Atp Oil & Gas (ATPGQ) 10-Q 2005 Q2 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-Q

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

For the quarterly period ended June 30, 2005

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

The number of shares outstanding of Registrant’s common stock, par value $0.001, as of August 5, 2005, was 29,041,897.

ATP OIL & GAS CORPORATION

TABLE OF CONTENTS

	Page
PART I.FINANCIAL INFORMATION
ITEM 1.FINANCIAL STATEMENTS (Unaudited)
Consolidated Balance Sheets: June 30, 2005 and December 31, 2004	3
Consolidated Statements of Operations: For the three and six months ended June 30, 2005 and 2004	4
Consolidated Statements of Cash Flows: For the six months ended June 30, 2005 and 2004	5
Consolidated Statements of Comprehensive Income (Loss): For the three and six months ended June 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	15
ITEM 3.QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	23
ITEM 4.CONTROLS AND PROCEDURES	24
PART II.OTHER INFORMATION	25

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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 Amounts)

(Unaudited)

	June 30, 2005			December 31, 2004
Assets
Current assets
Cash and cash equivalents	$	114,882		$	102,774
Accounts receivable (net of allowance of $1,496 and $1,499)		32,233			36,991
Derivative asset		3			791
Other current assets		4,449			3,788
Total current assets		151,567			144,344
Oil and gas properties (using the successful efforts method of accounting)
Proved properties		550,619			439,887
Unproved properties		10,992			10,516
		561,611			450,403
Less: Accumulated depletion, impairment and amortization		(247,364	)		(237,197	)
Oil and gas properties, net		314,247			213,206
Furniture and fixtures (net of accumulated depreciation)		753			741
Other assets, net		24,226			13,856
Total assets	$	490,793		$	372,147
Liabilities and Shareholders’ Equity
Current liabilities
Accounts payable and accruals	$	62,337		$	68,573
Current maturities of long-term debt		3,500			2,200
Asset retirement obligation		4,149			4,925
Derivative liability		1,823			316
Total current liabilities		71,809			76,014
Long-term debt		338,392			208,109
Asset retirement obligation		20,694			19,998
Deferred revenue		649			741
Other long-term liabilities and deferred obligations		8,983			10,121
Total liabilities		440,527			314,983
Shareholders’ equity
Preferred stock: $0.001 par value, 10,000,000 shares authorized; none issued		—			—
Common stock: $0.001 par value, 100,000,000 shares authorized; 29,071,658 issued and 28,995,818 outstanding at June 30, 2005; 28,959,701 issued and 28,883,861 outstanding at December 31, 2004		29			29
Additional paid in capital		141,598			140,628
Accumulated deficit		(91,080	)		(88,759	)
Accumulated other comprehensive income		630			6,177
Treasury stock, at cost		(911	)		(911	)
Total shareholders’ equity		50,266			57,164
Total liabilities and shareholders’ equity	$	490,793		$	372,147

See accompanying notes to consolidated financial statements.

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ATP OIL & GAS CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(In Thousands, Except Per Share Amounts)

(Unaudited)

	Three Months Ended June 30,						Six Months Ended June 30,
	2005			2004			2005			2004
Oil and natural gas revenues	$	33,488		$	32,879		$	70,468		$	56,890
Costs and operating expenses:
Lease operating		6,007			4,944			10,581			9,442
Exploration		2,173			195			2,507			280
General and administrative		5,163			3,694			9,354			7,778
Credit facility and related		—			—			—			1,850
Depreciation, depletion and amortization		15,201			13,961			35,704			25,544
Asset retirement accretion		600			483			1,179			974
(Gain) loss on abandonment		76			(17	)		76			(273	)
(Gain) on disposition of properties		—			(3,029	)		—			(6,011	)
Total costs and operating expenses		29,220			20,231			59,401			39,584
Income from operations		4,268			12,648			11,067			17,306
Other income (expense):
Interest income		998			108			1,488			132
Interest expense		(8,595	)		(6,010	)		(14,884	)		(9,759	)
Loss on extinguishment of debt		—			—			—			(3,326	)
Other income		7			180			8			180
Total other expense		(7,590	)		(5,722	)		(13,388	)		(12,773	)
Income (loss) before income taxes		(3,322	)		6,926			(2,321	)		4,533
Income tax expense		—			—			—			—
Net income (loss)	$	(3,322	)	$	6,926		$	(2,321	)	$	4,533
Basic and diluted income (loss) per common share	$	(0.11	)	$	0.28		$	(0.08	)	$	0.18
Weighted average number of common shares:
Basic		28,979			24,530			28,952			24,526
Diluted		29,794			24,715			29,788			24,706

See accompanying notes to consolidated financial statements.

