Atp Oil & Gas 10Q 2011 Q3 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 September 30, 2011

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

SECURITIES EXCHANGE ACT OF 1934

Commission file number: 001-32647

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 100

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 has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No ¨

Indicate by check mark whether the Registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer ¨ Accelerated filer x Non-accelerated filer ¨ Smaller reporting company ¨

Indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No x

The number of shares outstanding of the issuer’s common stock, par value $0.001, as of November 4, 2011 was 51,619,361.

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

TABLE OF CONTENTS


	Page
PART I. FINANCIAL INFORMATION

Item 1. Financial Statements (Unaudited)

Consolidated Balance Sheets: September 30, 2011 and December 31, 2010		3

Consolidated Statements of Operations: For the three and nine months ended September 30, 2011 and 2010		4

Consolidated Statements of Cash Flows: For the nine months ended September 30, 2011 and 2010		5

Consolidated Statements of Shareholders’ Equity and Temporary Equity: For the nine months ended September 30, 2011 and 2010		7

Consolidated Statements of Comprehensive Income (Loss): For the three and nine months ended September 30, 2011 and 2010		8

Notes to Consolidated Financial Statements		9

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		26

Item 3. Quantitative and Qualitative Disclosures about Market Risks		47

Item 4. Controls and Procedures		47

PART II. OTHER INFORMATION		49

Item 1. Legal Proceedings		49

Item 6. Exhibits		49

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(In Thousands, Except Shares Data)

(Unaudited)


	September 30, 2011			December 31, 2010
Assets
Current assets:
Cash and cash equivalents	$	172,175		$	154,695
Restricted cash		12,660			30,270
Accounts receivable (net of allowance of $225 and $225, respectively)		95,905			92,737
Deferred tax asset		—			8,191
Derivative asset		1,880			1,688
Other current assets		35,252			26,408

Total current assets		317,872			313,989

Oil and gas properties (using the successful efforts method of accounting):
Proved properties		4,687,122			4,291,440
Unproved properties		23,530			20,402

		4,710,652			4,311,842
Less accumulated depletion, depreciation, impairment and amortization		(1,685,647	)		(1,407,206	)

Oil and gas properties, net		3,025,005			2,904,636
Derivative asset		4,176			—
Deferred tax asset		16,899			—
Restricted cash		10,000			10,000
Deferred financing costs, net		43,934			48,353
Other assets, net		13,270			13,124

Total assets	$	3,431,156		$	3,290,102

Liabilities and Equity
Current liabilities:
Accounts payable and accruals	$	286,086		$	230,703
Current maturities of long-term debt		31,989			21,625
Asset retirement obligation		61,255			43,386
Deferred tax liability		17,038			—
Derivative liability		28,653			37,893
Current maturities of other long-term obligations		153,004			86,521

Total current liabilities		578,025			420,128
Long-term debt		1,983,704			1,857,784
Other long-term obligations		414,015			472,500
Asset retirement obligation		95,488			123,472
Deferred tax liability		47,768			16,956
Derivative liability		642			6,425

Total liabilities		3,119,642			2,897,265

Commitments and contingencies (Note 13)

Temporary equity:
Redeemable noncontrolling interest		115,406			140,851
8% convertible perpetual preferred stock: $0.001 par value; 784,943 issued and outstanding at September 30, 2011; None issued at December 31, 2010; Liquidation value of $78.5 million		68,153			—

Shareholders’ equity:
8% convertible perpetual preferred stock: $0.001 par value, 10,000,000 shares authorized; 2,340,057 issued and outstanding at September 30, 2011; 1,400,000 issued and outstanding at December 31, 2010. Liquidation value of $234.0 million and $140.0 million at September 30, 2011 and December 31, 2010, respectively.		224,583			140,000
Common stock: $0.001 par value, 100,000,000 shares authorized; 51,695,201 issued and 51,619,361 outstanding at September 30, 2011; 51,347,163 issued and 51,271,323 outstanding at December 31, 2010		52			51
Additional paid-in capital		533,885			570,739
Accumulated deficit		(526,586	)		(356,866	)
Accumulated other comprehensive loss	��	(103,068	)		(101,027	)
Treasury stock, at cost		(911	)		(911	)

Total shareholders’ equity		127,955			251,986

Total liabilities and equity	$	3,431,156		$	3,290,102

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,
	2011			2010			2011			2010
Oil and gas production revenues	$	170,135		$	102,121		$	509,518		$	296,249


Costs, operating expenses and other:
Lease operating		27,707			27,493			101,754			89,423
Exploration		66			543			1,066			1,264
General and administrative		13,540			9,646			33,442			28,269
Depreciation, depletion and amortization		77,715			62,505			231,353			158,621
Impairment of oil and gas properties		—			2,988			45,704			15,078
Accretion of asset retirement obligation		3,722			3,566			11,157			10,419
Drilling interruption costs		—			—			19,691			8,714
Loss on abandonment		2,691			32			4,074			233
Gain on exchange/disposal of properties		(1,000	)		(15,000	)		(1,000	)		(27,020	)

		124,441			91,773			447,241			285,001

Income from operations		45,694			10,348			62,277			11,248


Other income (expense):
Interest income		68			293			184			591
Interest expense, net		(77,356	)		(69,249	)		(249,883	)		(146,113	)
Derivative income (expense)		86,693			(12,665	)		72,349			14,799
Gain (loss) on debt extinguishment		—			—			1,091			(78,171	)

		9,405			(81,621	)		(176,259	)		(208,894	)


Income (loss) before income taxes		55,099			(71,273	)		(113,982	)		(197,646	)


Income tax benefit (expense):
Current		—			297			—			70
Deferred		(44,136	)		19,575			(38,784	)		76,196

		(44,136	)		19,872			(38,784	)		76,266

Net income (loss)		10,963			(51,401	)		(152,766	)		(121,380	)
Less income attributable to the redeemable noncontrolling interest		(9,829	)		(4,129	)		(16,954	)		(12,355	)
Less convertible preferred stock dividends		(6,725	)		(2,820	)		(12,270	)		(8,420	)

Net loss attributable to common shareholders	$	(5,591	)	$	(58,350	)	$	(181,990	)	$	(142,155	)


Net loss per share attributable to common shareholders:
Basic	$	(0.11	)	$	(1.15	)	$	(3.56	)	$	(2.81	)

Diluted	$	(0.11	)	$	(1.15	)	$	(3.56	)	$	(2.81	)


Weighted average number of common shares:
Basic		51,113			50,800			51,061			50,673
Diluted		51,113			50,800			51,061			50,673

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,
	2011			2010
Cash flows from operating activities
Net loss	$	(152,766	)	$	(121,380	)
Adjustments to reconcile net loss to net cash provided by operating activities –
Depreciation, depletion and amortization		231,353			158,621
Impairment of oil and gas properties		45,704			15,078
Gain on exchange/disposal of properties		(1,000	)		(27,020	)
Accretion of asset retirement obligation		11,157			10,419
Deferred income tax expense (benefit)		38,784			(76,196	)
Derivative income		(82,286	)		(14,088	)
(Gain) loss on debt extinguishment		(1,091	)		21,829
Stock-based compensation		4,669			5,366
Amortization of deferred revenue		—			(19,336	)
Noncash interest expense		29,015			22,756
Other noncash items, net		264			509
Changes in assets and liabilities –
Accounts receivable and other current assets		16,514			(13,476	)
Accounts payable and accruals		(5,095	)		39,908
Other assets and liabilities		(6,593	)		(601	)

Net cash provided by operating activities		128,629			2,389


Cash flows from investing activities –
Additions to oil and gas properties		(312,196	)		(498,625	)
Proceeds from disposition of properties		1,000			17,053
Increase (decrease) in restricted cash		17,610			(16,850	)

Net cash used in investing activities		(293,586	)		(498,422	)


Cash flows from financing activities –
Proceeds from senior second lien notes		—			1,492,965
Proceeds from first lien term loans		59,400			147,000
Proceeds from term loan facility–ATP Titan assets		91,000			143,250
Proceeds from term loans		—			46,000
Payments of term loans		(18,046	)		(1,262,610	)
Deferred financing costs		(4,536	)		(59,294	)
Proceeds from other long-term obligations		70,327			171,136
Payments of other long-term obligations		(130,882	)		(69,091	)
Distributions to noncontrolling interest		(36,132	)		(10,688	)
Proceeds from preferred stock issuances, net of costs		149,781			—
Purchase of capped-call options on ATP common stock		(26,500	)		—
Preferred stock dividends		(8,371	)		(8,448	)
Derivative contracts, net		66,009			—
Other financings, net		(30,625	)		—
Exercise of stock options/warrants		307			3,580

Net cash provided by financing activities		181,732			593,800


Effect of exchange rate changes on cash and cash equivalents		705			203


Increase in cash and cash equivalents		17,480			97,970
Cash and cash equivalents, beginning of year		154,695			108,961

Cash and cash equivalents, end of period	$	172,175		$	206,931

See accompanying notes to consolidated financial statements.

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (Continued)

(In Thousands)

(Unaudited)


	Nine Months Ended September 30,
	2011		2010
Noncash investing and financing activities
Increase in noncash property additions	$	20,643	$	112,927
Net property additions—nonmonetary exchange		—		11,778
Asset retirement costs capitalized		—		1,258

See accompanying notes to consolidated financial statements.

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY AND TEMPORARY EQUITY

(In Thousands)

(Unaudited)


	Nine Months Ended September 30,
	2011					2010
	Shares		Amount			Shares		Amount

Temporary Equity:

Redeemable Noncontrolling Interest:
Balance, beginning of period			$	140,851				$	139,598
Income attributable to the redeemable noncontrolling interest				16,954					12,355
Limited partner distributions				(42,399	)				(10,688	)

Balance, end of period			$	115,406				$	141,265


8% Convertible Perpetual Preferred Stock, Series B
Balance, beginning of period		—	$	—			—	$	—
Issuance of preferred stock		785		70,645			—		—
Issuance costs		—		(2,492	)		—		—

Balance, end of period		785	$	68,153			—	$	—

Shareholders’ Equity:

8% Convertible Perpetual Preferred Stock
Balance, beginning of period		1,400	$	140,000			1,400	$	140,000

Balance, end of period		1,400		140,000			1,400		140,000


8% Convertible Perpetual Preferred Stock, Series B
Balance, beginning of period		—		—			—		—
Issuance of preferred stock		940		84,583			—		—

Balance, end of period		940		84,583			—		—


Common Stock
Balance, beginning of period		51,271		51			50,679		51
Issuance of common stock – exercise of stock options/warrants		34		—			415		—
Restricted stock, net of forfeitures		314		1			178		—

Balance, end of period		51,619		52			51,272		51


Paid-in Capital
Balance, beginning of period				570,739					571,595
Purchase of capped-call options				(26,500	)				—
Issuance costs related to preferred stock				(2,976	)				—
Issuance of common stock – exercise of stock options/warrants				223					3,552
Preferred stock dividends				(12,270	)				(8,420	)
Stock-based compensation				4,669					5,366

Balance, end of period				533,885					572,093


Accumulated Deficit
Balance, beginning of period				(356,866	)				(19,317	)
Net loss				(152,766	)				(121,380	)
Less income attributable to the redeemable noncontrolling interest				(16,954	)				(12,355	)

Balance, end of period				(526,586	)				(153,052	)


Accumulated Other Comprehensive Loss
Balance, beginning of period				(101,027	)				(95,487	)
Other comprehensive loss				(2,041	)				(879	)

Balance, end of period				(103,068	)				(96,366	)


Treasury Stock, at Cost
Balance, beginning of period		76		(911	)		76		(911	)

Balance, end of period		76		(911	)		76		(911	)


Total Shareholders’ Equity			$	127,955				$	461,815

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,
	2011			2010			2011			2010
Net income (loss)	$	10,963		$	(51,401	)	$	(152,766	)	$	(121,380	)
Other comprehensive income (loss) – foreign currency translation adjustment		(9,389	)		8,811			(2,041	)		(879	)

Comprehensive income (loss)		1,574			(42,590	)		(154,807	)		(122,259	)
Less income attributable to the redeemable noncontrolling interest		(9,829	)		(4,129	)		(16,954	)		(12,355	)
Less convertible preferred stock dividends		(6,725	)		(2,820	)		(12,270	)		(8,420	)

Comprehensive loss attributable to common shareholders	$	(14,980	)	$	(49,539	)	$	(184,031	)	$	(143,034	)

See accompanying notes to consolidated financial statements.

Note 1 — Organization

Organization

ATP Oil & Gas Corporation is engaged internationally in the acquisition, development and production of oil and natural gas properties. Our management team has extensive engineering, geological, geophysical, technical and operational expertise in developing and operating properties in both our current and planned areas of operation. In the Gulf of Mexico and in the U.K. and Dutch sectors of the North Sea (the “North Sea”), we seek to acquire and develop properties with proved undeveloped reserves (“PUD”) that are economically attractive to us but are not strategic to major or large independent exploration-oriented oil and gas companies. Occasionally we will acquire properties that are already producing or where previous drilling has encountered reservoirs that appear to contain commercially productive quantities of oil and gas even though the reservoirs do not meet the SEC definition of proved reserves. In the Gulf of Mexico and North Sea, we believe that our strategy provides assets for us to develop and produce with an attractive risk profile at a competitive cost.

During 2011, we acquired three licenses in the Mediterranean Sea covering potential natural gas resources in the deep water off the coast of Israel. In the Mediterranean Sea our licenses relate to exploratory prospects where drilling has occurred nearby and hydrocarbons have been discovered by others. Our capital investment in the Mediterranean Sea related to these three licenses is expected to be minimal for the remainder of 2011 as we prepare our exploration and development plans for drilling in 2012.

Basis of Presentation

The consolidated financial statements include our accounts, the accounts of our majority owned limited partnership, ATP Infrastructure Partners, L.P. (“ATP-IP”) and those of our wholly-owned subsidiaries; ATP Oil & Gas (UK) Limited, or “ATP (UK);” ATP Oil & Gas (Netherlands) B.V.; ATP Energy, Inc., ATP Titan LLC, four wholly owned limited liability companies created to own our interests in ATP-IP and ATP Titan LLC and four other wholly owned limited liability companies formed related to our operations in the Mediterranean Sea. All intercompany transactions are eliminated in consolidation, and we separate the redeemable noncontrolling interest in ATP-IP in the accompanying statements.

