Table of Contents
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, 2010
OR
¨ | 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 200 Houston, Texas 77027 | ||
(Address of principal executive offices) (Zip Code) |
(713) 622-3311
(Registrant's telephone number, including area code)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨
Indicate by check mark whether the registrant 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 ¨ 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 2, 2010 was 51,271,698.
Table of Contents
ATP OIL & GAS CORPORATION AND SUBSIDIARIES
Page | ||||
September 30, 2010 and December 31, 2009 | 3 | |||
For the three and nine months ended September 30, 2010 and 2009 | 4 | |||
For the nine months ended September 30, 2010 and 2009 | 5 | |||
Consolidated Statements of Shareholders’ Equity and Noncontrolling Interest: | ||||
For the nine months ended September 30, 2010 and 2009 | 7 | |||
For the three and nine months ended September 30, 2010 and 2009 | 8 | |||
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 | 42 | |||
42 | ||||
44 | ||||
44 | ||||
44 | ||||
46 |
2
Table of Contents
ATP OIL & GAS CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(In Thousands, Except Share and Per Share Amounts)
(Unaudited)
September 30, 2010 | December 31, 2009 | |||||||
Assets | ||||||||
Current assets: | ||||||||
Cash and cash equivalents | $ | 206,931 | $ | 108,961 | ||||
Restricted cash | 17,354 | 10,504 | ||||||
Accounts receivable (net of allowance of $225 and $291, respectively) | 65,921 | 52,551 | ||||||
Deferred tax asset | 27,112 | 101,956 | ||||||
Derivative asset | 5,979 | 1,321 | ||||||
Other current assets | 10,875 | 10,615 | ||||||
Total current assets | 334,172 | 285,908 | ||||||
Oil and gas properties (using the successful efforts method of accounting): | ||||||||
Proved properties | 4,215,408 | 3,609,131 | ||||||
Unproved properties | 20,868 | 13,910 | ||||||
4,236,276 | 3,623,041 | |||||||
Less accumulated depletion, depreciation, impairment and amortization | (1,301,443 | ) | (1,137,269 | ) | ||||
Oil and gas properties, net | 2,934,833 | 2,485,772 | ||||||
Restricted cash | 10,000 | — | ||||||
Deferred tax asset | 4,438 | — | ||||||
Deferred financing costs, net | 47,449 | 16,378 | ||||||
Other assets, net | 15,218 | 15,089 | ||||||
Total assets | $ | 3,346,110 | $ | 2,803,147 | ||||
Liabilities and Equity | ||||||||
Current liabilities: | ||||||||
Accounts payable and accruals | $ | 261,935 | $ | 212,736 | ||||
Current maturities of long-term debt | 10,867 | 16,838 | ||||||
Asset retirement obligation | 46,984 | 43,418 | ||||||
Derivative liability | 12,539 | 16,216 | ||||||
Other current liabilities | 28,639 | 23,094 | ||||||
Total current liabilities | 360,964 | 312,302 | ||||||
Long-term debt | 1,773,170 | 1,199,847 | ||||||
Other long-term obligations | 495,190 | 274,942 | ||||||
Asset retirement obligation | 111,811 | 106,781 | ||||||
Deferred tax liability | — | 146,764 | ||||||
Derivative liability | 1,895 | 7,646 | ||||||
Deferred revenue | — | 19,336 | ||||||
Total liabilities | 2,743,030 | 2,067,618 | ||||||
Commitments and contingencies (Note 12) | ||||||||
Temporary equity—redeemable noncontrolling interest | 141,265 | 139,598 | ||||||
Shareholders’ equity: | ||||||||
8% convertible perpetual preferred stock: $0.001 par value, 10,000,000 shares authorized; 1,400,000 issued and outstanding at September 30, 2010 and December 31, 2009; at liquidation value | 140,000 | 140,000 | ||||||
Common stock: $0.001 par value, 100,000,000 shares authorized; 51,347,538 issued and 51,271,698 outstanding at September 30, 2010; 50,755,310 issued and 50,679,470 outstanding at December 31, 2009 | 51 | 51 | ||||||
Additional paid-in capital | 572,093 | 571,595 | ||||||
Accumulated deficit | (153,052 | ) | (19,317 | ) | ||||
Accumulated other comprehensive loss | (96,366 | ) | (95,487 | ) | ||||
Treasury stock, at cost | (911 | ) | (911 | ) | ||||
Total shareholders’ equity | 461,815 | 595,931 | ||||||
Total liabilities and equity | $ | 3,346,110 | $ | 2,803,147 | ||||
See accompanying notes to consolidated financial statements.