4

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In Thousands)

(Unaudited)

	Six Months Ended June 30,
	2005			2004
Cash flows from operating activities
Net income (loss)	$	(2,321	)	$	4,533
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities –
Depreciation, depletion and amortization		35,704			25,544
Gain on disposition of properties		—			(6,011	)
Accretion of asset retirement obligation		1,179			974
Dry hole costs		2,107			—
Amortization of deferred financing costs		1,792			1,106
Loss on extinguishment of debt		—			3,326
Ineffectiveness of cash flow hedges		(173	)		20
Other noncash items		896			632
Noncash interest and credit facility expenses		—			1,709
Changes in assets and liabilities –
Accounts receivable and other assets		3,361			(17,568	)
Derivative liability		—			(166	)
Accounts payable and accruals		(3,095	)		(15,856	)
Other long-term assets		(626	)		(364	)
Other long-term liabilities and deferred obligations		(54	)		(3,455	)
Net cash provided by (used in) operating activities		38,770			(5,576	)
Cash flows from investing activities
Acquisition and development of oil and gas properties		(146,957	)		(32,746	)
Proceeds from disposition of properties		—			19,200
Additions to furniture and fixtures		(182	)		(139	)
Net cash used in investing activities		(147,139	)		(13,685	)
Cash flows from financing activities
Proceeds from long-term debt		132,113			227,000
Payments of long-term debt		(1,425	)		(165,130	)
Deferred financing costs		(10,416	)		(8,476	)
Repurchase of warrants		—			(750	)
Exercise of stock options		1,039			33
Other		(68	)		—
Net cash provided by financing activities		121,243			52,677
Effect of exchange rate changes on cash		(766	)		—
Net increase in cash and cash equivalents		12,108			33,416
Cash and cash equivalents, beginning of period		102,774			4,564
Cash and cash equivalents, end of period	$	114,882		$	37,980
Supplemental disclosures of cash flow information:
Cash paid during the period for interest	$	10,596		$	9,413

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 June 30,						Six Months Ended June 30,
	2005			2004			2005			2004
Net income (loss)	$	(3,322	)	$	6,926		$	(2,321	)	$	4,533
Other comprehensive loss:
Reclassification adjustment for settled contracts (net of income tax of $0)		76			(13	)		(292	)		(13	)
Change in fair value of outstanding hedge positions (net of income tax of $0)		(1,772	)		(470	)		(2,239	)		(1,239	)
Foreign currency translation adjustment		(2,201	)		(46	)		(3,017	)		772
Other comprehensive loss		(3,897	)		(529	)		(5,548	)		(480	)
Comprehensive income (loss)	$	(7,219	)	$	6,397		$	(7,869	)	$	4,053

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,” 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. The results of operations for the six months ended June 30, 2005 are not necessarily indicative of results to be expected for the entire year.

Note 2 — Recent Accounting Pronouncements

In November 2004, the Financial Accounting Standards Board (“FASB”) issued Revised Statement No. 123, “Accounting for Share-Based Payment” (“SFAS 123R”). This statement requires companies to measure and recognize compensation expense for all stock-based payments. In addition, companies will be required to calculate this compensation using the fair-value based method, versus the intrinsic value method previously allowed under SFAS No. 123, “Accounting for Stock-Based Compensation” (“SFAS 123”). As issued, this revision was effective for interim periods beginning after June 15, 2005. On April 14, 2005, the Securities and Exchange Commission (“SEC”) amended the compliance date for SFAS 123R to the beginning of the next fiscal year that begins after June 15, 2005. Accordingly, we will adopt this revised statement effective January 1, 2006. We are currently evaluating how we will adopt SFAS 123R and have not determined the method we will use to value stock-based compensation.