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 statement of the results of operations for the interim periods. The interim financial information and notes hereto should be read in conjunction with our 2010 Annual Report on Form 10-K. The results of operations for the nine months ended September 30, 2011 are not necessarily indicative of results to be expected for the entire year. We have reclassified certain amounts applicable to prior periods to conform to current classifications. These reclassifications do not affect earnings.

Note 2 — Recent Accounting Pronouncements

In May 2011, the FASB issued guidance which will result in common fair value measurement and disclosure requirements in GAAP and International Financial Reporting Standards. For public entities, the guidance is effective for fiscal years, and interim periods within those years, beginning after December 15, 2011. We expect to adopt the provisions for the quarter ended March 31, 2012 and we do not anticipate that this will have a material impact on our financial position or results of operations.

In June 2011, the FASB issued guidance which eliminates the option to present components of other comprehensive income as part of the statement of changes in shareholders’ equity and requires that all nonowner changes in shareholders’ equity be presented either in a single continuous statement of comprehensive income or in two separate but consecutive statements. For public entities, the guidance is effective for fiscal years, and interim periods within those years, beginning after December 15, 2011. We expect to adopt the provisions for the quarter ending March 31, 2012 and we do not anticipate that this will have a material impact on our financial position or results of operations.

Note 3 — Risks and Uncertainties

Since May 2010 when the federal government imposed the first of a series of moratoriums on drilling in the Gulf of Mexico, we have faced unparalleled difficulties in obtaining permits to continue our development programs. Prior to the moratoriums, we anticipated developing and bringing to production three additional wells at our Telemark Hub and two additional wells at our Gomez Hub by the end of 2010. As of September 30, 2011, we have been able to bring to production two additional wells at the Telemark Hub and the third well has been drilled to total depth. First production of the third well has now been deferred until January of 2012 as we modify completion plans to accommodate additional pay sands discovered during drilling. During the third quarter, the two wells planned for the Gomez Hub were postponed to late 2012/early 2013 as permits have not yet been received for these two wells. We have also drilled two wells at Clipper—one has been completed, and the second is scheduled to be completed by the end of 2011—with pipeline construction and first production expected in the second half of 2012.

The new wells that have been placed on production have taken longer to complete and bring to production than originally planned and have not produced at rates that were previously projected. In addition, we have incurred capital and operating costs higher than we expected primarily due to additional regulations imposed since the deepwater Macondo incident and the requirement to sidetrack two of the wells. The new wells have helped us achieve production growth in 2011, and we forecast production and operating cash flow growth during the remainder of 2011 and 2012 as activity continues. While cash flows were lower than previously projected due to lower than expected production rates, the delays in bringing on new production and higher costs, we continued our development operations by supplementing our cash flows from operating activities with funds raised through various financing transactions (see the Consolidated Statement of Cash Flows.) Our projections for the fourth quarter of 2011 and calendar 2012 reflect our expectations for production based on actual production history, the development delays at Telemark and Gomez discussed above, the deferral of certain capital expenditures, the continuation of commodity prices near current levels, the higher anticipated costs associated with maintaining existing production and bringing additional production on-line, and the higher cost of servicing our additional financing and other obligations.

As of September 30, 2011, we had a working capital deficit of $260 million. To preserve our development momentum in the negative working capital environment that we have experienced throughout 2011, we have increased our First Lien Term Loans, issued convertible perpetual preferred stock, granted net profits interests (NPI’s) and dollar-denominated overriding royalty interests (ORRI’s) to certain of our vendors, and we have entered into prepaid swaps against our future production that provided cash proceeds to us at closing. We have negotiated with the constructor of the hull of the Octabuoy in China to defer the majority of our payments until the hull is ready to be moved to the North Sea, currently scheduled to be mid- to late-2012. A similar arrangement is in place for the topsides for the Octabuoy being constructed by the same company in China.

While we believe we can continue to meet our obligations for at least the next twelve months, our cash flow projections are highly dependent upon numerous assumptions including the timing and rates of production from our new wells, the sales prices we realize for our oil and natural gas, the cost to develop and produce our reserves, and a number of other factors, some of which are beyond our control. Our inability to increase near-term production levels and generate sufficient liquidity through the actions noted above could result in our inability to meet our obligations as they come due which would have a material adverse affect on us. In the event we do not achieve the projected production and cash flow increases, we will attempt to fund any short-term liquidity needs through more of these type transactions; however, there is no assurance that we will be able to repeat these types of transactions in the future if they are required to meet any short-term liquidity needs.

As operator of all of our projects that require cash commitments within the next twelve months, we retain significant control over the development concept and its timing. We consider the control and flexibility afforded by operating our properties under development to be instrumental to our business plan and strategy. To manage our liquidity, we have recently delayed certain capital commitments, and within certain constraints, we can continue to conserve capital by further delaying or eliminating future capital commitments. While postponing or eliminating capital projects will delay or reduce future cash flows from scheduled new production, this control and flexibility is one method by which we can match our capital commitments to our available capital resources.

Despite our anticipated production growth, we remain highly leveraged. Servicing our debt and other long-term obligations will continue to place significant constraints on us and makes us vulnerable to adverse economic and industry conditions. Specifically, certain of our financing and derivative transactions require us to make payments in future periods from the proceeds (or net profits) from the sale of production. While these financing transactions have enabled us to continue the development of our properties and meet current operating needs, they will significantly burden the future net cash flows from our production until these obligations are satisfied. (See Note 7, “Other Long-term Obligations,” and Note 12, “Derivative Instruments and Risk Management Activities” for further details.)

geological, geophysical, engineering and economic data for each reservoir. Therefore, these estimates are inherently imprecise and the quality and reliability of this data can vary. Estimates of our oil and natural gas reserves and the costs and timing associated with developing these reserves are subject to change, and may differ materially from our estimates. A substantial portion of our total proved reserves are undeveloped and recognition of such reserves as proved requires our ability to demonstrate sufficient capital is available to fund their development. The size of our operations and our capital expenditures budget limit the number of properties that we can develop in any given year and we intend to continue to develop these reserves through the end of the year and beyond, but there is no assurance we will be successful. Development of these reserves may not yield the expected results, or the development may be delayed or the costs may exceed our estimates, any of which may materially affect our financial position, results of operations, cash flows, the quantity of proved reserves that we report, and our ability to meet the requirements of our financing obligations.

A substantial portion of our current production is concentrated among relatively few wells located offshore in the Gulf of Mexico and in the North Sea, which are characterized by production declines more rapid than those of conventional onshore properties. As a result, we are particularly vulnerable to a near-term severe impact resulting from unanticipated complications in the development of, or production from, any single material well or infrastructure installation, including lack of sufficient capital, delays in receiving necessary drilling and operating permits, increased regulation, reduced access to equipment and services, mechanical or operational failures, and bad weather. Any unanticipated significant disruption to, or decline in, our current production levels or prolonged negative changes in commodity prices or operating cost levels could have a materially adverse effect on our financial position, results of operations, cash flows, the quantity of proved reserves that we report, and our ability to meet our commitments as they come due.

Oil and natural gas development and production in the Gulf of Mexico are regulated by the Bureau of Ocean Energy Management (“BOEM”) and the Bureau of Safety and Environmental Enforcement (“BSEE”) of the Department of the Interior, collectively, formerly known as the Bureau of Ocean Energy Management, Regulation and Enforcement (“BOEMRE”). Our near-term operating and development plans in the Gulf of Mexico, as well as our longer-term business plan, are dependent upon receiving regulatory approvals for deepwater drilling and other permits required by the BSEE. Delays in the permitting process directly impact the timing of our development and production activities, and can materially affect our financial position, results of operations, cash flows, and the quantity of proved reserves that we report.

We cannot predict future changes in laws and regulations governing oil and gas operations in the Gulf of Mexico. New regulations issued since the Macondo incident in 2010 have changed the way we conduct our business and increased our costs of developing and commissioning new assets. We incurred additional costs in 2010 from the deepwater drilling moratoriums, subsequent drilling permit delays and additional inspection and commissioning costs. Some of these additional costs have continued into 2011 and are expected to continue. Should there be additional significant future regulations or additional statutory limitations, they could require further changes in the way we conduct our business, further increase our costs of doing business or ultimately prohibit us from drilling for or producing hydrocarbons in the Gulf of Mexico. Additionally, we cannot influence or predict if or how the governments of other countries in which we operate may modify their regulatory regimes from time to time.

As an independent oil and gas producer, our revenue, profitability, cash flows, proved reserves and future rate of growth are substantially dependent on prevailing prices for oil and natural gas. Historically, the energy markets have been very volatile, and we expect such price volatility to continue. Any extended decline in oil or gas prices could have a materially adverse effect on our financial position, results of operations, cash flows, the quantities of oil and gas reserves that we can economically produce, and may restrict our ability to obtain additional financing or to meet the contractual requirements of our debt and other obligations.

Note 4 — Oil and Gas Properties

Acquisitions

During June 2011, we acquired interests in three deepwater licenses in the Mediterranean Sea off the coast of Israel. We will operate the licenses with working interests of 40%.

Impairment of Oil and Gas Properties

During the first nine months of 2011, we recognized impairment of proved Gulf of Mexico oil and gas properties of $45.7 million primarily related to two properties acquired in 2005 and 1999 for which remediation is not cost-effective in the current cost environment.

Note 5 — Income Taxes

Income taxes during interim periods are based on the estimated annual effective income tax rate plus any significant, unusual or infrequently occurring items that are recorded in the period the specific item occurs. We compute income taxes using an asset and liability approach, which results in the recognition of deferred tax liabilities and assets for the expected future tax consequences of temporary differences between the financial basis and the tax basis of those assets and liabilities. As of September 30, 2011 and December 31, 2010, for U.S. and Netherlands tax provision purposes, we have provided valuation allowances for the entirety of our net

deferred tax assets based on our cumulative net losses coupled with the uncertainties surrounding our future earnings forecasts. We recognized deferred tax assets only to the extent we expect to be able to offset deferred tax liabilities. The U.K. supplementary charge of corporation tax was increased from 20% to 32%, effective March 24, 2011, and Royal Assent was received on July 19, 2011. The U.K. rate increase has been reflected in the income tax provision for the nine months ended September 30, 2011, and all U.K. deferred tax assets and liabilities subject to the supplementary charge of corporation tax have been updated to reflect the 32% rate as of September 30, 2011. We recognized income tax expense of $44.1 million and benefit of $19.9 million, respectively, for the three months ended September 30, 2011 and 2010. We recognized income tax expense of $38.8 million and benefit of $76.3 million, respectively, for the nine months ended September 30, 2011 and 2010. The worldwide effective income tax rates for the three months ended September 30, 2011 and 2010 were 80% and 28%, respectively. The worldwide effective income tax rates for the nine months ended September 30, 2011 and 2010 were (34)% and 39%, respectively.

Note 6 — Long-term Debt

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


	September 30,			December 31,
	2011			2010
First lien term loans, net of unamortized discount of $2,663 and $2,644, respectively,	$	205,541		$	146,607
Senior second lien notes, net of unamortized discount of $5,021 and $6,071, respectively,		1,494,979			1,493,929
Term loan facility –ATP Titanassets, net of unamortized discount of $17,460 and $10,760, respectively,		315,173			238,873

Total debt		2,015,693			1,879,409
Less current maturities		(31,989	)		(21,625	)

Total long-term debt	$	1,983,704		$	1,857,784

In April 2010, we issued senior second lien notes (the “Notes”) in an aggregate principal amount of $1.5 billion, due May 1, 2015. The Notes bear interest at an annual rate of 11.875%, payable each May 1 and November 1, and contain restrictions that, among other things, limit the incurrence of additional indebtedness, mergers and consolidations, and certain restricted payments.

At any time (which may be more than once), on or prior to May 1, 2013, the Company may, at its option, redeem up to 35% of the outstanding Notes with money raised in certain equity offerings, at a redemption price of 111.9%, plus accrued interest, if any. In addition, the Company may redeem the Notes, in whole or in part, at any time before May 1, 2013 at a redemption price equal to par plus an applicable make-whole premium plus accrued and unpaid interest to the date of redemption. The Company may also redeem any of the Notes at any time on or after May 1, 2013, in whole or in part, at specified redemption prices, plus accrued and unpaid interest to the date of redemption.

The Notes also contain a provision allowing the holders thereof to require the Company to purchase some or all of those Notes at a purchase price equal to 101% of their aggregate principal amount, plus accrued and unpaid interest to the date of repurchase, upon the occurrence of specified change of control events.

In June 2010, we entered into a first lien credit agreement (the “Credit Facility”) with an initial balance of $150.0 million, due October 15, 2014, to replace the previous credit facility. Initial proceeds of the Credit Facility were $144.3 million, net of original issue discount and transaction fees. Principal outstanding under the term loans issued pursuant to the Credit Facility initially bore interest at an annual rate of 11.0%. As security for the Company’s obligations under the Credit Facility, the Company granted the lenders a security interest in and a first lien on not less than 80% of its proved oil and gas reserves in the Gulf of Mexico, capital stock of material subsidiaries (limited in the case of the Company’s non-U.S. subsidiaries to not more than 65% of the capital stock) and certain infrastructure assets, a portion of which has since been released in connection with the ATP Titan LLC financing discussed below. In February 2011, we entered into Incremental Loan Assumption Agreement and Amendment No. 1, relating to our First Lien Credit Agreement, dated as of June 18, 2010 to, among other things, decrease the interest rate on the entire balance outstanding from 11% to 9%. Additional borrowings were $60.0 million ($58.0 million, net of transaction costs and discount). Quarterly

Principal payments are required equal to¹/2% of remaining principal balance until June 18, 2014 and the remaining principal balance is due October 15, 2014.

The Notes and Credit Facility contain certain negative covenants which place limits on the Company’s ability to, among other things:

•

incur additional indebtedness;

•

pay dividends on the Company’s capital stock or purchase, repurchase, redeem, defease or retire the Company’s capital stock or subordinated indebtedness;

•

make investments outside of our normal course of business;

•

incur liens;

•

create any consensual restriction on the ability of the Company’s restricted subsidiaries to pay dividends, make loans or transfer property to the Company;

•

engage in transactions with affiliates;

•

sell assets; and

•

consolidate, merge or transfer assets.