3
Table of Contents
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, | |||||||||||||||
2010 | 2009 | 2010 | 2009 | |||||||||||||
Revenues: | ||||||||||||||||
Oil and gas production | $ | 102,121 | $ | 75,010 | $ | 296,249 | $ | 224,163 | ||||||||
Other | — | — | — | 13,664 | ||||||||||||
102,121 | 75,010 | 296,249 | 237,827 | |||||||||||||
Costs, operating expenses and other: | ||||||||||||||||
Lease operating | 27,493 | 22,891 | 89,423 | 60,463 | ||||||||||||
Exploration | 543 | — | 1,264 | 267 | ||||||||||||
General and administrative | 9,644 | 6,945 | 29,213 | 25,153 | ||||||||||||
Depreciation, depletion and amortization | 62,505 | 37,460 | 158,621 | 120,433 | ||||||||||||
Impairment of oil and gas properties | 2,988 | — | 15,078 | 8,748 | ||||||||||||
Accretion of asset retirement obligation | 3,566 | 2,995 | 10,419 | 8,940 | ||||||||||||
Contract termination costs | — | — | 8,714 | — | ||||||||||||
Loss on abandonment | 32 | 1,936 | 233 | 2,949 | ||||||||||||
Gain on exchange/disposal of properties | (15,000 | ) | — | (27,020 | ) | — | ||||||||||
Other, net | 2 | 408 | (944 | ) | 696 | |||||||||||
91,773 | 72,635 | 285,001 | 227,649 | |||||||||||||
Income from operations | 10,348 | 2,375 | 11,248 | 10,178 | ||||||||||||
Other income (expense): | ||||||||||||||||
Interest income | 293 | 182 | 591 | 555 | ||||||||||||
Interest expense, net | (69,249 | ) | (9,000 | ) | (146,113 | ) | (31,797 | ) | ||||||||
Derivative income (expense) | (12,665 | ) | (3,458 | ) | 14,799 | 14,999 | ||||||||||
Loss on debt extinguishment | — | — | (78,171 | ) | — | |||||||||||
(81,621 | ) | (12,276 | ) | (208,894 | ) | (16,243 | ) | |||||||||
Loss before income taxes | (71,273 | ) | (9,901 | ) | (197,646 | ) | (6,065 | ) | ||||||||
Income tax (expense) benefit: | ||||||||||||||||
Current | 297 | (376 | ) | 70 | (22 | ) | ||||||||||
Deferred | 19,575 | 4,770 | 76,196 | 4,116 | ||||||||||||
19,872 | 4,394 | 76,266 | 4,094 | |||||||||||||
Net loss | (51,401 | ) | (5,507 | ) | (121,380 | ) | (1,971 | ) | ||||||||
Less income attributable to the redeemable noncontrolling interest | (4,129 | ) | (3,552 | ) | (12,355 | ) | (9,818 | ) | ||||||||
Less convertible preferred stock dividends | (2,820 | ) | (62 | ) | (8,420 | ) | (62 | ) | ||||||||
Net loss attributable to common shareholders | $ | (58,350 | ) | $ | (9,121 | ) | $ | (142,155 | ) | $ | (11,851 | ) | ||||
Net loss per share attributable to common shareholders: | ||||||||||||||||
Basic | $ | (1.15 | ) | $ | (0.20 | ) | $ | (2.81 | ) | $ | (0.30 | ) | ||||
Diluted | $ | (1.15 | ) | $ | (0.20 | ) | $ | (2.81 | ) | $ | (0.30 | ) | ||||
Weighted average number of common shares: | ||||||||||||||||
Basic | 50,800 | 44,520 | 50,673 | 39,038 | ||||||||||||
Diluted | 50,800 | 44,520 | 50,673 | 39,038 |
See accompanying notes to consolidated financial statements.