On March 29, 2005, the SEC released Staff Accounting Bulletin (“SAB”) 107 providing additional guidance in applying the provisions of SFAS 123(R), “Share-Based Payment.” SAB 107 should be applied when adopting SFAS 123(R) and addresses a wide range of issues, focusing on valuation methodologies and the selection of assumptions. In addition, SAB 107 addresses the interaction of SFAS 123(R) with existing SEC guidance.

In April 2005, the FASB issued Staff Position No. FAS 19-1, “Accounting for Suspended Well Costs” (“FSP 19-1”). FSP 19-1 amends SFAS No. 19, “Financial Accounting and Reporting by Oil and Gas Producing Companies,” (“SFAS 19”) to allow continued capitalization of exploratory well costs beyond one year from the date drilling was completed under circumstances where the well has found a sufficient quantity of reserves to justify its completion as a producing well and the enterprise is making sufficient progress assessing the reserves and the economic and operating viability of the project. FSP 19-1 also amends SFAS 19 to require enhanced disclosures of suspended exploratory well costs in the notes to the financial statements for annual and interim periods when there has been a significant change from the previous disclosure. We adopted the new requirements in the current period and it did not have a material impact on our consolidated financial position or results of operations.

In May 2005, the FASB issued SFAS No. 154, “Accounting Changes and Error Corrections—a replacement of APB Opinion No. 20 and FASB Statement No. 3” (“SFAS 154”). SFAS 154 changes the requirements for the accounting and reporting of a change in accounting principle, including voluntary changes in accounting principle and changes required by an accounting pronouncement that does not include specific transition provisions. SFAS 154 requires retrospective application to prior period financial statements of changes in accounting principle. If impractical to determine either the period-specific effects or the cumulative effect of the change, the new accounting principle would be applied as if it were adopted prospectively from the earliest date practical. The correction of errors in prior period financial statements should be identified as a “restatement.” SFAS 154 is effective for fiscal years beginning after December 15, 2005. Accordingly, we will adopt this statement effective January 1, 2006.

Note 3 — Acquisitions

On June 8, 2005, we increased our ownership in the Tors fields to 100% by acquiring the remaining 25% interest pursuant to an agreement with Gaz de France. The Secretary of State for Trade and Industry gave approval for ATP Oil & Gas (UK) Limited to have a 100% interest in the Tors fields and to act as the sole development and production operator. In accordance with the purchase agreement, we also are committed to pay future consideration contingent upon the successful development and operation of the property.

ATP was awarded seven blocks relating to its winning bids at the March 16, 2005 Central Gulf of Mexico Offshore Lease Sale. ATP owns a 100% working interest in and is the operator of all seven blocks. Two of the blocks are adjacent to the Company’s wholly-owned Mississippi Canyon 711 development. Two additional blocks are contiguous to an existing ATP operated development in the West Cameron area and the remaining three blocks provide for new development area opportunities.

During the second quarter of 2005, ATP acquired 100% of the working interest in South Marsh Island 166. The property has a temporarily abandoned well which has encountered hydrocarbons.

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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 six months ended June 30, 2005 (in thousands):

Asset retirement obligation at January 1, 2005	$	24,923
Liabilities incurred		212
Liabilities settled		(1,154	)
Accretion		1,179
Foreign currency translation		(317	)
Asset retirement obligation at June 30, 2005	$	24,843

Note 5 — Long-Term Debt

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

	June 30, 2005			December 31, 2004
Term loan, net of unamortized discount of $7,233 and $8,129	$	341,892		$	210,309
Less current maturities		(3,500	)		(2,200	)
Total long-term debt	$	338,392		$	208,109

At June 30, 2005, we have a $350.0 million 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 and ATP Oil & Gas (UK) Limited. The $350.0 million 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 June 30, 2005, the weighted average rate on outstanding borrowings was approximately 8.7%.

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.

8

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 June 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 Loans.

