million related to our prior credit facility and net proceeds of $262.0 million related to our new Term Loan and warrants issued. We also incurred deferred financing costs of approximately $13.5 million related to the new Term Loan.

The Company’s restricted cash represents a time deposit denominated in Pounds Sterling which secures an irrevocable stand-by letter of credit for our future abandonment obligations with respect to the Kilmar field in the North Sea. The Letter of Credit and Reimbursement Agreement has an initial term of one year, and it extends for successive one-year terms unless thirty days notice is given of the intention not to extend the letter of credit.

Term Loan

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


	September 30, 2005			December 31, 2004
Term loan, net of unamortized discount of $6,809 and $8,129	$	341,441		$	210,309
Less current maturities		(3,500	)		(2,200	)

Total long-term debt	$	337,941		$	208,109

From this increase in borrowings, we received net proceeds of $117.8 million after deducting $3.6 million for accrued and unpaid interest on the Term Loans up to the Amendment Date and $10.7 million for fees and expenses.

The terms of the Term Loan, as amended April 14, 2005, require us to maintain certain covenants. Capitalized terms are defined in the credit agreement for the Term Loan. The covenants include:

•

Current Ratio of 1.0/1.0;

•

Consolidated Net Debt to EBITDAX coverage ratio of not greater than 3.0/1.0 at the end of each quarter;

•

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

•

Pre-tax PV-10 of our Total Proved Developed Producing Oil and Gas Reserves to Net Debt of at least 0.5/1.0 at June 30 and December 31 of any fiscal year;

•

Pre-tax PV-10 of our Total Proved Oil and Gas Reserves to Net Debt of at least 2.5/1.0 at June 30 and December 31 of any fiscal year;

•

the requirement to maintain hedges on no less than 40% of the next twelve months of forecasted production attributable to our proved producing reserves;

•

an increase in the amount of Permitted Business Investments from $25.0 million to $75.0 million during any fiscal year.

Commitments and Contingencies

ATP is required to make future payments under contractual obligations. ATP has also made various commitments in the future should certain events occur or conditions exist. ATP’s contractual obligations and commercial commitments from January 1, 2005 forward are described in the 2004 Form 10-K, as amended. 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. Although it is difficult to predict the ultimate outcome of these matters, management believes that the recorded amounts, if any, are reasonable. ATP’s contractual obligations and commercial commitments and have not changed significantly as of September 30, 2005.

Accounting Pronouncements

See Note 1 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 2004 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. We currently 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 local 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 functional currency in the U.S. dollar. We have not utilized derivatives or other financial instruments to hedge the risk associated with the movement in foreign currencies.

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 natural gas revenues 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 8 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

Our principal executive officer and principal financial officer performed an evaluation of our disclosure controls and procedures, which have been designed to permit us to effectively identify and timely disclose important information. They concluded that the controls and procedures were effective as of September 30, 2005, to ensure that material information was accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding required disclosure. Since that date, 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. 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 2004 Form 10-K, as amended.

PART II. OTHER INFORMATION

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

Item 2 — Unregistered Sales of Equity Securities and Use of Proceeds.

On August 2, 2005, ATP entered into a Subscription Agreement for the private placement of 175,000 shares of its 13 ¹/2% series A cumulative perpetual preferred stock, par value, $0.001 per share (the “Preferred Stock”), at a price of $1,000.00 per share. The 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 Preferred Stock is exempt from the registration requirements of the Securities Act of 1933, as amended, pursuant to Section 4(2) and Regulation D, Rule 506 promulgated thereunder because the transaction did not involve a public offering and the Preferred Stock was offered and issued only to institutional accredited investors.

Item 5 — Other Information

(a)

Completion of Acquisition or Disposition of Assets

On October 31, 2005, ATP acquired substantially all of the oil and gas assets of Millennium Offshore Group, Inc. (the “MOG Acquisition”). These assets consist of 29 blocks located on the Gulf of Mexico Outer Continental Shelf in less than 600 feet of water. The Company will operate most of the properties, which are currently producing approximately 25 MMcfe per day net to ATP’s interest. The reserves are approximately 80% gas and 20% oil and will be included in our year-end reserve report. Cash paid at closing was $40.0 million, and a contingent payment of an additional $10.0 million is expected to be required upon the attainment of certain cumulative production. The acquisition was effective October 1, 2005, and accordingly, the purchase price will be adjusted in a post-closing settlement expected to occur on January 31, 2006.