4
Table of Contents
ATP OIL & GAS CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In Thousands)
(Unaudited)
Nine Months Ended September 30, | ||||||||
2010 | 2009 | |||||||
Cash flows from operating activities | ||||||||
Net loss | $ | (121,380 | ) | $ | (1,971 | ) | ||
Adjustments to reconcile net loss to net cash provided by operating activities: | ||||||||
Depreciation, depletion and amortization | 158,621 | 120,433 | ||||||
Impairment of oil and gas properties | 15,078 | 8,748 | ||||||
Gain on exchange/disposal of properties | (27,020 | ) | — | |||||
Accretion of asset retirement obligation | 10,419 | 8,940 | ||||||
Deferred income tax benefit | (76,196 | ) | (4,116 | ) | ||||
Derivative (income) expense | (14,088 | ) | 23,762 | |||||
Loss on debt extinguishment | 21,829 | — | ||||||
Stock-based compensation | 5,366 | 6,100 | ||||||
Amortization of deferred revenue | (19,336 | ) | (32,395 | ) | ||||
Noncash interest expense | 22,756 | 11,233 | ||||||
Other noncash items, net | 509 | 3,045 | ||||||
Changes in assets and liabilities: | ||||||||
Accounts receivable and other current assets | (13,476 | ) | 30,277 | |||||
Accounts payable and accruals | 39,908 | (48,302 | ) | |||||
Other assets | 209 | |||||||
Other long-term liabilities and deferred obligations | (810 | ) | (522 | ) | ||||
Net cash provided by (used in) operating activities | 2,389 | 125,232 | ||||||
Cash flows from investing activities | ||||||||
Additions to oil and gas properties | (498,625 | ) | (465,109 | ) | ||||
Proceeds from disposal of oil and gas properties | 17,053 | — | ||||||
Increase in restricted cash | (16,850 | ) | (7,534 | ) | ||||
Net cash used in investing activities | (498,422 | ) | (472,643 | ) | ||||
Cash flows from financing activities | ||||||||
Proceeds from senior second lien notes, net of discount | 1,492,965 | — | ||||||
Proceeds from first lien term loans, net of discount | 147,000 | — | ||||||
Proceeds from term loan facility—Titanassets, net of discount | 143,250 | — | ||||||
Proceeds from revolving credit facility, net of discount | 46,000 | — | ||||||
Payments of term loans | (1,262,610 | ) | (61,289 | ) | ||||
Deferred financing costs | (59,294 | ) | — | |||||
Issuance of common stock | — | 161,592 | ||||||
Issuance of preferred stock | — | 135,549 | ||||||
Net profits interests payments | (7,879 | ) | (1,211 | ) | ||||
Principal payments of vendor deferrals | (5,752 | ) | — | |||||
Sale of redeemable noncontrolling interest, net of costs | — | 148,751 | ||||||
Distributions to noncontrolling interest | (10,688 | ) | (15,408 | ) | ||||
Proceeds—pipeline transaction | — | 74,511 | ||||||
Principal payments of pipeline obligation | (455 | ) | — | |||||
Proceeds from sales of net profits interests | 50,000 | — | ||||||
Proceeds from dollar-denominated overriding royalty transactions (“Overrides”) | 121,136 | — | ||||||
Principal payments—Overrides | (55,005 | ) | — | |||||
Preferred stock dividends | (8,448 | ) | — | |||||
Exercise of stock options | 3,580 | 3 | ||||||
Net cash provided by financing activities | 593,800 | 442,498 | ||||||
Effect of exchange rate changes on cash and cash equivalents | 203 | 7,049 | ||||||
Increase in cash and cash equivalents | 97,970 | 102,136 | ||||||
Cash and cash equivalents, beginning of year | 108,961 | 214,993 | ||||||
Cash and cash equivalents, end of period | $ | 206,931 | $ | 317,129 | ||||
See accompanying notes to consolidated financial statements.