Note 6 — Stock –Based Compensation

SFAS No. 123, “Accounting for Stock-Based Compensation” (“SFAS 123”), 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 its 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.

9

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 June 30,						Six Months Ended June 30,
	2005			2004			2005			2004
Net income (loss) as reported	$	(3,322	)	$	6,926		$	(2,321	)	$	4,533
Deduct: Total stock-based compensation expense determined under fair value of all awards, net of related tax effects		(111	)		(34	)		(222	)		(69	)
Pro forma net income (loss)	$	(3,433	)	$	6,892		$	(2,543	)	$	4,464
Earnings per share:
Basic and diluted – as reported	$	(0.11	)	$	0.28		$	(0.08	)	$	0.18
Basic and diluted – pro forma	$	(0.11	)	$	0.28		$	(0.08	)	$	0.18

Note 7 — 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 June 30,					Six Months Ended June 30,
	2005			2004		2005			2004
Net income (loss)	$	(3,322	)	$	6,926	$	(2,321	)	$	4,533
Weighted average shares outstanding – basic		28,979			24,530		28,952			24,526
Effect of dilutive securities – stock options		466			185		489			180
Effect of dilutive securities – warrants		349			—		347			—
Weighted average shares outstanding – diluted		29,794			24,715		29,788			24,706
Net income (loss) per share – basic and diluted	$	(0.11	)	$	0.28	$	(0.08	)	$	0.18

Note 8 — 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.

10

At June 30, 2005, Accumulated Other Comprehensive Income included $1.8 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 June 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)
Gulf of Mexico	2005	Put	492,000	—	5.01	3
North Sea	2006	Swaps	5,400,000	11.57	—	(1,823	)

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 June 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	4,539,000	$	6.39
2006	2,780,000		7.36
Oil (Bbl):
2005	207,000		41.97
2006	300,500		47.96

(1) Includes the effect of basis differentials.

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Note 9 — 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 who participates on behalf of the Dutch government. 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 June 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) at June 30, 2005. We do not agree with the position that has been suggested and, if necessary, we will defend our position vigorously.

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 10 — 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.

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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 six months ended June 30, 2005 and 2004 is as follows (in thousands):

	Three Months Ended June 30, 2005
	Gulf of Mexico		North Sea			Total
Oil and natural gas revenues	$	31,461	$	2,027		$	33,488
Depreciation, depletion and amortization		13,799		1,402			15,201
Income (loss) from operations		5,058		(790	)		4,268
Acquisition and development of oil and gas properties		60,687		40,005			100,692
	Three Months Ended June 30, 2004
	Gulf of Mexico		North Sea			Total
Oil and natural gas revenues	$	26,296	$	6,583		$	32,879
Depreciation, depletion and amortization		8,671		5,290			13,961
Income (loss) from operations		13,525		(877	)		12,648
Acquisition and development of oil and gas properties		10,763		568			11,331
	Six Months Ended June 30, 2005
	Gulf of Mexico		North Sea			Total
Oil and natural gas revenues	$	64,131	$	6,337		$	70,468
Depreciation, depletion and amortization		32,123		3,580			35,704
Income (loss) from operations		11,508		(441	)		11,067
Acquisition and development of oil and gas properties		104,577		42,380			146,957
	Six Months Ended June 30, 2004
	Gulf of Mexico		North Sea			Total
Oil and natural gas revenues	$	47,108	$	9,782		$	56,890
Depreciation, depletion and amortization		17,798		7,746			25,544
Income (loss) from operations		19,117		(1,811	)		17,306
Acquisition and development of oil and gas properties		28,630		4,116			32,746
	At June 30, 2005
	Gulf of Mexico		North Sea			Total
Identifiable assets	$	388,436	$	102,357		$	490,793
	At December 31, 2004
	Gulf of Mexico		North Sea			Total
Identifiable assets	$	317,043	$	55,104		$	372,147

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Note 11 — Subsequent Event

On August 2, 2005, ATP entered into a Subscription Agreement for the private placement of 175,000 shares of its 13½% 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 and approximately $0.25 million of related expenses. The issuance of the Preferred Stock is exempt from the registration requirements of the Securities Act of 1933, as amended (the “Act”), pursuant to Section 4(2) of the Act 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.