In September 2010, we formed ATP Titan LLC (“Titan LLC”), a wholly owned and operated subsidiary which we consolidate in our financial statements, and transferred to it our 100% ownership of theATP Titan platform and related infrastructure assets. Simultaneous with the transfer, Titan LLC entered into a $350.0 million term loan facility (the “ATP Titan Facility”). Under the initial agreement and the First and Second Amendments to Term Loan Agreement and Limited Waivers entered into in March and September 2011, respectively, we have now drawn down the entire amount available receiving proceeds of $317.9 million, net of discount and direct issuance costs. TheATP Titan Facility bears interest at LIBOR (floor of 0.75%) plus 8%. Principal payments are required equal to 2.25% (of original principal) per quarter until October 4, 2012, and 2.5% thereafter until maturity. TheATP Titan Facility requires us to maintain in a restricted account a minimum $10.0 million cash balance plus additional amounts based on production at the Telemark Hub to be used for the quarterly debt service of theATP Titan Facility. TheATP Titan Facility is secured solely by theATP Titan and related infrastructure assets and the outstanding member interests in Titan LLC, which are all owned indirectly by the Company. TheATP Titan Facility includes a customary condition that there has not occurred a material adverse change with respect to the Company. The Company remains operator and 100% owner of theATP Titan platform, related infrastructure assets and the working interest in its Telemark Hub oil and gas reserves.

The Credit Facility and the Notes contain customary events of default, and if certain of those events of default were to occur and remain uncured, such as a failure to pay principal or interest when due, our lenders could terminate future lending commitments under the Credit Facility, and our lenders could declare the outstanding borrowings due and payable. The Credit Facility also contains an event of default if there has occurred a material adverse change with respect to the Company’s compliance with environmental requirements and applicable laws and regulations. TheATP Titan Facility contains standard events of default and an event of default if there has occurred a material adverse change with respect to the Company. TheATP Titan Facility also contains provisions that provide for cross defaults among the documents entered into in connection with theATP Titan Facility and acceleration of Titan LLC’s payment obligations under theATP Titan Facility in certain situations. In addition, our hedging arrangements contain standard events of default, including cross default provisions, that, upon a default, provide for (i) the delivery of additional collateral, (ii) the termination and acceleration of the hedge, (iii) the suspension of the lenders’ obligations under the hedging arrangement or (iv) the setoff of payment obligations owed between the parties.

The effective annual interest rate and fair value of our long-term debt was 11.9% and $1.6 billion, respectively, at September 30, 2011.

Note 7 — Other Long-term Obligations

Other long-term obligations consisted of the following (in thousands):


	September 30,			December 31,
	2011			2010
Net profits interests	$	350,073		$	331,776
Dollar-denominated overriding royalty interests		37,944			52,825
Gomez pipeline obligation		73,189			73,868
Vendor deferrals – Gulf of Mexico		10,029			7,096
Vendor deferrals – North Sea		93,202			90,874
Other		2,582			2,582

Total		567,019			559,021
Less current maturities		(153,004	)		(86,521	)

Other long-term obligations	$	414,015		$	472,500

Net Profits Interests

Beginning in 2009, we have granted dollar-denominated overriding royalty interests in the form of net profits interests (“NPIs”) in certain of our proved oil and gas properties in and around the Telemark Hub, Gomez Hub and Clipper to certain of our vendors in exchange for oil and gas property development services and to certain finance entities in exchange for cash proceeds. During April 2011, we closed an NPI transaction in the Telemark Hub for $40.0 million. The purchaser acquired an existing vendor NPI for $19.7 million, thereby extinguishing the existing NPI liability of $20.8 million, and contributed an additional $20.3 million toward the development of the Telemark Hub in exchange for a larger percentage of the net profits from production at the Telemark Hub that will continue until the purchaser recovers $40.0 million, plus an overall rate of return.

The interests granted are paid solely from the net profits, as defined, of the subject properties. As the net profits increase or decrease, primarily through higher or lower production levels and higher or lower prices of oil and natural gas, the payments due the holders of the net profits interests increase or decrease accordingly. If there is no production from a property or if the net profits are negative during a payment period, no payment would be required. We also accrete the liability over the estimated term in which the NPI is expected to be settled using the effective interest method with related interest expense presented net of amounts capitalized on the Consolidated Statements of Operations. The term of the NPIs is dependent on the value of the services contributed by these vendors or the cash proceeds contributed by the finance companies coupled with the timing of production and future economic conditions, including commodity prices and operating costs. Upon recovery of the agreed rate of return, the NPIs terminate. Because NPIs were granted on proved properties where production is reasonably assured, we have accounted for these NPI’s as financing obligations on our Consolidated Balance Sheets. As such, the reserves and production revenues associated with the NPIs are retained by the Company. We expect approximately 80% of the NPIs to be repaid over the next 18 months based on anticipated production, commodity prices and operating costs.

Dollar-denominated Overriding Royalty Interests

During April and June 2011, we sold, for an aggregate of $50.0 million, two dollar-denominated overriding royalty interests (“Overrides”) in our Gomez Hub properties similar to those sold in 2009 and 2010. These Overrides obligate us to deliver proceeds from the future sale of hydrocarbons in the specified proved properties until the purchasers achieve a specified return. As the proceeds from the sale of hydrocarbons increase or decrease, primarily through changes in production levels and oil and natural gas prices, the payments due the holders of the overriding royalty interests will increase or decrease accordingly. If there is no production from a property during a payment period, no payment would be required. The percentage of property revenues available to satisfy these obligations is dependent upon certain conditions specified in the agreement. Upon recovery of the agreed rate of return, the Overrides terminate and our interest increases accordingly. Because of the explicit rate of return, dollar-denomination and limited payment terms of the Overrides, they are reflected in the accompanying financial statements as financing obligations. As such, the reserves and production revenues are retained by the Company. Related interest expense is presented net of amounts capitalized on the Consolidated Statements of Operations. We expect the Overrides to be repaid over approximately the next 18 months based on anticipated production and commodity prices.

Gomez Pipeline Obligation

In 2009, we sold to a third party for net proceeds of $74.5 million the oil and natural gas pipelines that service the Gomez Hub. In conjunction with the sale, we entered into agreements with the purchaser to transport our oil and natural gas production for the remaining production life of our fields serviced by theATP Innovatorproduction platform for a per-unit fee that is subject to a minimum monthly payment through December 31, 2016. Such minimum fees, if applicable, can be recovered by ATP in future periods within the same calendar year whenever fees owed during a month exceed the minimum due. We remain the operator of the pipeline and are responsible for all of the related operating costs. As a result of the retained asset retirement obligation and the purchaser’s option to convey the pipeline back to us at the end of the life of the fields in the Gomez Hub, the transaction has been accounted for as a financing obligation equal to the net proceeds received. This obligation is being amortized based on the estimated proved reserve life of the Gomez Hub properties using the effective interest method with related interest expense presented net of amounts capitalized on the Consolidated Statements of Operations. All payments made in excess of the minimum fee in future periods will be reflected as interest expense of the financing obligation.

Vendor Deferrals

In the Gulf of Mexico, in addition to the NPIs exchanged for development services described above, we have negotiated with certain other vendors involved in the development of the Telemark and Gomez Hubs to partially defer payments over a twelve-month period beginning with first production. We accrue the present value of the deferred payments and accrete the balance over the estimated term in which it is expected to be paid using the effective interest method with related interest expense presented net of amounts capitalized, on the Consolidated Statements of Operations.

In the U.K. North Sea, development of our interest in the Cheviot field continues. During February 2011, we entered into an amendment to our agreement for the construction and delivery of the Octabuoy hull and topside equipment. The amendment provided for additional deferrals totaling approximately $124.3 million and delayed the final payment until the second quarter of 2013. The remaining amount due under the amended agreement in 2011 is $15.6 million (which was paid in the fourth quarter of 2011) with an aggregate of $229.0 million due in 2012 and 2013. As work is completed and amounts are earned under the amended agreement, we record obligations and related interest expense, net of amounts capitalized, on the Consolidated Financial Statements.

The weighted average effective interest rate on our other long-term obligations set forth above was 19.2% at September 30, 2011.

Note 8 — Preferred Stock

In June 2011, we issued 1.7 million shares of 8% convertible perpetual preferred stock (“Series B Preferred Stock”) and received net proceeds of $123.3 million ($90 per share before underwriters’ discounts and commissions, option contract costs (discussed below) and offering expenses). The Series B Preferred Stock has terms and features which are substantially identical to the convertible preferred stock we issued in 2009 (collectively, the “Preferred Stock”). Each share of Preferred Stock is perpetual, has no voting rights, has a liquidation preference of $100, pays cumulative dividends at an annual rate of 8% and is convertible at any time, at the option of the holder, into 4.5045 shares of common stock. After September 30, 2014, we have the option to force conversion to common stock provided that the prevailing common stock market price exceeds the conversion price by 150% on average for a stipulated period of time.

In conjunction with issuance of the Series B Preferred Stock, we purchased for $26.5 million capped-call options (“Options”) to cover all 14.1 million shares of common stock issuable upon conversion of the Series B Preferred Stock and the preferred stock we issued in 2009. The Options allow us to prevent dilution due to common stock issuance upon preferred stock conversion up to a price per common share of $27.50. The shares of common stock acquirable under the Options are indexed to our common stock price at the time of exercise and the Options can only be settled in common stock. As a result, the purchase price of the Options is recorded as a component of additional paid-in capital within Shareholders’ Equity in the accompanying Consolidated Financial Statements.

At September 30, 2011, a portion of the Series B Preferred Stock is classified as temporary equity because, in the event of certain fundamental changes, as defined in the statement of resolutions, the Company could be required to issue in the aggregate more shares of common stock pursuant to the conversion ratio most favorable to the holders than currently are authorized and unissued (the “Common Share Shortfall”). The value of the temporary equity is deemed to be the number of shares of Preferred Stock that would account for such common share shortfall times the $86.83 fair value per share (net of issuance costs of $3.17 per share). This amount will be revalued in future reporting periods as the Common Share Shortfall changes, and at such time as we have sufficient authorized and unissued common shares to satisfy the most favorable conversion obligation possible under the statement of resolutions, this amount will be reclassified to permanent equity.

Note 9 — Asset Retirement Obligation

Following are reconciliations of the beginning and ending asset retirement obligation for the following periods (in thousands):


	Nine Months Ended
	September 30,
	2011			2010
Asset retirement obligation, beginning of period	$	166,858		$	150,199
Liabilities incurred		4,074			1,491
Liabilities settled		(25,602	)		(2,890	)
Property dispositions		—			(242	)
Accretion of asset retirement obligation		11,157			10,419
Changes in estimates		256			(182	)

Total asset retirement obligation		156,743			158,795
Less current portion		(61,255	)		(46,984	)

Total long-term asset retirement obligation, end of period	$	95,488		$	111,811

Note 10 — Stock–Based Compensation

Stock-based compensation expense was as follows (in thousands):


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2011		2010		2011		2010
Stock options		687		657		1,690		2,022
Restricted stock		1,097		1,151		2,979		3,344

The fair values of options granted were estimated at the date of grant using a Black-Scholes option-pricing model assuming no dividends and with the following weighted average assumptions for grants during the periods indicated:


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2011			2010			2011			2010
Weighted average volatility		87	%		84	%		85	%		84	%
Expected term (in years)		3.8			3.8			3.8			3.8
Risk-free rate		0.8	%		1.0	%		1.4	%		1.2	%
Weighted average fair value of options – grant date	$	8.41		$	5.45		$	9.62		$	5.53

The following table sets forth a summary of option transactions for the nine months ended September 30, 2011:


	Number of Options			Weighted Average Grant Price		Aggregate Intrinsic Value (1) ($000)		Weighted Average Remaining Contractual Life
									(in years	)
Outstanding at beginning of period		1,521,291		$	23.31
Granted		328,510			16.03
Canceled		(61,682	)		23.17
Expired		(173,687	)		38.27
Exercised		(34,927	)		6.15	$	406

Outstanding at end of period		1,579,505			20.54	$	570		2.9

Vested and expected to vest		1,347,270			20.51	$	486		2.9

Options exercisable at end of period		623,055			27.61	$	235		1.9

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

At September 30, 2011, unrecognized compensation expense related to nonvested stock option grants totaled $3.5 million. Such unrecognized expense will be recognized as vesting occurs over a weighted average period of 2.5 years.

At September 30, 2011, unrecognized compensation expense related to restricted stock totaled $4.2 million. Such unrecognized expense will be recognized as vesting occurs over a weighted average period of 2.1 years. The following table sets forth the changes in nonvested restricted stock for the nine months ended September 30, 2011:


	Number of Shares			Weighted Average Grant-date Fair Value		Aggregate Intrinsic Value (1) ($000)
Nonvested at beginning of period		422,637		$	19.76
Granted		313,111			16.62
Vested		(243,065	)		24.65

Nonvested at end of period		492,683			15.36	$	3,799

(1)	Based upon the closing market price of the common stock on the last trading day of the period.