Financial Statements of Businesses Acquired—The Company is investigating its disclosure requirements for the MOG Acquisition under Rule 3-05(b) of Regulation S-X. The Company expects to file any financial information required under the rules in an amendment to this report no later than 71 calendar days after the date this report is filed.

Pro Forma Financial Information—The Company is investigating its disclosure requirements for the MOG Acquisition under Article 11 of Regulation S-X. If required, the Company expects to furnish any pro forma financial information under Article 11 in an amendment to this report no later than 71 calendar days after the date this report was filed.

(b)

Entry into a Material Definitive Agreement

On October 11, 2005, ATP Oil & Gas Corporation (the “Corporation”) entered into a Rights Agreement (the “Rights Agreement”) with American Stock Transfer & Trust Company, as rights agent (the “Rights Agent”), in connection with the declaration of a dividend distribution of preferred share purchase rights to shareholders of record on October 17, 2005. The material terms and conditions of the Rights Agreement are described below in Item 5(c).

(c)

Material Modification to Rights of Security Holders

On October 1, 2005, the Board of Directors of ATP Oil & Gas Corporation (the “Company”) authorized the issuance of one preferred share purchase right (a “Right”) with respect to each outstanding share of common stock, par value $.001 per share (the “Common Shares”), of the Company. The rights will be issued on October 17, 2005 to the holders of record of Common Shares on that date. Each Right entitles the

registered holder to purchase from the Company one one-hundredth (1/100) of a share of Junior Participating Preferred Stock, par value $.001 per share (the “Preferred Shares”), of the Company at a price of $150.00 per one one-hundredth of a Preferred Share (the “Purchase Price”), subject to adjustment. The description and terms of the Rights are set forth in a Rights Agreement (the “Rights Agreement”) dated as of October 11, 2005 between the Company and American Stock Transfer & Trust Company, as Rights Agent.

Detachment of Rights; Exercise. Initially, the Rights will attach to all Common Share certificates representing outstanding shares and no separate Right Certificate will be distributed. The Rights will separate from the Common Shares and a Distribution Date will occur upon the earlier of (i) 10 business days following a public announcement that a person or group of affiliated or associated persons, other than and Exempt Person (as defined in the Rights Agreement) (an “Acquiring Person”) has acquired beneficial ownership of 15% or more of the outstanding Common Shares of the Company and (ii) 10 business days following the commencement or announcement of an intention to commence a tender offer or exchange offer the consummation of which would result in the beneficial ownership by a person or group of 15% or more of such outstanding Common Shares.

Until the Distribution Date (or earlier redemption or expiration of the Rights) (i) the Rights will be evidenced, with respect to any of the Common Shares outstanding on October 17, 2005, by the certificates representing such Common Shares, (ii) the Rights will be transferred with and only with the Common Shares, (iii) new Common Share certificates issued after October 17, 2005, upon transfer or new issuance of the Common Shares will contain a notation incorporating the Rights Agreement by reference and (iv) the surrender for transfer of any certificates for Common Shares outstanding as of October 17, 2005, even without such notation or a copy of this Summary of Rights being attached thereto, will also constitute the transfer of the Rights associated with the Common Shares represented by such certificate.

As soon as practicable following the Distribution Date, separate certificates evidencing the Rights (the “Right Certificates”) will be mailed to holders of record of the Common Shares as of the close of business on the Distribution Date and such separate Right Certificates alone will thereafter evidence the Rights.

The Rights are not exercisable until the Distribution Date. The Rights will expire on October 17, 2015 (the “Final Expiration Date”), unless the Final Expiration Date is extended or the Rights are earlier redeemed or exchanged by the Company as described below.

If a person or group, other than an Exempt Person, were to acquire 15% or more of the Common Shares of the Company, each Right then outstanding (other than Rights beneficially owned by the acquiring person which would become null and void) would become a right to buy that number of Common Shares (or under certain circumstances, the equivalent number of one one-hundredth of a Preferred Share) that at the time of such acquisition would have a market value of two times the Purchase Price of the Right.