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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, 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 undeveloped 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 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.

2005 Highlights

Our financial and operating performance for the second quarter 2005 included the following highlights:

• Acceleration of the first phase of the Tors development, including Kilmar jacket and deck construction completion;

• Increased ownership of the Tors property to 100%;

• Additional liquidity of $287.3 million since the beginning of the second quarter; $117.8 million net from the April 14, 2005 amendment of our Term Loan and $169.5 million net from the August 3, 2005 issuance of non-convertible perpetual preferred stock;

• Production of 10.7 Bcfe for the first half of the year and 5.0 Bcfe for the second quarter;

• Oil and natural gas revenues of $70.5 million for the first half of the year and $33.5 million for the second quarter, cash flows from operating activities of $38.8 million for the first half of the year and $28.1 million for the second quarter, and a net loss of $2.3 million for the first half of the year and $3.3 million for the second quarter;

• First production at High Island 74 and from a third well at Matagorda Island 709, and

• Acquisition of eight properties in the Gulf of Mexico, including seven at the Central Gulf of Mexico Lease Sale.

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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. Mississippi Canyon 711 (Gomez) in the Gulf of Mexico is currently scheduled to begin production 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.

These are not the only projects on which ATP is focused for 2005. ATP placed four wells on production in the Gulf of Mexico in the first half of 2005 with another four wells in progress at the end of the second quarter. In the second half of the year, eight additional wells are scheduled at six properties. The Company has delivered production of 54 - 65 MMcfe per day since the third quarter of 2004, despite offshore decline rates and a seasonal shut-in at our Helvellyn property in the U.K. Sector North Sea.

To fund its development plans, ATP has completed two financings, adding a total of $287.3 million in new liquidity. The first transaction, completed in April 2005, provided $117.8 million net 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 $169.5 million net of new equity in the form of a non-convertible, perpetual preferred stock.

Mississippi Canyon 711 and Tors will each require in excess of $100.0 million in development capital during the remainder of 2005. Other developments in the Gulf of Mexico and the North Sea, including our first development in the Dutch Sector, will total in excess of $100.0 million during the remainder of 2005. During the first two quarters of 2005, ATP paid $147.0 million for acquisition and development of oil and gas properties. Current estimates project that capital expenditures during the remainder of 2005 will be between $200 and $250 million. 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 Annual Report on Form 10-K.

Results of Operations

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

For the three months ended June 30, 2005, we reported a net loss of $3.3 million, or $0.11 per share on total revenue of $33.5 million as compared with net income of $6.9 million, or $0.28 per share, on total revenue of $32.9 million for the three months ended June 30, 2004.

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Oil and Natural Gas Revenues

Revenues presented in the table and in the discussion below represent revenues from sales of our oil and natural gas production volumes, and exclude the impact, if any, of hedging ineffectiveness and revenues from ATP Energy, Inc., a wholly owned subsidiary. Production sold under fixed price delivery contracts, which have been designated for the normal purchase and sale exemption under SFAS 133, are also included in these amounts. Approximately 58% and34% of our natural gas production was sold under these contracts for the three months ended June 30, 2005 and 2004, respectively. Approximately 58% and 42% of our oil production was sold under these contracts for the comparable periods. The realized prices below may differ from the market prices in effect during the periods depending on when the fixed price delivery contract was executed.