5
Table of Contents
ATP OIL & GAS CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS—(Continued)
(In Thousands)
(Unaudited)
Nine Months Ended September 30, | ||||||||
2010 | 2009 | |||||||
Noncash investing and financing activities | ||||||||
Increase in noncash property additions | $ | 112,927 | $ | 76,242 | ||||
Net property additions—nonmonetary exchange | 11,778 | — | ||||||
Asset retirement costs capitalized | 1,258 | — | ||||||
Increase in accrued limited partner distributions | — | 3,563 |
See accompanying notes to consolidated financial statements.
6
Table of Contents
ATP OIL & GAS CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF
SHAREHOLDERS’ EQUITY AND NONCONTROLLING INTEREST
(In Thousands)
(Unaudited)
Nine Months Ended September 30, | ||||||||||||||||
2010 | 2009 | |||||||||||||||
Shares | Amount | Shares | Amount | |||||||||||||
Temporary Equity—Redeemable Noncontrolling Interest: | ||||||||||||||||
Balance, beginning of period | $ | 139,598 | $ | — | ||||||||||||
Sale of Class A Limited Partner Interest, net of formation costs | — | 148,751 | ||||||||||||||
Income attributable to the redeemable noncontrolling interest | 12,355 | 9,818 | ||||||||||||||
Limited partner distributions | (10,688 | ) | (18,971 | ) | ||||||||||||
Balance, end of period | $ | 141,265 | $ | 139,598 | ||||||||||||
Shareholders’ Equity: | ||||||||||||||||
8% Convertible Perpetual Preferred Stock, liquidation value | ||||||||||||||||
Balance, beginning of period | 1,400 | $ | 140,000 | — | $ | — | ||||||||||
Issuance of preferred stock | — | — | 1,400 | 140,000 | ||||||||||||
Balance, end of period | 1,400 | 140,000 | 1,400 | 140,000 | ||||||||||||
Common Stock | ||||||||||||||||
Balance, beginning of period | 50,679 | 51 | 35,903 | 36 | ||||||||||||
Issuance of common stock—secondary offering | — | — | 14,050 | 14 | ||||||||||||
Issuance of common stock—exercise of stock options/warrants | 415 | — | — | — | ||||||||||||
Restricted stock, net of forfeitures | 178 | — | 130 | — | ||||||||||||
Balance, end of period | 51,272 | 51 | 50,083 | 50 | ||||||||||||
Paid-in Capital | ||||||||||||||||
Balance, beginning of period | 571,595 | 400,334 | ||||||||||||||
Issuance of common stock—secondary offering | — | 157,124 | ||||||||||||||
Issuance of common stock—options/warrants | 3,552 | — | ||||||||||||||
Preferred stock dividends | (8,420 | ) | — | |||||||||||||
Stock-based compensation | 5,366 | 6,100 | ||||||||||||||
Balance, end of period | 572,093 | 563,558 | ||||||||||||||
Retained Earnings (Accumulated Deficit) | ||||||||||||||||
Balance, beginning of period | (19,317 | ) | 29,644 | |||||||||||||
Net loss | (121,380 | ) | (1,971 | ) | ||||||||||||
Less income attributable to the redeemable noncontrolling interest | (12,355 | ) | (9,818 | ) | ||||||||||||
Balance, end of period | (153,052 | ) | 17,855 | |||||||||||||
Accumulated Other Comprehensive Loss | ||||||||||||||||
Balance, beginning of period | (95,487 | ) | (112,754 | ) | ||||||||||||
Other comprehensive income (loss) | (879 | ) | 16,843 | |||||||||||||
Balance, end of period | (96,366 | ) | (95,911 | ) | ||||||||||||
Treasury Stock, at Cost | ||||||||||||||||
Balance, beginning of period | 76 | (911 | ) | 76 | (911 | ) | ||||||||||
Balance, end of period | 76 | (911 | ) | 76 | (911 | ) | ||||||||||
Total Shareholders' Equity | $ | 461,815 | $ | 624,641 | ||||||||||||
See accompanying notes to consolidated financial statements.