Note 11 — Earnings Per Share

Basic and diluted net loss per share (“EPS”) is computed based on the following information (in thousands, except per share amounts):


	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
Net loss attributable to common shareholders:
Net loss attributable to common shareholders	$	(5,591	)	$	(58,350	)	$	(181,990	)	$	(142,155	)
Add impact of assumed preferred stock conversions (if-converted method)		—			—			—			—

Net loss attributable to common shareholders and impact of assumed conversions	$	(5,591	)	$	(58,350	)	$	(181,990	)	$	(142,155	)

Weighted average shares outstanding:
Weighted average shares outstanding—basic		51,113			50,800			51,061			50,673
Effect of potentially dilutive securities—stock options and warrants		—			—			—			—
Nonvested restricted stock		—			—			—			—
Preferred stock		—			—			—			—

Weighted average shares outstanding—diluted		51,113			50,800			51,061			50,673

Net loss per share attributable to common shareholders:
Basic	$	(0.11	)	$	(1.15	)	$	(3.56	)	$	(2.81	)

Diluted	$	(0.11	)	$	(1.15	)	$	(3.56	)	$	(2.81	)

The following were excluded from diluted EPS because their inclusion would have been antidilutive (in thousands):


	Three Months Ended September 30,				Nine Months Ended September 30,
	2011		2010		2011		2010
Net loss attributable to common shareholders:
Preferred stock dividends	$	6,725	$	2,820	$	12,270	$	8,420
Weighted average shares outstanding:
Common stock equivalents		269		295		414		503
Assumed conversion of preferred stock		14,077		6,306		9,238		6,306
Out-of-the-money stock options		1,098		1,009		950		1,167

Note 12 — Derivative Instruments and Risk Management Activities

At September 30, 2011, we had the following derivative contracts in place:


						Net Fair Value Asset (Liability) (1)
Period	Type	Volumes		Price		Current			Noncurrent
				$/Unit		($000)			($000)
Oil (Bbl) –Gulf of Mexico
Remainder 2011	Swaps		552,000		84.91		7,777			—
2012	Swaps		2,218,750		89.06		13,179			3,510
2013	Swaps		90,000		90.40		—			666
Remainder 2011	Prepaid Swaps (4)		142,600		—		(14,292	)		—
2012	Prepaid Swaps (4)		354,950		—		(32,052	)		—
Remainder 2011	Calls (2)		184,000		110.00		19			—

Total							(25,369	)		4,176

Natural Gas (MMBtu)
North Sea
Remainder 2011	Swaps		460,000		9.27		(418	)		—
2012	Swaps		1,646,000		8.58		(2,653	)		(471	)
Gulf of Mexico
Remainder 2011	Calls (3)		920,000		5.10		(1	)		—
2012	Calls (3)		3,660,000		5.35		(194	)		(171	)
Remainder 2011	Fixed-price physicals		1,380,000		4.64		1,162			—
2012	Fixed-price physicals		1,365,000		4.64		700			—

Total							(1,404	)		(642	)

Total asset							1,880			4,176
Total liability							(28,653	)		(642	)

Total							(26,773	)		3,534

(1)

None of the derivatives outstanding is designated as a hedge for accounting purposes.

(2)

During the three months ended September 30, 2011, we terminated certain oil swaps and realized $10.7 million in gains. However, we retained the purchased-call options which had been matched to some of the oil swaps in order to allow us to reparticipate in price increases above the option strike price.

(3)

During the first quarter of 2011, we sold U.S. gas call options and received premiums of $2.1 million.

(4)

In order to manage our exposure to oil price volatility, in the third quarter of 2011, we entered into certain off-market oil swap derivative contracts which provide us with $62.3 million of cash advances from the counterparty and obligate us to pay market prices at the time of settlement.

At December 31, 2010, we had the following derivative contracts in place:


					Net Fair Value Asset (Liability) (2)
Period	Type	Volumes		Price	Current			Noncurrent
				$/Unit (1)	($000)			($000)
Oil (Bbl) –Gulf of Mexico
2011	Swaps		2,124,500	81.99		(23,084	)		—
2012	Swaps		1,120,750	89.37		—			(4,236	)
2013	Swaps		90,000	90.40		—			(199	)
2011	Swaps (3)		911,000	78.41		(12,027	)		—

Total						(35,111	)		(4,435	)

Natural Gas (MMBtu)
North Sea
2011	Swaps		1,641,000	7.21		(2,782	)		—
2012	Swaps		1,464,000	8.20		—			(1,249	)
Gulf of Mexico
2011	Fixed-price physicals		5,025,000	4.78		1,030			—
2012	Fixed-price physicals		1,365,000	4.64		—			(741	)

2011	Collars		1,350,000	4.75-7.95		658			—

Total						(1,094	)		(1,990	)


Derivative asset						1,688			—
Derivative liability						(37,893	)		(6,425	)

Total						(36,205	)		(6,425	)

(1)

Unit price for collars reflects the floor and the ceiling prices, respectively.

(2)

None of the derivatives outstanding are designated as hedges for accounting purposes.

(3)

These swaps include call options to allow us to participate in per barrel price increases above $111.00.

During the first quarter of 2011, we sold certain natural gas call options in exchange for a premium from the counterparties. At settlement of a call option, if the market price exceeds the strike price of the call option, the Company pays the counterparty such excess. If the market price settles below the strike price of the call option, no payment is due from either party. Cash settlements of our derivative instruments are classified as operating cash flows unless the derivative contains a significant financing element at contract inception, in which case these cash settlements are classified as financing cash flows in the accompanying Consolidated Statements of Cash Flows.

During the nine months ended September 30, 2011, we paid net cash settlements of $15.1 million on our commodity derivatives. Our derivative income (expense) for the nine months ended September 30, 2011 and 2010 is based entirely on nondesignated derivatives and consists of the following (in thousands):


	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
Gains (losses) from:
Settlements of contracts	$	(1,206	)	$	1,888		$	(17,761	)	$	439
Early terminations of contracts		10,700			—			10,700			—
Unrealized gains (losses) on open contracts		77,199			(14,553	)		79,410			14,360


Derivative income (expense)	$	86,693		$	(12,665	)	$	72,349		$	14,799

Note 13 — Commitments and Contingencies

The development, production and sale of oil and natural gas in the Gulf of Mexico and in the North Sea are subject to extensive laws and regulations, including environmental laws and regulations in each locality in which we operate. We may be required to make large expenditures to comply with environmental and other governmental regulations. Under these laws and regulations, we could be liable for personal injuries, property damage, oil spills, discharge of hazardous materials, remediation and clean-up costs and other environmental damages. Failure to comply with these laws and regulations also may result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties. Moreover, these laws and regulations could change in ways that substantially increase our costs (see the discussion in Note 3, “Risks and Uncertainties”). Accordingly, any of these liabilities, penalties, suspensions, terminations or regulatory changes could materially adversely affect our financial condition and results of operations. We believe that we are in compliance with all of the laws and regulations which apply to our operations.

Under the provisions of our limited partnership agreement with ATP-IP, we could be required to repurchase the Class A limited partner interest if certain change of control events were to occur. If a change of control were to become probable in a future period, we would be required to adjust the carrying amount of the redeemable noncontrolling interest to its redemption amount, to the extent it differed from the carrying amount, at the time the change of control was deemed to be probable. We do not currently believe a change of control is probable.

We are a party to a multi-year (life of reserves) firm transportation agreement covering certain production in the North Sea that requires us to pay a pipeline tariff on our nominated contract quantity of natural gas during the contract period, whether or not the volumes are delivered to the pipeline. For any contract period where actual deliveries fall short of contract quantities, we can make up such amounts by delivering volumes over the subsequent four years free of tariff, within certain limitations. While we control our nominations, we are subject to the risk we may be required to prepay or ultimately pay transportation on undelivered volumes.

In the normal course of business, we occasionally purchase oil and gas properties for little or no up-front costs and instead commit to pay consideration contingent upon the successful development and operation of the properties. The contingent consideration generally includes amounts to be paid upon achieving specified operational milestones, such as first commercial production and again upon achieving designated cumulative sales volumes. At September 30, 2011, the aggregate amount of such contingent commitments related to unmet operational milestones was $7.9 million.

We maintain insurance to protect the Company and its subsidiaries against losses arising out of our oil and gas operations. Our insurance includes coverage for physical damage to our offshore properties, general (third party) liability, workers compensation and employers liability, seepage and pollution and other risks. Our insurance includes various limits and deductibles or retentions, which must be met prior to or in conjunction with recovery. Additionally, our insurance is subject to the terms, conditions and exclusions of such policies. For losses emanating from offshore operations, ATP has up to an aggregate of $2.4 billion of various insurance coverages with individual policy limits ranging from $1.0 million to over $500 million each. While we maintain insurance levels, deductibles and retentions that we believe are prudent and responsible, there is no assurance that such coverage will adequately protect us against liability from all potential consequences and damages.

In general, our current insurance policies cover physical damage to our oil and gas assets. The coverage is designed to repair or replace assets damaged by insurable events.

Our excess liability policies generally provide coverage (dependent on the asset) for bodily injury and property damage, including coverage for negative environmental effects such as seepage and pollution. This liability coverage would cover claims for bodily injury or death brought against the company by or on behalf of individuals who are not employees of the company. The liability limits scale to either our operating interest or the total insured interest including nonoperating partners.

Our energy insurance package includes coverage for operator’s extra expense, which provides coverage for control of well, re-drill and pollution arising from a covered event. We maintain a $150 million Oil Spill Financial Responsibility policy in order to provide a Certificate of Financial Responsibility to the BSEE under the requirements of the Oil Pollution Act of 1990. Additionally, as noted above, our excess liability policies provide coverage (dependent on the asset) for bodily injury and property damage, including coverage for negative environmental effects such as seepage and pollution. Legislation has been proposed but has not passed to increase the limit of the Oil Spill Financial Responsibility policy required for the certificate and there is no assurance that we will be able to obtain this insurance should that happen.

The occurrence of a significant accident or other event not fully covered by our insurance could have a materially adverse effect on our operations and financial condition. Our insurance does not protect us against all operational risks. We do not carry business interruption insurance at levels that would provide enough funds for us to continue operating without access to other funds. For some risks, we may not obtain insurance if we believe the cost of available insurance is excessive relative to the risks presented. Because third-party contractors and other service providers are used in our offshore operations, we may not realize the full benefit of worker’s compensation laws in dealing with their employees. In addition, pollution and environmental risks generally are not fully insurable.

On January 29, 2010, Bison Capital Corporation (“Bison”) filed suit against ATP in the United States District Court for the Southern district of New York alleging ATP owed fees totaling $102 million to Bison under a February 2004 agreement. The case was tried in January 2011. On March 8, 2011 the Court entered a judgment in favor of Bison for $1.65 million plus prejudgment interest and Bison’s reasonable attorney’s fees. ATP provided for this judgment in the financial statements as of December 31, 2010. Subsequently, Bison gave notice that it would appeal the judgment. By September 16, 2011, both Bison and ATP filed their respective briefs with the United States Court of Appeals for the Second Circuit. The case remains active pending resolution by the appellate court.

We are, in the ordinary course of business, involved in various other legal proceedings from time to time. Management does not believe that the outcome of these proceedings as of September 30, 2011, either individually or in the aggregate, will have a materially adverse effect on our financial condition, results of operations or cash flows.

Note 14 — Segment Information

The Company’s operations are focused in the Gulf of Mexico and the North Sea. Management reviews and evaluates separately the operations of its segments. The operations of the segments include liquid hydrocarbon and natural gas production and sales. Segment activity is as follows (in thousands):


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

September 30, 2011:
Revenues	$	165,698		$	4,437		$	170,135
Depreciation, depletion and amortization		75,083			2,632			77,715
Income (loss) from operations		47,333			(1,639	)		45,694
Interest income		68			—			68
Interest expense, net		77,356			—			77,356
Derivative income		86,277			416			86,693
Income tax expense (1)		—			44,136			44,136
Additions to oil and gas properties		137,668			37,673			175,341

September 30, 2010:
Revenues	$	98,415		$	3,706		$	102,121
Depreciation, depletion and amortization		58,898			3,607			62,505
Impairment of oil and gas properties		2,988			—			2,988
Income (loss) from operations		12,463			(2,115	)		10,348
Interest income		293			—			293
Interest expense, net		69,249			—			69,249
Derivative income (expense)		(14,918	)		2,253			(12,665	)
Income tax benefit (expense)		19,942			(70	)		19,872
Additions to oil and gas properties		79,575			38,864			118,439

For the Nine Months Ended –	Gulf of Mexico			North Sea			Total

September 30, 2011:
Revenues	$	494,949		$	14,569		$	509,518
Depreciation, depletion and amortization		221,570			9,783			231,353
Impairment of oil and gas properties		45,704			—			45,704
Income (loss) from operations		66,203			(3,926	)		62,277
Interest income		184			—			184
Interest expense, net		249,883			—			249,883
Derivative income (expense)		73,570			(1,221	)		72,349
Gain on debt extinguishment		1,091			—			1,091
Income tax expense (1)		—			38,784			38,784
Additions to oil and gas properties		240,892			159,135			400,027
Total assets		2,924,381			506,775			3,431,156

September 30, 2010:
Revenues	$	281,785		$	14,464		$	296,249
Depreciation, depletion and amortization		143,760			14,861			158,621
Impairment of oil and gas properties		15,078			—			15,078
Income (loss) from operations		18,205			(6,957	)		11,248
Interest income		591			—			591
Interest expense, net		146,113			—			146,113
Derivative income (expense)		17,984			(3,185	)		14,799
Loss on debt extinguishment		78,171			—			78,171
Income tax benefit		72,483			3,783			76,266
Additions to oil and gas properties		528,070			103,669			631,739
Total assets		2,979,553			366,557			3,346,110

(1)

Income taxes during interim periods are based on the estimated annual effective income tax rate plus any significant, unusual or infrequently occurring items that are recorded in the period the specific item occurs. The U.K. supplementary charge of corporation tax was increased from 20% to 32%, effective March 24, 2011, and Royal Assent was received on July 19, 2011. The U.K. rate increase has been reflected in the income tax provision for the three and nine months ended September 30, 2011, and all U.K. deferred tax assets and liabilities subject to the supplementary charge of corporation tax have been updated to reflect the 32% rate as of September 30, 2011.

Note 15 — Fair Value Measurements

Assets and Liabilities Measured at Fair Value on a Recurring Basis

The fair values of our derivative contracts are classified as Level 3 based on the significant unobservable inputs into our expected present value models. The following table sets forth a reconciliation of changes in the fair value of these financial assets (liabilities) during the nine months ended September 30, 2011 (in thousands):


	U.S. Gas Fixed- Price Physicals			U.S. Gas Calls			U.S. Oil Swaps⁽¹⁾			U.S. Oil Swaps⁽²⁾			U.S. Gas Price Collars			U.K. Gas Swaps			Total
Balance at beginning of period	$	289		$	—		$	(27,519	)	$	(12,027	)	$	658		$	(4,031	)	$	(42,630	)
Derivative gains (losses) included in earnings		3,663			1,767			60,012			8,391			170			(1,654	)		72,349
Sales		—			(2,133	)		(68,348	)		—			—			—			(70,481	)
Settlements and terminations		(2,090	)		—			14,643			3,655			(828	)		2,143			17,523


Balance at end of period	$	1,862		$	(366	)	$	(21,212	)	$	19		$	—		$	(3,542	)	$	(23,239	)


Changes in unrealized gain (loss) included in derivative income (expense) relating to derivatives still held at September 30, 2011	$	2,907		$	(366	)	$	(10,709	)	$	(684	)	$	—		$	(1,953	)	$	(10,805	)

(1)

In the second and third quarters of 2011, we entered into certain off-market oil swap derivative contracts which provide us with $73.3 million of cash advances from the counterparty (of which $4.8 million will be received in subsequent periods) and obligate us to pay market prices at the time of settlement.