	Three Months Ended June 30,						% Change from 2004 to 2005
	2005			2004
Production:
Natural gas (MMcf)		3,721			5,434		(32	)%
Oil and condensate (MBbls)		205			199		3	%
Total (MMcfe)		4,953			6,630		(25	)%
Revenues from production (in thousands):
Natural gas	$	24,627		$	26,720		(8	)%
Effects of cash flow hedges		(255	)		(278	)	8	%
Total	$	24,372		$	26,442		(8	)%
Oil and condensate	$	8,944		$	6,443		39	%
Effects of cash flow hedges		—			—		—
Total	$	8,944		$	6,443		39	%
Natural gas, oil and condensate	$	33,571		$	33,153		1	%
Effects of cash flow hedges		(255	)		(278	)	8	%
Total revenues from production	$	33,316		$	32,875		1	%
Average sales price per unit:
Natural gas (per Mcf)	$	6.62		$	4.92		35	%
Effects of cash flow hedges (per Mcf)		(0.07	)		(0.05	)	(40	)%
Total (per Mcf)	$	6.55		$	4.87		35	%
Oil and condensate (per Bbl)	$	43.57		$	32.27		35	%
Effects of cash flow hedges (per Bbl)		—			—		—
Total (per Bbl)	$	43.57		$	32.27		35	%
Natural gas, oil and condensate (per Mcfe)	$	6.78		$	5.00		36	%
Effects of cash flow hedges (per Mcfe)		(0.05	)		(0.04	)	(25	)%
Total (per Mcfe)	$	6.73		$	4.96		36	%

Revenues from production increased 1% in the second quarter of 2005 compared to the same period in 2004. During the current period our production declined from the comparative period in 2004 due to natural decline which was not offset by significant new production. We expect the 2005 projects we are developing to begin contributing significantly to our production by the fourth quarter of the 2005. The comparable revenues were impacted favorably by a 36% increase in our sales price per unit.

Lease Operating. Lease operating expenses for the second quarter of 2005 increased to $6.0 million ($1.21 per Mcfe) from $4.9 million ($0.75 per Mcfe) in the second 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 $1.3 million ($0.27 per Mcfe) related to various platform repairs performed on our oil and gas properties in the Gulf of Mexico during the period.

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Exploration. During the second quarter of 2005, exploration expense included 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 $2.2 million in the second quarter of 2005. This exploration well was in progress at June 30, 2005. We expect to record an additional $3.4 million in the third quarter of 2005 related to the costs incurred on this well during July 2005.

General and Administrative. General and administrative expense increased to $5.2 million for the second quarter of 2005 compared to $3.7 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 $1.2 million (10%) during the second quarter of 2005 to $15.2 million from $14.0 million for the same period in 2004. The average DD&A rate was $3.10 per Mcfe in the second quarter of 2005 compared to $2.11 per Mcfe in the same quarter of 2004. The average DD&A expense per Mcfe increase was mainly due to the increased cost of development for those properties placed on production during the second quarter of 2005, and to the downward revision of reserves on six of our properties at December 31, 2004.

Gain on Disposition of Properties.In the second quarter of 2004, we recognized a gain of $3.0 million on the sale of interests in certain Gulf of Mexico properties.

Income Taxes. In the second quarter of 2005, we recorded income tax benefit of $1.4 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.

Six Months Ended June 30, 2005 Compared to Six Months Ended June 30, 2004

For the six months ended June 30, 2005, we reported net loss of $2.3 million, or $0.08 per share, on total revenue of $70.5 million as compared to net income of $4.5 million, or $0.18 per share, on total revenue of $56.9 million for the six months ended June 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 and revenues from ATP Energy, Inc., a wholly owned subsidiary. Production sold under fixed price delivery contracts, which have been designated for the normal purchase and sale exemption under SFAS 133, are also included in these amounts. Approximately 50% and 42% of our natural gas production was sold under these contracts for the six months ended June 30, 2005 and 2004, respectively. Approximately 58% and 37%, respectively, of our oil production was sold under these contracts for the comparable periods. The realized prices below may differ from the market prices in effect during the periods depending on when the fixed price delivery contract was executed.