If, after a person or group, other than an Exempt Person, acquires 15% or more of the Common Shares of the Company, the Company were acquired in a merger or other business combination transaction or assets constituting more than 50% of its consolidated assets or producing more than 50% of its earning power or cash flow were sold, proper provision will be made so that each holder of a Right will thereafter have the right to receive, upon the exercise thereof at the then current Purchase Price of the Right, that number of shares of common stock of the acquiring company which at the time of such transaction would have a market value of two times the Purchase Price of the Right.

Preferred Shares. The dividend and liquidation rights, and the non-redemption feature, of the Preferred Shares are designed so that the value of one one-hundredth of a Preferred Share purchasable upon exercise of each Right will approximate the value of one Common Share. The Preferred Shares issuable upon exercise of the Rights will be non-redeemable and rank junior to all other series of the Company’s preferred stock. Each whole Preferred Share will be entitled to receive a quarterly preferential dividend equal to the greater of (i) $1.00 and (ii) 100 times the aggregate per share dividend declared on the Common Shares. In the event of

liquidation, the holders of the Preferred Shares will be entitled to receive a preferential liquidation payment per whole share equal to the greater of (i) $100 and (ii) 100 times the aggregate amount to be distributed per Common Share. In the event of any merger, consolidation or other transaction in which Common Shares are exchanged for or changed into other stock or securities, cash or other property, each whole Preferred Share will be entitled to receive 100 times the amount received per Common Share. Each whole Preferred Share shall be entitled to 100 votes on all matters submitted to a vote of the stockholders of the Company, and Preferred Shares shall generally vote together as one class with the Common Shares and any other capital stock on all matters submitted to a vote of the stockholders of the Company.

The offer and sale of the Preferred Shares issuable upon exercise of the Rights will be registered with the Securities and Exchange Commission and such registration will not be effective until the Rights become exercisable.

Antidilution and Other Adjustments. The Purchase Price and the number of one one-hundredth of a Preferred Share or other securities or property issuable upon exercise of the Rights are subject to customary adjustments from time to time to prevent dilution.

The number of outstanding Rights and the number of one one-hundredth of a Preferred Share issuable upon exercise of each Right are also subject to adjustment in the event of a stock split of the Common Shares or a stock dividend on the Common Shares payable in Common Shares or subdivisions, consolidations or combinations of the Common Shares occurring, in any such case, prior to the Distribution Date.

Exchange Option. At any time after the acquisition by a person or group of affiliated or associated persons, other than an Exempt Person, of beneficial ownership of 15% or more of the outstanding Common Shares of the Company and before the acquisition by a person or group of 50% or more of the outstanding Common Shares of the Company, the Board of Directors may, at its option, issue Common Shares in mandatory redemption of, and in exchange for, all or part of the then outstanding and exercisable Rights (other than Rights owned by such person or group which would become null and void) at an exchange ratio of one Common Share (or one one-hundredth of a Preferred Share) per Right, subject to adjustment.

Redemption of Rights. At any time prior to the first public announcement that a person or group has become the beneficial owner of 15% or more of the outstanding Common Shares, the Board of Directors of the Company may redeem all but not less than all the then outstanding Rights at a price of $.01 per Right (the “Redemption Price”). The redemption of the Rights may be made effective at such time, on such basis and with such conditions as the Board of Directors in its sole discretion may establish. Immediately upon the action of the Board of Directors ordering redemption of the Rights, the right to exercise the Rights will terminate and the only right of the holders of Rights will be to receive the Redemption Price.

No Rights as Shareholder. Until a Right is exercised, the holder thereof, as such, will have no rights as a shareholder of the Company, including, without limitation, the right to vote or to receive dividends.

Amendment of Rights. The terms of the Rights may be amended by the Board of Directors of the Company without the consent of the holders of the Rights, including an amendment to extend the Final Expiration Date, and, provided a Distribution Date has not occurred, to extend the period during which the Rights may be redeemed, except that after the first public announcement that a person or group has become the beneficial owner of 15% or more of the outstanding Common Shares, no such amendment may materially and adversely affect the interests of the holders of the Rights.