(2)	During the three months ended September 30, 2011, we terminated these and other oil swaps but we retained the purchased-call options which had been matched to these oil swaps in order to allow us to reparticipate in price increases above certain levels.

The following table sets forth a reconciliation of changes in the fair value of these financial assets (liabilities) during the nine months ended September 30, 2010 (in thousands):


	Gas Fixed- Price Physicals			Gas Price Collars			Oil Swaps			Oil Swaps⁽¹⁾			Oil Puts			Subtotal U.S.
U.S.

Balance at beginning of period	$	(778	)	$	(339	)	$	(7,837	)	$	(14,910	)	$	2		$	(23,862	)
Derivative gains (losses) included in earnings		9,668			3,794			(400	)		5,022			(2	)		18,082
Settlements and terminations		(4,909	)		(1,457	)		1,550			4,169						(647	)


Balance at end of period	$	3,981		$	1,998		$	(6,687	)	$	(5,719	)	$	—		$	(6,427	)


Changes in unrealized gain (loss) included in derivative income (expense) relating to derivatives still held at September 30, 2010	$	4,401		$	2,686		$	(34	)	$	(2,370	)	$	(2	)	$	4,681

(1)	These swaps include those which were matched with call options to allow us to reparticipate in price increases above certain levels.


	Gas Fixed- Price Physicals			Financial Gas Swaps			Subtotal U.K.			Grand Total
U.K.

Balance at beginning of period	$	1,321		$	—		$	1,321		$	(22,541	)
Derivative gains (losses) included in earnings		(829	)		(2,454	)		(3,283	)		14,799
Settlements and terminations		(646	)		580			(66	)		(713	)


Balance at end of period	$	(154	)	$	(1,874	)	$	(2,028	)	$	(8,455	)


Changes in unrealized gain (loss) included in derivative income (expense) relating to derivatives still held at September 30, 2010	$	(120	)	$	(1,874	)	$	(1,994	)	$	2,687

Assets Measured at Fair Value on a Nonrecurring Basis

Oil and gas property is measured at fair value on a nonrecurring basis upon impairment and when acquired in a nonmonetary property exchange. During the nine months ended September 30, 2011 and 2010, we recorded impairment expense of $45.7 million and $15.1 million, respectively, related to proved and unproved Gulf of Mexico properties. The impairment charges reduce the oil and gas properties’ carrying values to their estimated fair values and are classified as Level 3. Fair value is calculated as the estimated discounted future net cash flows attributable to the assets. In the nine months ended September 30, 2010, we recorded gain on nonmonetary property exchange of $12.0 million related to proved Gulf of Mexico properties. The gain on nonmonetary property exchange reflects the difference between the carrying value of the property surrendered and the estimated fair value of the property received, classified as Level 3, and is calculated based on the estimated discounted future net cash flows attributable to that asset.

The Company’s primary assumptions in preparing the estimated discounted future net cash flows to be recovered from oil and gas properties are based on (i) proved reserves and risk-adjusted probable and possible reserves, (ii) commodity forward-curve prices and assumptions as to costs and expenses, and (iii) the estimated discount rate that would be used by market participants to determine the fair value of the assets.

Note 16 — Subsequent Events

Our evaluation has identified no matters which require disclosure as events subsequent to September 30, 2011.

ATP OIL & GAS CORPORATION AND SUBSIDIARIES

Item 2.Management’s Discussion and Analysis of Financial Condition and Results of Operations

Executive Overview

General

We seek to create value and reduce operating risks through the acquisition and subsequent development of properties in areas that typically have:

•

significant undeveloped reserves or nearby discoveries;

•

close proximity to developed markets for oil and natural gas;

•

existing infrastructure or the ability to install our own infrastructure of oil and natural gas pipelines and production/processing platforms;

•

opportunities to aggregate production and create operating efficiencies that capitalize upon our hub concept; and

•

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

In the Gulf of Mexico and the North Sea, our focus is on acquiring properties that are noncore or nonstrategic to their current owners for a variety of reasons. For example, larger oil companies from time to time adjust their capital spending or shift their focus to exploration prospects they believe offer greater reserve potential. Some projects may provide lower economic returns to a company due to the cost structure and focus of that company. Also, due to timing or budget constraints, a company may be unwilling or unable to develop a property before the expiration of the lease. With our cost structure and acquisition strategy, it is not unusual for us to acquire a property at a cost that is less than the development costs incurred by the previous owner. This strategy, coupled with our expertise in our areas of focus and our ability to develop projects, tends to make our oil and gas property acquisitions more financially attractive to us than to the seller. Given our strategy of acquiring properties that contain proved reserves, or where previous drilling by others indicates to us the presence of recoverable hydrocarbons, our operations typically are lower risk than exploration-focused Gulf of Mexico and North Sea operators.

Since we operate almost all of the properties in which we acquire a working interest, we are able to influence the plans and timing of a project’s development significantly. In addition, practically all of our properties have previously defined and targeted reservoirs, eliminating from our development plan the time necessary in typical exploration efforts to locate and determine the extent of oil and gas reservoirs. Without the exploration time constraint, we focus on developing projects in the shortest time possible between initial

significant investment and first revenue generated in order to maximize our rate of return. We may initiate new development projects by simultaneously obtaining the various required components such as the pipeline and the production platform or subsea well completion equipment.

Events that occurred in 2010 and regulations that were enacted in 2010 and 2011 have had a major impact on our operations and ability to move forward with development plans. On April 20, 2010, a semi-submersible drilling rig operating in the deepwater Outer Continental Shelf (“OCS”) in the Gulf of Mexico exploded, burned for two days and sank, resulting in an oil spill in Gulf of Mexico waters. In response to this crisis, the U.S. Department of the Interior (“DOI”), on May 6, 2010, instructed a predecessor of BSEE to stop issuing drilling permits for OCS wells and to suspend existing OCS drilling permits issued after April 20, 2010, until May 28, 2010, when a report on the accident was expected to be completed. On May 28, 2010, DOI issued a moratorium (“Moratorium I”), originally scheduled to last for six months, that essentially halted all drilling in water depths greater than 500 feet in the Gulf of Mexico. On June 7, 2010, a lawsuit was filed by several suppliers of services to Gulf of Mexico exploration and production companies challenging the legality of Moratorium I. This challenge was successful and on June 22, 2010, a Federal District Court issued a preliminary injunction preventing Moratorium I from taking effect. On July 8, 2010, the United States Court of Appeals for the Fifth Circuit denied the DOI’s motion to stay the preliminary injunction against the enforcement of Moratorium I. On July 12, 2010, in response to the Court’s actions, the DOI issued a second moratorium (“Moratorium II”) originally scheduled to end on November 30, 2010 that (i) specifically superseded Moratorium I, (ii) suspended all existing drilling operations in the Gulf of Mexico and other regions of the OCS utilizing a subsea blowout preventer (“BOP”) or a surface BOP on a floating facility, and (iii) suspended pending and future permits to drill wells involving the use of a subsurface BOP or a surface BOP on a floating facility. Several lawsuits challenging the legality of Moratorium II and, among other things, the BOEMRE handling of drilling permits and development plans were subsequently filed in different Federal District Courts, all of which have been consolidated into one case in a Federal District Court that is still pending. On October 12, 2010, the DOI lifted Moratorium II as to all deepwater drilling activity. While we had no ownership in the Macondo well and no direct costs associated with the Macondo well, we do focus on the deeper water of the Gulf of Mexico and have been and continue to be negatively impacted by the drilling moratoriums and related regulatory uncertainties.

The lifting of Moratorium II, however, did not remove all restrictions on offshore drilling. According to DOI’s order lifting Moratorium II, prior to receiving new permits to drill wells, OCS lessees and operators must first comply with an earlier notice to lessees and operators issued by the BOEMRE that requires additional testing, third-party verification, training for rig personnel, and governmental approvals to enhance well bore integrity and the operation of BOPs and other well control equipment used in OCS wells, (“NTL 2010-No.5”). NTL 2010-No. 5 was set aside by the Federal District Court on October 19, 2010, as having been improperly issued by BOEMRE. The DOI’s order lifting Moratorium II, however, also requires OCS lessees and operators to comply with BOEMRE Interim Final Rule entitled “Increased Safety Measures for Energy Development on the Outer Continental Shelf (the “Safety Interim Final Rule”) issued in September 2010, before recommencing deepwater operations. In general, the Safety Interim Final Rule incorporates the terms of NTL 2010-No.5 and establishes new safety requirements relating to the design of wells and testing of the integrity of well bores, the use of drilling fluids, and the functionality and testing of BOPs. Longer term, OCS lessees and operators will be required to comply with the BOEM’s new Final Workplace Safety Rule, also issued by BOEMRE in September 2010. The Final Workplace Safety Rule requires all OCS operators to implement all of the formerly voluntary practices in the American Petroleum Institute’s Recommended Practice 75, which includes the development and maintenance of a Safety and Environmental Management System, within one year after the date of the rule. In addition to these two rules, before a permit will be issued, each operator must demonstrate that it has enforceable obligations that ensure that containment resources are available promptly in the event of a deepwater blowout.

During the third quarter of 2011, we placed on production the Mississippi Canyon (“MC”) Block 941 #4 well in the deepwater Gulf of Mexico. The MC 941 #4 well is the third completed well at ATP’s Telemark Hub in 4,000 feet of water and was drilled to approximately 12,000 feet and cased during 2009. During the third quarter of 2011, we received all necessary permits and have begun drilling the fourth Telemark Hub well, MC

942 #2. We received permits to complete the previously drilled #2 and #4 wells at Green Canyon (“GC”) Block 300 (“Clipper”) in the deepwater Gulf of Mexico (3,450 feet of water). The GC Block 300 #2 well was sidetracked and encountered a gas reservoir between 15,590 and 15,721 feet total vertical depth. We reentered and sidetracked the GC Block 300 #4 well and encountered an oil reservoir between 15,430 and 15,500 total vertical depth. We are using the DiamondOcean Victory drilling vessel for well operations and have scheduled first production in the latter part of 2012 after installation of a pipeline and modification to the host platform.

During June 2011, we acquired interests in three deepwater licenses in the Mediterranean Sea off the coast of Israel. ATP will operate its licenses with working interests of 40%.

During the first nine months of 2011, we obtained significant additional financing. In June 2011, we closed an 8% convertible perpetual preferred stock offering that provided net proceeds of $123.3 million, net of discount, related option contract costs and issuance costs. In the second quarter 2011, we conveyed dollar-denominated overriding royalty interests (“Overrides”) and dollar-denominated overriding royalty interests in the form of net profits interests (“NPIs”) in the Gomez Hub and the Telemark Hub for aggregate net proceeds of $70.3 million. These Overrides and NPIs obligate us to deliver a percentage of the proceeds from the future sale of hydrocarbons in the specified proved properties until the purchaser recovers its original investment, plus an overall rate of return. In the second and third quarters of 2011, we entered into certain off-market oil swap derivative contracts which provide us with $73.3 million cash advances from the counterparty and obligate us to pay market prices at the time of settlement. During 2011 so far we have also obtained additional financing from our term loans totaling $150.4 million. The details of these transactions are discussed below inLiquidity and Capital Resources.

Risks and Uncertainties

Our estimates of proved oil and natural gas reserves and the estimated future net revenues from such reserves are based upon various assumptions, including assumptions relating to oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The estimation process requires significant assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir. Therefore, these estimates are inherently imprecise and the quality and reliability of this data can vary. Estimates of our oil and natural gas reserves and the costs and timing associated with developing these reserves are subject to change, and may differ materially from our estimates. A substantial portion of our total proved reserves are undeveloped and recognition of such reserves as proved requires our ability to demonstrate sufficient capital is available to fund their development. The size of our operations and our capital expenditures budget limit the number of properties that we can develop in any given year and we intend to continue to develop these reserves through the end of the year and beyond, but there is no assurance we will be successful. Development of these reserves may not yield the expected results, or the development may be delayed or the costs may exceed our estimates, any of which may materially affect our financial position, results of operations, cash flows, the quantity of proved reserves that we report, and our ability to meet the requirements of our financing obligations.

Oil and natural gas development and production in the Gulf of Mexico are regulated by BOEM and BSEE. Our near-term operating and development plans in the Gulf of Mexico, as well as our longer-term business plan, are dependent upon receiving regulatory approvals for deepwater drilling and other permits required by the BSEE. Delays in the permitting process directly impact the timing of our development and production activities, and can materially affect our financial position, results of operations, cash flows, and the quantity of proved reserves that we report.

Results of Operations

Three Months Ended September 30, 2011 Compared to Three Months Ended September 30, 2010

For the three months ended September 30, 2011 and 2010 we reported net loss attributable to common shareholders of $5.6 million and $58.4 million, or $0.11 and $1.15 per diluted share, respectively.

Oil and Gas Production Revenues

Revenues presented in the table and the discussion below represent revenues from sales of oil and natural gas production volumes. The table below also includes oil and natural gas production revenues from amortization of deferred revenue in the first quarter of 2010 related to the second quarter 2008 sale of a limited-term overriding royalty interest. The table below does not reflect any production volumes associated with those revenues.