	Six Months Ended June 30,					% Change from 2004 to 2005
	2005		2004
Production:
Natural gas (MMcf)		8,315		9,051		(8	)%
Oil and condensate (MBbls)		403		371		9	%
Total (MMcfe)		10,730		11,276		(5	)%
Revenues from production (in thousands):
Natural gas	$	53,264	$	45,162		18	%
Effects of cash flow hedges		157		(230	)	168	%
Total	$	53,421	$	44,932		19	%
Oil and condensate	$	16,874	$	11,772		43	%
Effects of cash flow hedges		—		—		0	%
Total	$	16,874	$	11,772		43	%
Natural gas, oil and condensate	$	70,138	$	56,934		23	%
Effects of cash flow hedges		157		(230	)	168	%
Total revenues from production	$	70,295	$	56,704		24	%
Average sales price per unit:
Natural gas (per Mcf)	$	6.41	$	4.99		28	%
Effects of cash flow hedges (per Mcf)		0.02		(0.03	)	167	%
Total (per Mcf)	$	6.43	$	4.96		29	%
Oil and condensate (per Bbl)	$	41.87	$	31.74		32	%
Effects of cash flow hedges (per Bbl)		—		—		0	%
Total (per Bbl)	$	41.87	$	31.74		32	%
Natural gas, oil and condensate (per Mcfe)	$	6.54	$	5.05		30	%
Effects of cash flow hedges (per Mcfe)		0.01		(0.02	)	150	%
Total (per Mcfe)	$	6.55	$	5.03		30	%

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Revenues from production increased 24% in the first half of 2005 compared to the same period in 2004. This increase was due primarily to a 30% increase in our sales price per Mcfe in 2005 as compared to 2004.

Lease Operating. Lease operating expenses for the first half of 2005 increased to $10.6 million ($0.99 per Mcfe) from $9.4 million ($0.84 per Mcfe) in the first half of 2004. This increase was due primarily to $1.7 million ($0.16 per Mcfe) in lease operating expense incurred in 2005 related to various platform repairs performed on our oil and gas properties in the Gulf of Mexico during the period.

Exploration. During the first half of 2005, exploration expense included one exploratory, step-out well at our producing Eugene Island 30/71 complex. This well found non-commercial quantities of hydrocarbons, resulting in exploration and dry hole expense of approximately $2.2 million in the first half of 2005. This exploration well was in progress at June 30, 2005. We expect to record an additional $3.4 million in the third quarter of 2005 related to the costs incurred on this well during July 2005.

General and Administrative. General and administrative expense increased to $9.4 million for the first half of 2005 compared to $7.8 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 fees of $0.8 million and professional fees of $0.8 million.

Depreciation, Depletion and Amortization. DD&A expense increased $10.2 million (40%) during the first half of 2005 to $35.7 million from $25.5 million for the same period in 2004. The average DD&A rate was $3.33 per Mcfe in the first half of 2005 compared to $2.27 per Mcfe in the same half of 2004. The average DD&A expense per Mcfe increase was mainly due to the increased cost of development for those properties placed on production during the first half of 2005, and to the downward revision of reserves on six of our properties at December 31, 2004.

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.

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.

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Income Taxes. In the first half of 2005, we recorded income tax expense of $0.2 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.

Liquidity and Capital Resources

At June 30, 2005, we had working capital of approximately $79.8 million, an increase of approximately $11.4 million from December 31, 2004.

On August 2, 2005, ATP entered into a Subscription Agreement for the private placement of 175,000 shares of its 13½% 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 and approximately $0.25 million of related expenses. The issuance of the Preferred Stock is exempt from the registration requirements of the Securities Act of 1933, as amended (the “Act”), pursuant to Section 4(2) of the Act 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.

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. While we have cash on our consolidated balance sheet of $114.9 at June 30, 2005, we expect that we will utilize all of this cash as well as a portion of the proceeds from our preferred stock offering 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

	Six Months Ended, June 30,
	2005			2004
	(in thousands)
Cash provided by (used in):
Operating activities	$	38,770		$	(5,576	)
Investing activities		(147,139	)		(13,685	)
Financing activities		121,243			52,677

Cash provided from operating activities in the first half of 2005 was $38.8 million and cash used in operations in the first half of 2004 was $5.6 million, respectively. Cash flow from operations increased primarily due to higher oil and gas revenues during the first half of 2005 compared to the first half of 2004. Gas sales increased by $8.5 million, or 19%, and oil sales increased by $5.1 million, or 43%. 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 half of 2005 and 2004 was $147.0 million and $13.7 million, respectively. Acquisition and development expenditures of oil and natural gas properties in the Gulf of Mexico and North Sea totaled approximately $104.6 million and $42.4 million, respectively, in first half of 2005. Such expenditures in the Gulf of Mexico and North Sea were approximately $28.6 million and $4.1 million, respectively, in first half of 2004, offset by the receipt of $19.2 million in proceeds for the sale of certain interests in seven of our properties.