The foregoing description of the Rights does not purport to be complete and is qualified in its entirety by reference to the Rights Agreement, form of Statement of Designations of Junior Participating Preferred Stock, form of Right Certificate, form of the Summary of Rights and the specimen of the legend to be placed on new Common Share certificates, filed as exhibits hereto and incorporated by reference herein.

(d)

Amendments to Articles of Incorporation or Bylaws; Change in Fiscal Year

On October 14, 2005, in connection with the adoption of the Rights Agreement referred to in Item 5(b) above, the Corporation filed with the Secretary of State of the State of Texas a Statement of Designations, whereby the Corporation authorized 1,000,000 shares of its authorized preferred stock to be designated as Junior Participating Preferred Stock, par value $.001, and set forth the rights, voting powers, preferences, qualifications, limitations and restrictions of the Junior Participating Preferred Stock. A brief description of the rights, voting powers, preferences, qualifications, limitations and restrictions of the Junior Participating Preferred Stock is set forth in Item 5(c), above and is incorporated herein by reference.

The full text of the Statement of Designations is referenced herein as Exhibit 3.1 and is incorporated herein by reference. The foregoing description of the Statement of Designations is qualified in its entirety by reference to such exhibit.

Item 6 — Exhibits



3.1		Statement of Designations of Junior Participating Preferred Stock (incorporated by reference to Exhibit 2 to the Company’s Registration Statement on Form 8-A filed with the Securities and Exchange Commission on October 14, 2005).

4.1		Statement of Resolutions Establishing the 13¹/2% Series A Cumulative Perpetual Preferred Stock of ATP Oil & Gas Corporation, incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K, dated August 2, 2005.

4.2		Form of Stock Certificate, incorporated by reference to Exhibit 4.2 to the Company’s Current Report on Form 8-K, dated August 2, 2005.

4.3		Form of Subscription Agreement, incorporated by reference to Exhibit 4.3 to the Company’s Current Report on Form 8-K, dated August 2, 2005.

4.4		Rights Agreement dated October 11, 2005 between ATP Oil & Gas Corporation, and American Stock Transfer & Trust Company, as Rights Agent, specifying the terms of the Rights, which includes the form of Statement of Designations of Junior Participating Preferred Stock as Exhibit A, the form of Right Certificate as Exhibit B and the form of the Summary of Rights to Purchase Preferred Shares as Exhibit C (incorporated by reference to Exhibit 1 to the Company’s Registration Statement on Form 8-A filed with the Securities and Exchange Commission on October 14, 2005).

10.1		Purchase and Sale Agreement by and between Millennium Offshore Group, Inc., (“Seller”) and ATP Oil & Gas Corporation (“Buyer”) dated as of October 31, 2005.

10.2		Sale and Purchase Agreement, dated October 19, 2005, by and between Rowandrill, Inc. and ATP Oil & Gas Corporation, incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K, dated October 19, 2005.

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

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

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

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



99.1		Form of Right Certificate (included as Exhibit B to the Rights Agreement referenced as Exhibit 4.4 hereto). Pursuant to the Rights Agreement, printed Right Certificates will not be delivered until as soon as practicable after the Distribution Date (incorporated by reference to Exhibit 3 to the Company’s Registration Statement on Form 8-A filed with the Securities and Exchange Commission on October 14, 2005).

99.2		Form of Summary of Rights to Purchase Preferred Shares (included as Exhibit C to the Rights Agreement referenced as Exhibit 4.4 hereto) which, together with certificates representing the outstanding Common Shares of the Company, shall represent the Rights prior to the Distribution Date (incorporated by reference to Exhibit 4 to the Company’s Registration Statement on Form 8-A filed with the Securities and Exchange Commission on October 14, 2005).

99.3		Specimen of legend to be placed, pursuant to Section 3(c) of the Rights Agreement, on all new Common Share certificates issued by the Company after October 17, 2005 and prior to the Distribution Date upon transfer, exchange or new issuance (incorporated by reference to Exhibit 5 to the Company’s Registration Statement on Form 8-A filed with the Securities and Exchange Commission on October 14, 2005).

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 4, 2005	By:	/s/ Albert L. Reese, Jr.
		Albert L. Reese, Jr.
		Chief Financial Officer

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