	Three Months Ended September 30,				% Change from 2010 to 2011
	2011		2010		% Change from 2010 to 2011
Production:
Oil and condensate (MBbl)		1,540		1,127		37	%
Natural gas (MMcf)		4,107		4,900		(16	%)
Total (MBoe)		2,224		1,944		14	%
Gulf of Mexico (MBoe)		2,137		1,849
North Sea (MBoe)		87		95

Revenues from production (in thousands):
Oil and condensate	$	150,344	$	78,102		92	%
Amortization of deferred revenue		–		852

Total	$	150,344	$	78,954		90	%

Natural gas	$	19,791	$	23,167		(15	%)
Oil, condensate and natural gas	$	170,135	$	101,269		68	%
Amortization of deferred revenue		–		852

Total	$	170,135	$	102,121		67	%


Average realized sales price:
Oil and condensate (per Bbl)	$	97.63	$	69.30		41	%
Natural gas (per Mcf)		4.82		4.73		2	%
Gulf of Mexico (per Mcf)		4.31		4.50
North Sea (per Mcf)		8.35		6.46
Oil, condensate and natural gas (per Boe)		76.50		52.09		47	%
Gulf of Mexico (per Boe)		77.54		52.76
North Sea (per Boe)		50.99		39.01

Revenues from production increased in 2011 compared to 2010 due to a 14% increase in production and a 47% increase in average realized sales price. The production increase occurred in the Gulf of Mexico where we now have production from three wells at our Telemark Hub compared to only one well in the third quarter of 2010. The higher average realized sales price is due to increased commodity market prices.

Lease Operating

Lease operating expenses include costs incurred to operate and maintain wells. These costs include, among others, workover expenses, operator fees, processing fees and insurance. Lease operating expense was as follows (in thousands except per Boe amounts):


	Three Months Ended September 30,				% Change from 2010 to 2011
	2011		2010		% Change from 2010 to 2011
Recurring operating expenses	$	23,458	$	21,575		9	%
Workover expenses		4,249		5,918		(28	%)

Lease operating	$	27,707	$	27,493		(1	%)

Recurring operating expenses per Boe	$	10.55	$	11.10		(5	%)
Gulf of Mexico		10.45		10.92		(4	%)
North Sea		13.02		15.18		(14	%)

Lease operating expense for the three months ended September 30, 2011 were comparable to the same period in 2010. The workover expenses in the third quarter of 2011 were primarily due to well work and pipe line remediation at our Gomez Hub. The workover expenses during the third quarter of 2010 were primarily due to hydrate remediation and facilities inspection activities on our Gomez Hub. Per unit costs changed primarily due to the effect of changing production volumes on fixed costs.

General and Administrative

General and administrative expenses are overhead-related expenses, including employee compensation, legal and accounting fees, insurance, and investor relations expenses. General and administrative expense was as follows:


	Three Months Ended September 30,				% Change from 2010 to 2011
	2011		2010		% Change from 2010 to 2011
General and administrative (in thousands)	$	13,540	$	9,646		40	%
Per Boe		6.09		4.96		23	%

General and administrative expense in the third quarter of 2011 increased $3.9 million compared to the third quarter of 2010 primarily due to prospect generation costs and organization and startup costs of operations in Israel.

Depreciation, Depletion and Amortization

Depreciation, depletion and amortization (“DD&A”) expense was as follows:


	Three Months Ended September 30,				% Change from 2010 to 2011
	2011		2010		% Change from 2010 to 2011
DD&A (in thousands)	$	77,715	$	62,505		24	%
Per Boe		34.94		32.15	��	9	%
Gulf of Mexico		35.14		31.85		10	%
North Sea		30.25		37.98		(20	%)

DD&A expense for the three months ended September 30, 2011 increased $15.2 million compared to the same period during 2010 primarily due to the increase in production at our Telemark Hub. The per unit increase in the Gulf of Mexico is primarily a result of higher costs incurred on our new developments relative to some of our older properties. The per-unit costs for the North Sea decreased primarily due to the effect of production mix differences.

Loss on Abandonment

We recognized aggregate loss on abandonment during the third quarter of 2011 of $2.7 million. These amounts are the result of actual abandonment costs exceeding the previously accrued estimates, due to unforeseen circumstances that required additional work or the use of equipment more expensive than anticipated and unanticipated vendor price increases.

Gain on Exchange/Disposal of Properties

In the third quarter of 2010, we sold to a third party our 67% working interest in the deep operating rights of one of our Gulf of Mexico properties resulting in a $15.0 million gain.

Interest Expense, Net

Interest expense, net of amounts capitalized, increased to $77.4 million in the third quarter of 2011 compared to $69.2 million in the third quarter of 2010. Interest expense in the third quarter of 2011 and 2010 is net of capitalized interest of $9.1 million and $3.3 million, respectively (related to our Cheviot development in the U.K. in both periods). The increase in interest expense is primarily due to: (i) an approximate $330 million increase in our aggregate average balance outstanding of debt and other long term obligations in the third quarter of 2011 as compared to the same period in 2010 (see Note 6—Long-term Debt and Note 7—Other Long-term Obligations to the Consolidated Financial Statements) and (ii) higher noncash interest resulting from the amortization of additional debt-related discounts and issuance costs.

Derivative Income (Expense)

Derivative income (expense) is related to net gains and losses associated with our oil and gas price derivative contracts and is as follows (in thousands):


	Three Months Ended September 30,
	2011			2010
Gulf of Mexico
Realized gains	$	9,528		$	2,197
Unrealized gains (losses)		76,749			(17,115	)

		86,277			(14,918	)

North Sea
Realized losses		(34	)		(309	)
Unrealized gains		450			2,562

		416			2,253

Total
Realized gains		9,494			1,888
Unrealized gains (losses)		77,199			(14,553	)

	$	86,693		$	(12,665	)

Income Tax Benefit (Expense)

We recorded income tax expense of $44.1 million during the three months ended September 30, 2011 resulting in an overall effective income tax rate of 80%. In each jurisdiction, the rates were determined based on our expectations of net income or loss for the year, taking into consideration permanent differences. As of September 30, 2011, for U.S. and Netherlands tax provision purposes, we have provided valuation allowances

for the entirety of our net deferred tax assets based on our cumulative net losses coupled with the uncertainties surrounding our future earnings forecasts arising from the effects of permitting delays in the Gulf of Mexico. We recognized deferred tax assets only to the extent we expect to be able to offset deferred tax liabilities. In the comparable quarter of 2010 we recorded income tax benefit of $19.9 million resulting in an overall effective tax rate of 28%.

Income Attributable to the Redeemable Noncontrolling Interest

Income attributable to the redeemable noncontrolling interest represents the 49% Class A limited partner interest in ATP Infrastructure Partners, LP (“ATP-IP”).

Convertible Preferred Stock Dividends

Convertible preferred stock dividends represent declared dividends payable in cash or common stock, at the option of the Company, due for the three months ended September 30, 2011 and 2010. The outstanding shares of convertible preferred stock provide for cumulative preferred dividends at the annual rate of 8% of the $312.5 million aggregate liquidation value as of September 30, 2011 and $140.0 million as of September 30, 2010.

Nine Months Ended September 30, 2011 Compared to Nine Months Ended September 30, 2010

For the nine months ended September 30, 2011 and 2010 we reported net loss attributable to common shareholders of $182.0 million and $142.2 million, or $3.56 and $2.81 per diluted share, respectively.

Oil and Gas Production Revenues

Revenues presented in the table and the discussion below represent revenues from sales of oil and natural gas production volumes. The table below also includes oil and natural gas production revenues from amortization of deferred revenue in the first nine months of 2010 related to the second quarter 2008 sale of a limited-term overriding royalty interest. The table below does not reflect any production volumes associated with those revenues.


	Nine Months Ended September 30,				% Change from 2010 to 2011
	2011		2010		% Change from 2010 to 2011
Production:
Oil and condensate (MBbl)		4,601		2,933		57	%
Natural gas (MMcf)		12,651		14,665		(14	%)
Total (MBoe)		6,709		5,377		25	%
Gulf of Mexico (MBoe)		6,429		4,964
North Sea (MBoe)		280		413

Revenues from production (in thousands):
Oil and condensate	$	446,156	$	206,070		117	%
Amortization of deferred revenue		–		17,819

Total	$	446,156	$	223,889		99	%

Natural gas	$	63,362	$	70,843		(11	%)
Amortization of deferred revenue		–		1,517

Total	$	63,362	$	72,360		(12	%)

Oil, condensate and natural gas	$	509,518	$	276,913		84	%
Amortization of deferred revenue		–		19,336

Total	$	509,518	$	296,249		72	%


Average realized sales price:
Oil and condensate (per Bbl)	$	96.97	$	70.26		38	%
Natural gas (per Mcf)		5.01		4.83		4	%
Gulf of Mexico (per Mcf)		4.47		4.65
North Sea (per Mcf)		8.57		5.72
Oil, condensate and natural gas (per Boe)		75.94		51.50		47	%
Gulf of Mexico (per Boe)		76.99		52.87
North Sea (per Boe)		52.03		35.02

Revenues from production increased in 2011 compared to 2010 due to a 25% increase in production and a 47% increase in average realized sales price. The production increase occurred in the Gulf of Mexico where we now have production from three wells at our Telemark Hub. The higher average realized sales price is due to increased commodity market prices.

Lease Operating


	Nine Months Ended September 30,				% Change from 2010 to 2011
	2011		2010		% Change from 2010 to 2011
Recurring operating expenses	$	72,749	$	65,391		11	%
Workover expenses		29,005		24,032		21	%

Lease operating	$	101,754	$	89,423		14	%

Recurring operating expenses per Boe	$	10.84	$	12.18		(11	%)
Gulf of Mexico		10.68		12.24		(13	%)
North Sea		14.58		11.22		30	%

Lease operating expense for the nine months ended September 30, 2011 increased $12.3 million compared to the same period in 2010. The increase in recurring operating expense was primarily due to the new production from the Telemark Hub. The workover expenses during the nine months ended September 30, 2011 were primarily due to hydrate remediation activities, hull repair work and well work at our Telemark Hub and Gomez Hub properties. The workover expenses for the same period in 2010 were primarily due to hydrate remediation activities on our Canyon Express pipeline which enabled us to commence production at our Kings Peak well and to re-establish production from two wells at Aconcagua. Per unit costs changed primarily due to the effect of changing production volumes on fixed costs.

General and Administrative


	Nine Months Ended September 30,				% Change from 2010 to 2011
	2011		2010		% Change from 2010 to 2011
General and administrative (in thousands)	$	33,442	$	28,269		18	%
Per Boe		4.99		5.26		(5	%)

General and administrative expense in the first nine months of 2011 has increased compared to the first nine months of 2010 primarily due to prospect generation costs and organization and startup costs of operations in Israel. The per unit cost has decreased primarily due to the effect of increased production.

Depreciation, Depletion and Amortization

Depreciation, depletion and amortization (“DD&A”) expense was as follows:


	Nine Months Ended September 30,				% Change from 2010 to 2011
	2011		2010		% Change from 2010 to 2011
DD&A (in thousands)	$	231,353	$	158,621		46	%
Per Boe		34.48		29.50		17	%
Gulf of Mexico		34.46		28.96		19	%
North Sea		34.96		35.99		3	%

DD&A expense for the nine months ended September 30, 2011 increased $73 million compared to the same period during 2010 primarily due to the increase in production at our Telemark Hub. The per unit

increase in the Gulf of Mexico is primarily a result of higher costs incurred on our new developments relative to some of our older properties and the recognition of straight-line depreciation on ourATP Titan production platform which was placed into service at the beginning of the second quarter of 2010. The per unit costs for the North Sea decreased primarily due to the effect of production mix differences.

Impairment of Oil and Gas Properties

During the first nine months of 2011 and 2010, we recognized impairment of proved Gulf of Mexico oil and gas properties of $45.7 million and $15.1 million ($10.6 million related to proved properties and $4.5 million related to unproved properties), respectively. The impairment in the first nine months of 2011 was primarily related to two properties acquired in 2005 and 1999 for which remediation is not cost-effective in the current cost environment. The impairment recognized in the first nine months of 2010 was associated with the relinquishment of leases on certain proved properties and the write-off of unproved leases which were approaching their expiration dates.

Drilling Interruption Costs

Drilling interruption costs were $19.7 million and $8.7 million in the first nine months of 2011 and 2010, respectively. They consist of stand-by costs for drilling operations at our Telemark and Gomez Hubs resulting from the deepwater drilling moratoriums and subsequent drilling permit delays caused by the April 2010 Macondo incident in the Gulf of Mexico and the moratoriums.

Loss on Abandonment

We recognized aggregate loss on abandonment during the first nine months of 2011 and 2010 of $4.1 million and $0.2 million, respectively. These amounts are the result of actual abandonment costs exceeding the previously accrued estimates, due to unforeseen circumstances that required additional work or the use of equipment more expensive than anticipated and unanticipated vendor price increases.

Gain on Exchange/Disposal of Properties

In the third quarter of 2010, we sold to a third party our 67% working interest in the deep operating rights of one of our Gulf of Mexico properties resulting in a $15.0 million gain.

During January 2010, we consummated a nonmonetary exchange of our 10% nonoperated working interest in MC Block 800, for an incremental 50% working interest in MC Block 754, both proved properties. The consolidated financial statements reflect the incremental interest acquired in MC Block 754 at fair value and removal of the carrying costs of MC Block 800, resulting in recognition of a $12.0 million gain.

Interest Expense, Net

Interest expense, net of amounts capitalized, increased to $249.9 million in 2011 compared to $146.1 million in 2010. Interest expense in 2011 and 2010 is net of capitalized interest of $20.6 million and $49.6 million, respectively ($40.4 related to our Telemark development in 2010 and $20.6 million and $9.2 million related to our Cheviot development in the U.K. in 2011 and 2010 respectively). Our weighted average borrowing rate on our combined debt and long-term obligations was 14.5% in 2011 compared to 13.4% for the same period in 2010. The increase in interest expense and our weighted average borrowing rate is primarily due to: (i) an approximate $540 million increase in our aggregate average balance outstanding of debt and other long term obligations in the nine months ended September 30, 2011 at a higher cost, on average, as compared to the comparable period in 2010 (see Note 6—Long-term Debt and Note 7—Other Long-term Obligations to the Consolidated Financial Statements); (ii) higher noncash interest resulting from the amortization of additional debt-related discounts and issuance costs; and (iii) an increase in interest expense on one of our dollar denominated Overrides due to a reduction in the estimated remaining repayment period of the Override as a result of greater than forecasted production from the underlying properties at higher than forecasted prices. A reduction in the expected time required to pay the obligation results in an increase in the investor’s internal rate of return and requires a corresponding change in the estimated amortization and associated interest expense we record on the obligation.