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Cash provided by financing activities in the first half of 2005 consisted primarily of net proceeds of $117.8 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. Cash provided by financing activities in the first half of 2004 consisted of net payments of $117.1 million related to our prior credit facility and net proceeds of $179.5 million related to our new term loan and warrants issued. We also incurred deferred financing costs of approximately $8.5 million related to the new term loan.

Term Loan

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

	June 30, 2005			December 31, 2004
Term loan, net of unamortized discount of $7,233 and $8,129	$	341,892		$	210,309
Less current maturities		(3,500	)		(2,200	)
Total long-term debt	$	338,392		$	208,109

At June 30, 2005, we have a $350.0 million 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 and ATP Oil & Gas (UK) Limited. The $350.0 million 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 June 30, 2005, the weighted average rate on outstanding borrowings was approximately 8.7%.

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;

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• 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 June 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 Loans.

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 9 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 believes that the recorded amounts, if any, are reasonable.

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Contractual Obligations

We have various commitments primarily related to leases for office space, other property and equipment and other agreements. The following table summarizes certain contractual obligations at June 30, 2005 (in thousands):

	Payments Due By Period
Contractual Obligation	Total		Less Than 1 Year		1-3 Years		4-5 Years		After 5 Years
Long-term debt (1)	$	349,125	$	1,750	$	7,000	$	256,375	$	84,000
Interest on long-term debt (2)		129,843		15,064		59,496		52,883		2,400
Non-cancelable operating leases		3,802		324		1,228		1,167		1,083
Total contractual obligations	$	482,770	$	17,138	$	67,724	$	310,425	$	87,483

(1) Long-term debt does not reflect the unamortized discount of $7.2 million at June 30, 2005. See Note 5 to the Consolidated Financial Statements.

(2) Interest is based on average rates and quarterly principal payments in effect at June 30, 2005.

Accounting Pronouncements

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

Critical Accounting Policies

Our discussion and analysis of our financial condition and results of operations are based on consolidated financial statements which have been prepared in accordance with generally accepted accounting principles in the United States. The preparation of these financial statements requires us to make estimates and judgments that affect the reported amounts or assets, liabilities, revenues and expenses. We believe that certain accounting policies affect our more significant judgments and estimates used in the preparation of our consolidated financial statements. Our 2004 Annual Report on Form 10-K includes a discussion of our critical accounting policies.

Item 3. Quantitative and Qualitative Disclosures about Market Risks

Interest Rate Risk

We are exposed to changes in interest rates. Changes in interest rates affect the interest earned on our cash and cash equivalents and the interest rate paid on borrowings under the Term Loan. 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 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 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

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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 June 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.

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PART II. OTHER INFORMATION

Items 1, 3, & 5 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 13½% 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 and incurred approximately $0.25 million of related expenses. The issuance of the Preferred Stock is exempt from the registration requirements of the Securities Act of 1933, as amended (the “Act”), pursuant to Section 4(2) of the Act 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 4 – Submission of Matters to a Vote of Security Holders

The following items were presented for approval to stockholders of record on April 15, 2005 at the Company’s annual meeting of stockholders which was held on June 8, 2005 in Houston, Texas:

		For	Against	Abstained or Withheld
(i)	Election of Directors:
	Chris A. Brisack	24,949,582	—	327,537
	Walter Wendlandt	24,948,932	—	328,187
(ii)	Ratification of Deloitte & Touche LLP, independent certified public accountants, as auditors of the Company’s 2005 financial statements.	25,249,410	18,595	9,114

All matters received the required number of votes for approval.

Item 6 – Exhibits and Reports on Form 8-K

A. Exhibits

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

B. Reports on Form 8-K

April 20, 2005 - Amendment to the Company’s Term Loan.

May 11, 2005 - Results of operations for the first quarter of 2005.

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SIGNATURES

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

	ATP Oil & Gas Corporation
Date: August 9, 2005	By:	/s/ Albert L. Reese, Jr.
		Albert L. Reese, Jr.
		Chief Financial Officer

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