Derivative Income (Expense)

Derivative income (expense) is related to net gains and losses associated with our oil and gas price derivative contracts and is as follows (in thousands):


	Nine Months Ended September 30,
	2011			2010
Gulf of Mexico
Realized gain (losses)	$	(5,435	)	$	374
Unrealized gains		79,004			17,610

		73,569			17,984

North Sea
Realized gains (losses)		(1,626	)		65
Unrealized gains (losses)		406			(3,250	)

		(1,220	)		(3,185	)

Total
Realized gains (losses)		(7,061	)		439
Unrealized gains		79,410			14,360

	$	72,349		$	14,799

Gain (Loss) on Debt Extinguishment

Gain on debt extinguishment of $1.1 million in the nine months ended September 30, 2011 was related to an NPI transaction in the Telemark Hub for $40.0 million. The third party purchaser acquired an existing vendor NPI from us for $19.7 million, thereby extinguishing the existing NPI liability of $20.8 million, and contributed an additional $20.3 million toward the development of the Telemark Hub in exchange for a larger percentage of the net profits from production at the Telemark Hub that will continue until the purchaser recovers $40.0 million, plus an overall rate of return.

Loss on debt extinguishment was $78.2 million in the nine months ended September 30, 2010 was due to the second quarter refinancing of our previously outstanding term loans in which we charged to expense the remaining unamortized deferred financing costs, debt discount related to the retired debt and repayment premiums.

Income Tax Benefit (Expense)

We recorded income tax expense of $38.8 million during the nine months ended September 30, 2011 resulting in an overall effective tax rate of (34)%. In each jurisdiction, the rates were determined based on our expectations of net income or loss for the year, taking into consideration permanent differences. As of September 30, 2011, for U.S. and Netherlands tax provision purposes, we have provided valuation allowances for the entirety of our net deferred tax assets based on our cumulative net losses coupled with the uncertainties surrounding our future earnings forecasts arising from the effects of permitting delays in the Gulf of Mexico. We recognized deferred tax assets only to the extent we expect to be able to offset deferred tax liabilities. In the comparable period of 2010 we recorded income tax benefit of $76.3 million resulting in an overall effective tax rate of 39%.

Income Attributable to the Redeemable Noncontrolling Interest

Income attributable to the redeemable noncontrolling interest represents the 49% Class A limited partner interest in ATP-IP.

Convertible Preferred Stock Dividends

Convertible preferred stock dividends represent declared dividends payable in cash or common stock, at the option of the Company, due for the nine months ended September 30, 2011 and 2010. The outstanding shares of convertible preferred stock provide for cumulative preferred dividends at the annual rate of 8% of the $312.5 million aggregate liquidation value as of September 30, 2011 and $140.0 million as of September 30, 2010.

Liquidity and Capital Resources

Historically, we have funded our acquisition and development activities through a combination of bank borrowings, proceeds from equity offerings, cash from operations, the sale or conveyance of interests in selected properties and vendor financings. Our ongoing cash requirements consist primarily of servicing our debt and other obligations and funding development of our oil and gas reserves. So far in 2011, we have obtained additional financing from term loans and other sources as discussed below, placed on production the third well at our Telemark Hub and have re-entered and completed drilling the fourth Telemark Hub well, the MC Block 942 #2. We expect these new wells will generate sufficient cash flows to fund subsequent development projects and service our long-term debt and other obligations. We believe we can continue to meet our existing obligations for at least the next twelve months based on forecasted production levels and the continuation of commodity sales prices and operating costs near current levels. In the event we do not achieve the projected production and cash flow increases, we will attempt to fund any short-term liquidity needs through more of these type transactions; however, there is no assurance that we will be able to repeat these types of transactions in the future if they are required to meet our short-term liquidity needs. Our longer-term liquidity is also dependent on the prevailing prices for oil and natural gas which have historically been very volatile. To mitigate future price volatility, we may continue to hedge the sales price of a portion of our future production.

The size of our operations and our capital expenditures budget limit the number of properties that we can develop in any given year and a substantial portion of our current production is concentrated among relatively few wells located offshore in the Gulf of Mexico and in the North Sea, which are characterized by rapid production declines. As a result, we are particularly vulnerable to a near-term severe impact resulting from unanticipated complications in the development of, or production from, any single material well or infrastructure installation, including lack of sufficient capital, delays in receiving necessary drilling and operating permits, increased regulation, reduced access to equipment and services, mechanical or operational failures, and bad weather. Any unanticipated significant disruption to, or decline in, our current production levels or negative changes in current commodity prices or operating cost levels could have a material adverse effect on our financial position, results of operations and cash flows and our ability to meet our commitments as they come due. We have historically obtained various other sources of funding to supplement our cash flow from operations and we will continue to pursue them in the future, however, there is no assurance that these alternative sources will be available should these risks and uncertainties materialize.

During February 2011, we entered into Incremental Loan Assumption Agreement and Amendment No. 1, relating to our First Lien Credit Agreement, dated as of June 18, 2010 to, among other things, decrease the interest rate on the entire balance outstanding from 11% to 9%. Additional borrowings were $60.0 million ($58.0 million, net of transaction costs and discount).

During April and June 2011, we conveyed for an aggregate of $50.0 million, two dollar-denominated Overrides in the MC711 Hub. These Overrides obligate us to deliver a percentage of the proceeds from the future sale of hydrocarbons in the specified proved properties until the purchaser achieves a specified return.

Also during April 2011, we closed an NPI transaction in the Telemark Hub for $40.0 million. The purchaser acquired an existing vendor NPI for $19.7 million, thereby extinguishing the existing NPI liability of $20.8 million, and contributed an additional $20.3 million toward the development of the Telemark Hub in exchange for a larger percentage of the net profits from production at the Telemark Hub that will continue until the purchaser recovers an overall specified rate of return.

We have conveyed to certain vendors and financial parties dollar-denominated net profits interests and overriding royalty interests in our Telemark Hub, Gomez Hub and Clipper oil and gas properties in exchange for development services, equipment and cash. We have also negotiated with certain other vendors involved in the development of the Telemark Hub to partially defer payments for periods up to a year. These net profits interests and deferrals allow us to match our development cost cash flows with those from production. During the nine months ended September 30, 2011, we paid $224.1 million of principal and interest related to our other long-term obligations, which is dramatically increased from the comparable period in 2010 due to increased production and higher oil prices. SeeOther Long-term Obligations discussion below.

In June 2011, we issued 1.7 million shares of 8% convertible perpetual preferred stock (“Series B Preferred Stock”) and received net proceeds of $123.3 million ($90 per share before underwriters’ discounts and commissions, option contract costs (discussed below) and offering expenses). In conjunction with issuance of the Series B Preferred Stock, we purchased for $26.5 million capped-call options (“Options”) to cover all 14.1 million shares of common stock issuable upon conversion of the Series B Preferred Stock and the preferred stock we issued in 2009. The Options allow us to prevent dilution due to common stock issuance upon preferred stock conversion up to a price per common share of $27.50. The shares of common stock acquirable under the Options are indexed to our common stock price at the time of exercise and the Options can only be settled in common stock. As a result, the purchase price of the Options is recorded as a component of additional paid-in capital within Shareholders’ Equity in the accompanying Consolidated Financial Statements.

The Series B Preferred Stock has terms and features which are substantially identical to the convertible preferred stock we issued in 2009 (collectively, the “Preferred Stock”). Each share of Preferred Stock is perpetual, has no voting rights, has a liquidation preference of $100, pays cumulative dividends at an annual rate of 8% and is convertible at any time, at the option of the holder, into 4.5045 shares of common stock. After September 30, 2014, we have the option to force conversion to common stock provided that the prevailing common stock market price exceeds the conversion price by 150% on average for a stipulated period of time.

At September 30, 2011, a portion of the Series B Preferred Stock is classified as temporary equity because, in the event of certain fundamental changes, as defined in the statement of resolutions, the Company could be required to issue in the aggregate more shares of common stock pursuant to the conversion ratio most favorable to the holders than currently are authorized and unissued (the “Common Share Shortfall”). The value of the temporary equity is deemed to be the number of shares of Preferred Stock that would account for such Common Share Shortfall times the $86.83 fair value per share (net of issuance costs of $3.17 per share). This amount will be revalued in future reporting periods as the Common Share Shortfall changes, and at such time as we have sufficient authorized and unissued common shares to satisfy the most favorable conversion obligation possible under the statement of resolutions, this amount will be reclassified to permanent equity.

During March and September 2011, we entered into First and Second Amendments to Term Loan Agreement and Limited Waivers, relating to our Term Loan Facility–ATP Titan assets to, among other things, modify the conditions precedent for incremental borrowings drawn under the facility. Additional borrowings were $100.0 million ($89.1 million, net of transactions costs and discount).

In the second and third quarters of 2011, we entered into certain off-market oil swap derivative contracts which provide us with $73.3 million cash advances from the counterparty and obligate us to pay market prices at the time of settlement. In the third quarter of 2011, we also terminated certain oil swaps and received $10.7 million proceeds.

In the remainder of 2011, we anticipate incurring $70 million to $120 million in total capital expenditures excluding capitalized interest, of which $35 million to $75 million will be contributed by vendors through existing NPI or deferral programs. As operator of most of our projects under development, we have the ability to control the timing and extent of most of our capital expenditures should future market conditions warrant. We plan to finance anticipated expenses, debt service, development and abandonment requirements for the remainder of 2011 with cash on hand and funds generated by operating activities and, potentially, proceeds from other capital market transactions, other financings and possible sales of assets.

Cash Flows


	Nine Months Ended September 30,
	2011			2010
Cash provided by (used in) (in thousands):
Operating activities	$	128,629		$	2,389
Investing activities		(293,586	)		(498,422	)
Financing activities		181,732			593,800

Cash provided by operating activities during the first nine months of 2011 and 2010 was $128.6 million and $2.4 million, respectively. Cash flow from operating activities has increased primarily due to increased oil and gas revenues related to increased production and commodity prices, partially offset by increased interest and operating costs and decreases in working capital.

Cash used in investing activities was $293.6 million and $498.4 million during the first nine months of 2011 and 2010, respectively. During the first nine months of 2011, cash expended in the Gulf of Mexico and North Sea/East Mediterranean for additions to oil and gas properties was approximately $150.6 million and $161.2 million, respectively. During the first nine months of 2010, cash expended in the Gulf of Mexico and North Sea for additions to oil and gas properties was approximately $461.5 million and $37.1 million, respectively. During the first nine months of 2011, we also transferred $17.6 million of cash from restricted accounts.

Cash provided by financing activities was $181.7 million and $593.8 million during the first nine months of 2011 and 2010, respectively. The amount in 2011 is primarily related to $220.7 million of proceeds from term loans and other long-term obligations, $123.3 million net proceeds from our Series B preferred stock offering and $63.6 million, net from derivative contracts, partially offset by $179.6 million payments of other long-term liabilities, short-term notes and term loans. The amount in the first nine months of 2010 is primarily related to $336.4 million net proceeds from a debt refinancing, $143.3 million proceeds from a new term loan facility, $46.0 million net proceeds from our prior revolving credit facility and $170.6 million proceeds net of costs from sales of limited-term overriding royalty interests and net profit interests, partially offset by principal payments of Term Loans and other long-term obligations.

We had working capital deficits of approximately $260.2 million and $106.1 million as of September 30, 2011 and December 31, 2010, respectively. To preserve our development momentum in the negative working capital environment that we have experienced throughout 2011, we have increased our First Lien Term Loans, issued 8% convertible perpetual preferred stock, granted net profits interests (NPI’s) and dollar-denominated overriding royalty interests (ORRI’s) to certain of our vendors, and we have entered into prepaid swaps against our future production that provided cash proceeds to us at closing. We have negotiated with the constructor of the hull of the Octabuoy in China to defer the majority of our payments until the hull is ready to be moved to the North Sea, currently scheduled to be mid- to late-2012. A similar arrangement is in place for the topsides for the Octabuoy being constructed by the same company in China.

produce our reserves, and a number of other factors, some of which are beyond our control. Our inability to increase near-term production levels and generate sufficient liquidity through the actions noted above could result in our inability to meet our obligations as they come due which would have a material adverse affect on us. In the event we do not achieve the projected production and cash flow increases, we will attempt to fund any short-term liquidity needs through more of these type transactions; however, there is no assurance that we will be able to repeat these types of transactions in the future if they are required to meet any short-term liquidity needs.

Long-term Debt

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


	September 30, 2011			December 31, 2010
First lien term loans, net of unamortized discount of $2,663 and $2,644, respectively,	$	205,541		$	146,607
Senior second lien notes, net of unamortized discount of $5,021 and $6,071, respectively,		1,494,979			1,493,929
Term loan facility –ATP Titanassets, net of unamortized discount of $17,460 and $10,760, respectively,		315,173			238,873

Total debt		2,015,693			1,879,409
Less current maturities		(31,989	)		(21,625	)

Total long-term debt	$	1,983,704		$	1,857,784

stock of material subsidiaries (limited in the case of the Company’s non-U.S. subsidiaries to not more than 65% of the capital stock) and certain infrastructure assets, a portion of which has since been released in connection with the ATP Titan LLC financing discussed below. In February 2011, we entered into Incremental Loan Assumption Agreement and Amendment No. 1, relating to our First Lien Credit Agreement, dated as of June 18, 2010 to, among other things, decrease the interest rate on the entire balance outstanding from 11% to 9%. Additional borrowings were $60.0 million ($58.0 million, net of transaction costs and discount). Quarterly Principal payments are required equal to¹/2% of remaining principal balance until June 18, 2014 and the remaining principal balance is due October 15, 2014.

The Notes and Credit Facility contain certain negative covenants which place limits on the Company’s ability to, among other things:

•

incur additional indebtedness;

•

pay dividends on the Company’s capital stock or purchase, repurchase, redeem, defease or retire the Company’s capital stock or subordinated indebtedness;

•

make investments outside of our normal course of business;

•

incur liens;

•

create any consensual restriction on the ability of the Company’s restricted subsidiaries to pay dividends, make loans or transfer property to the Company;

•

engage in transactions with affiliates;

•

sell assets; and

•

consolidate, merge or transfer assets.

The effective annual interest rate and fair value of our long-term debt was 11.9% and $1.6 billion, respectively, at September 30, 2011.

Other Long-term Obligations

Other long-term obligations consisted of the following (in thousands):


	September 30, 2011			December 31, 2010
Net profits interests	$	350,073		$	331,776
Dollar-denominated overriding royalty interests		37,944			52,825
Gomez pipeline obligation		73,189			73,868
Vendor deferrals – Gulf of Mexico		10,029			7,096
Vendor deferrals – North Sea		93,202			90,874
Other		2,582			2,582

Total		567,019			559,021
Less current maturities		(153,004	)		(86,521	)

Other long-term obligations	$	414,015		$	472,500

Net Profits Interests

Dollar-denominated Overriding Royalty Interests

production from a property during a payment period, no payment would be required. The percentage of property revenues available to satisfy these obligations is dependent upon certain conditions specified in the agreement. Upon recovery of the agreed rate of return, the Overrides terminate and our interest increases accordingly. Because of the explicit rate of return, dollar-denomination and limited payment terms of the Overrides, they are reflected in the accompanying financial statements as financing obligations. As such, the reserves and production revenues are retained by the Company. Related interest expense is presented net of amounts capitalized on the Consolidated Statements of Operations. We expect the Overrides to be repaid over approximately the next 18 months based on anticipated production and commodity prices.

Gomez Pipeline Obligation

In 2009, we sold to a third party for net proceeds of $74.5 million the oil and natural gas pipelines that service the Gomez Hub. In conjunction with the sale, we entered into agreements with the purchaser to transport our oil and natural gas production for the remaining production life of our fields serviced by theATP Innovator production platform for a per-unit fee that is subject to a minimum monthly payment through December 31, 2016. Such minimum fees, if applicable, can be recovered by ATP in future periods within the same calendar year whenever fees owed during a month exceed the minimum due. We remain the operator of the pipeline and are responsible for all of the related operating costs. As a result of the retained asset retirement obligation and the purchaser’s option to convey the pipeline back to us at the end of the life of the fields in the Gomez Hub, the transaction has been accounted for as a financing obligation equal to the net proceeds received. This obligation is being amortized based on the estimated proved reserve life of the Gomez Hub properties using the effective interest method with related interest expense presented net of amounts capitalized on the Consolidated Statements of Operations. All payments made in excess of the minimum fee in future periods will be reflected as interest expense of the financing obligation.

Vendor Deferrals

The weighted average effective interest rate on our other long-term obligations set forth above was 19.2% at September 30, 2011.

Contractual Obligations

The following table summarizes certain contractual obligations at September 30, 2011 (in thousands):


	Total		Less than 1 year		1 – 3 years		3 – 5 years		More than 5 years
First lien term loans	$	208,204	$	2,077	$	4,092	$	202,035	$	–
Interest on first lien term loans (1)		61,526		18,949		37,230		5,347		–
Senior second lien notes		1,500,000		–		–		1,500,000		–
Interest on senior second lien notes (1)		638,281		178,125		356,250		103,906		–
Term loan facility –ATP Titan assets		332,633		30,900		69,309		70,000		162,424
Interest on term loan facility –ATP Titan assets (1)		119,666		27,491		46,116		33,883		12,176
Other long-term obligations		318,101		181,769		110,499		20,000		5,833
Other trade commitments		13,818		2,058		11,760		–		–
Noncancelable operating leases		2,099		1,310		709		80		–

Total contractual obligations	$	3,194,328	$	442,679	$	635,965	$	1,935,251	$	180,433

(1)	Interest is based on rates and principal repayment requirements in effect at September 30, 2011.

Excluded from the table above are the following:

•

Net profits interests payable and overriding royalty interests payable of $350.1 million and $37.9 million, respectively, as of September 30, 2011 that are payable only from the future cash flows of specified properties. The ultimate amount and timing of the payments will depend on production from the properties and future commodity prices and operating costs. We expect approximately 80% of the NPIs and all of such overriding royalty interests to be repaid over approximately the next 18 months based on anticipated production, commodity prices and operating costs.

•

Dividends on our 8% convertible perpetual preferred stock, which are approximately $25.0 million per year. These dividends are payable in cash or common stock at the Company’s option, although covenants with our creditors may prevent us from paying cash in the future.

•

Asset retirement obligations ($61.3 million current and $95.5 million long-term) at September 30, 2011. The ultimate settlement of such obligations is uncertain because they are subject to, among other things, federal, state, and local regulation, economic and operational factors.

•

Contingent consideration of $7.9 million to be paid by us upon achieving specified operational milestones because the ultimate amount and timing of the payments will depend on production from the specified properties and future commodity prices.

Commitments and Contingencies

Management is periodically faced with uncertainties, the outcomes of which are not within its control and will not be known for some time. We are involved in actions from time to time, which if determined adversely, could have a material adverse impact on our financial position, results of operations and cash flows. Management, with the assistance of counsel makes estimates, if determinable, of our 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. See Note 13, “Commitments and Contingencies” to Consolidated Financial Statements in Item 1 for additional discussion.

Accounting Pronouncements

See the discussion in Note 2, “Recent Accounting Pronouncements” to Consolidated Financial Statements in Item 1.

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 of America. 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. Critical accounting policies have not changed materially from those disclosed on our 2010 Annual Report on Form 10-K .

Item 3. Quantitative and Qualitative Disclosures about Market Risks

Interest Rate Risk

We are exposed to changes in interest rates on ourATP Titan assets - Term Loan Facility. Otherwise, we have no exposure to changes in interest rates because the interest rates on our other long-term debt instruments are fixed.

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 value of the local currency arising from the process of re-measuring the local functional currency in U.S. dollars.

Commodity Price Risk

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

In addition to the strategies discussed above, we have sold certain natural gas call options in exchange for a premium from the counterparty. At the time of settlement of a call option, if the market price exceeds the fixed price of the call option, the Company pays the counterparty such excess. If the market price settles below the fixed price of the call option, no payment is due from either party. Cash settlements of our derivative instruments are classified as operating cash flows unless the derivative contains a significant financing element at contract inception, in which case these cash settlements are classified as financing cash flows in the accompanying consolidated statement of cash flows. See Note 12, “Derivative Instruments and Risk Management Activities,” to Consolidated Financial Statements. We do not hold or issue significant derivative instruments for speculative purposes.

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

Our chief executive officer and chief financial officer have reviewed and evaluated the effectiveness of our disclosure controls and procedures, as defined in Exchange Act Rules 13a-15(e) and 15d-15(e), as of September 30, 2011 (the “Evaluation Date”). Based on this evaluation, the chief executive officer and chief financial officer have concluded that ATP’s disclosure controls and procedures were effective as of the Evaluation Date to ensure that information that is required to be disclosed by ATP in the reports it files or submits under the Exchange Act is (i) recorded, processed, summarized and reported, within the time periods

specified in the Securities and Exchange Commission’s rules and forms and (ii) accumulated and communicated to ATP’s management, including our chief executive officer and chief financial officer, as appropriate to allow timely decisions regarding required disclosure.

Changes in Internal Control Over Financial Reporting

During the nine months ended September 30, 2011, we have made no change to our internal controls over financial reporting that has materially affected, or is reasonably likely to materially affect, our internal controls over financial reporting.

Forward-looking Statements and Associated Risks

This Quarterly Report contains projections and other forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934. These projections and statements reflect the Company’s current views with respect to future events and financial performance. No assurances can be given, however, that these events will occur or that these projections will be achieved and actual results could differ materially from those projected as a result of certain factors. A discussion of these factors is included in the Company’s 2010 Annual Report on Form 10-K.

PART II.OTHER INFORMATION

Item 1.

Legal Proceedings

On January 29, 2010, Bison Capital Corporation (“Bison”) filed suit against ATP in the United States District Court for the Southern district of New York alleging ATP owed fees totaling $102 million to Bison under a February 2004 agreement. The case was tried in January 2011. On March 8, 2011 the Court entered a judgment in favor of Bison for $1.65 million plus prejudgment interest and Bison’s reasonable attorney’s fees. ATP provided for this judgment in the financial statements as of December 31, 2010. Either party could file a notice of appeal within 30 days of the judgment. Subsequently, Bison gave notice that it would appeal the judgment. By September 16, 2011, both Bison and ATP filed their respective briefs with the United States Court of Appeals for the Second Circuit. The case remains active pending resolution by the appellate court.

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

Item 6.

Exhibits



3.1		Amended and Restated Certificate of Formation, incorporated by reference to Exhibit 3.1 of the Current Report on Form 8-K of ATP Oil & Gas Corporation (“ATP”) filed June 10, 2010.

3.2		Statement of Resolutions Establishing the 8.00% Convertible Perpetual Preferred Stock of ATP Oil & Gas Corporation, incorporated by reference to Exhibit 4.4 of Registration Statement No. 333-162574 on Form S-3 of ATP filed October 19, 2009.

3.3		Statement of Resolutions Establishing the 8.00% Convertible Perpetual Preferred Stock, Series B of ATP Oil & Gas Corporation, incorporated by reference to Exhibit 3.1 of ATP’s Current Report on Form 8-K filed June 21, 2011.

3.4		Third Amended and Restated Bylaws of ATP Oil & Gas Corporation, incorporated by reference to Exhibit 3.1 of ATP’s Current Report on Form 8-K filed December 15, 2009.

4.1		Rights Agreement dated October 11, 2005 between ATP 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.

4.2		Form of Stock Certificate for 8.00% Convertible Perpetual Preferred Stock, incorporated by reference to Exhibit 4.1 of ATP’s Form 8-K dated September 29, 2009.

4.3		Form of Stock Certificate for 8.00% Convertible Perpetual Preferred Stock, Series B, incorporated by reference to Exhibit 4.1 of ATP’s Current Report on Form 8-K filed June 21, 2011.

4.4		Indenture dated as of April 23, 2010 between the Company and The Bank of New York Mellon Trust Company, N.A., as trustee (“Trustee”), incorporated by reference to Exhibit 4.1 to ATP’s Current Report on Form 8-K dated April 29, 2010.

4.5		Registration Rights Agreement dated as of April 23, 2010 between the Company and J.P. Morgan Securities Inc., incorporated by reference to Exhibit 10.2 to ATP’s Current Report on Form 8-K dated April 29, 2010.

4.6		Form of Nonqualified Stock Option Agreement, incorporated by reference to Exhibit 4.6 of Registration Statement No. 333-171263 on Form S-8 of ATP filed December 17, 2010.

4.7		Form of Restricted Stock Award Agreement (to be used in connection with awards to directors of ATP), incorporated by reference to Exhibit 4.7 of Registration Statement No. 333-171263 on Form S-8 of ATP filed December 17, 2010.



4.8		Form of Restricted Stock Award Agreement (to be used in connection with awards to executive officers of ATP), incorporated by reference to Exhibit 4.8 of Registration Statement No. 333-171263 on Form S-8 of ATP filed December 17, 2010.

10.1		Credit Agreement dated as of June 18, 2010 among ATP Oil & Gas Corporation, Credit Suisse AG and the lenders party thereto, incorporated by reference to Exhibit 10.1 of ATP’s Current Report on Form 8-K dated June 18, 2010.

10.2		Term Loan Agreement, dated as of September 24, 2010 among Titan LLC, as the Borrower, CLMG Corp., as Agent, and the Lenders party thereto incorporated by reference to Exhibit 99.1 to ATP’s Current Report on Form 8-K dated September 24, 2010.

10.3		ATP Oil & Gas Corporation 2010 Stock Plan incorporated by reference to Appendix A to ATP’s Schedule 14A dated April 29, 2010.

10.4		Intercreditor Agreement dated as of April 23, 2010 among the Company, the Trustee and Credit Suisse AG, incorporated by reference to Exhibit 10.3 to ATP’s Current Report on Form 8-K dated April 29, 2010.

10.5		Sale and Purchase Agreement between ATP Oil & Gas (UK) Limited and EDF Production UK Ltd., as amended and restated on October 23, 2008, incorporated by reference to Exhibit 10.1 to ATP’s Report on Form 10-Q for the quarter ended September 30, 2008.

10.6		Employment Agreement between ATP and Leland E. Tate, dated December 30, 2010, incorporated by reference to Exhibit 10.5 to ATP’s Form 8-K dated December 30, 2010.

10.7		Employment Agreement between ATP and Albert L. Reese, Jr., dated December 30, 2010, incorporated by reference to Exhibit 10.4 to ATP’s Form 8-K dated December 30, 2010.

10.8		Employment Agreement between ATP and Keith R. Godwin, dated December 30, 2010, incorporated by reference to Exhibit 10.2 to ATP’s Form 8-K dated December 30, 2010.

10.9		Employment Agreement between ATP and T. Paul Bulmahn, dated December 30, 2010, incorporated by reference to Exhibit 10.1 to ATP’s Form 8-K dated December 30, 2010.

10.10		Employment Agreement between ATP and George R. Morris, dated December 30, 2010, incorporated by reference to Exhibit 10.3 to ATP’s Form 8-K dated December 30, 2010.

10.11		All Employee Bonus Policy, incorporated by reference to exhibit 10.16 to ATP’s Annual Report on Form 10-K for the year ended December 31, 2008.

10.12		Discretionary Bonus Policy, incorporated by reference to exhibit 10.17 to ATP’s Annual Report on Form 10-K for the year ended December 31, 2008.

10.13		Incremental Loan Assumption Agreement and Amendment No. 1 to Credit Agreement among ATP, the lenders party thereto and Credit Suisse AG, incorporated by reference to Exhibit 10.1 of ATP’s Form 8-K dated February 19, 2011.

10.14		Amended and restated letter agreement dated June 15, 2011 between the Company and Credit Suisse International, c/o Credit Suisse Securities USA LLC relating to the capped call transactions, incorporated by reference to Exhibit 10.1 of ATP’s Current Report on Form 8-K filed June 21, 2011.

21.1		Subsidiaries of ATP, incorporated by reference to Exhibit 21.1 to ATP’s Report on Form 10-Q for the quarter ended March 31, 2011.

*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

*101.INS		XBRL Instance Document

*101.SCH		XBRL Schema Document

*101.CAL		XBRL Calculation Linkbase Document



*101.DEF		XBRL Definition Linkbase Document

*101.LAB		XBRL Label Linkbase Document

*101.PRE		XBRL Presentation Linkbase Document

* Filed herewith

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 9, 2011	By:	/s/ Albert L. Reese Jr.
		Albert L. Reese Jr.
		Chief Financial Officer

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Atp Oil & Gas (ATPGQ) Inactive 10-Q2011 Q3 Quarterly report

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