7
Table of Contents
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, | |||||||||||||||
2010 | 2009 | 2010 | 2009 | |||||||||||||
Net loss | $ | (51,401 | ) | $ | (5,507 | ) | $ | (121,380 | ) | $ | (1,971 | ) | ||||
Other comprehensive income (loss): | ||||||||||||||||
Reclassification adjustment for settled hedge contracts (net of taxes of $0, $453, $0 and $748, respectively) | — | (453 | ) | — | (748 | ) | ||||||||||
Changes in fair value of outstanding hedge positions (net of taxes of $0, ($273), $0 and ($3,642), respectively) | — | 273 | — | 3,642 | ||||||||||||
Foreign currency translation adjustment | 8,811 | (6,359 | ) | (879 | ) | 13,949 | ||||||||||
Other comprehensive income (loss) | 8,811 | (6,539 | ) | (879 | ) | 16,843 | ||||||||||
Comprehensive income (loss) | (42,590 | ) | (12,046 | ) | (122,259 | ) | 14,872 | |||||||||
Less comprehensive income attributable to the redeemable noncontrolling interest | (4,129 | ) | (3,552 | ) | (12,355 | ) | (9,818 | ) | ||||||||
Less convertible preferred stock dividends | (2,820 | ) | (62 | ) | (8,420 | ) | (62 | ) | ||||||||
Comprehensive income (loss) attributable to common shareholders | $ | (49,539 | ) | $ | (15,660 | ) | $ | (143,034 | ) | $ | 4,992 | |||||
See accompanying notes to consolidated financial statements.
8
Table of Contents
ATP OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
Note 1—Organization
ATP Oil & Gas Corporation (“the Company”) was incorporated in Texas in 1991. We are engaged in the acquisition, development and production of oil and natural gas properties in the Gulf of Mexico and the U.K. and Dutch Sectors of the North Sea (the “North Sea”). We primarily focus our efforts on oil and natural gas properties where previous drilling has encountered reservoirs that appear to contain commercially productive quantities of oil and gas. Many of these properties contain proved undeveloped reserves that are economically attractive to us but are not strategic to major or large exploration-oriented independent 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 Securities and Exchange Commission (“SEC”) definition of proved reserves.
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 Energy, Inc.; ATP Oil & Gas (UK) Limited, or “ATP (UK);” ATP Oil & Gas (Netherlands) B.V.; ATP Titan LLC and four other wholly owned limited liability companies created to own our interests in ATP-IP and ATP Titan LLC. 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 2009 Annual Report on Form 10-K. The results of operations for the quarter and year-to-date periods ended September 30, 2010 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
Effective January 2010, the Company adopted the applicable provisions of FASB ASU No. 2010-06, “Improving Disclosures about Fair Value Measurements,” which amends ASC 820-10-50 to require new disclosures concerning (1) transfers into and out of Levels 1 and 2 of the fair value measurement hierarchy, and (2) activity in Level 3 measurements. In addition, ASU No. 2010-06 clarifies certain existing disclosure requirements regarding the level of disaggregation and inputs and valuation techniques and makes conforming amendments to the guidance on employers’ disclosures about postretirement benefit plans assets. The requirements to disclose separately purchases, sales, issuances, and settlements in the Level 3 reconciliation are effective for fiscal years beginning after December 15, 2010 (and for interim periods within such years). Accordingly, we will apply the disclosure requirements relative to the Level 3 reconciliation in the first quarter of 2011. There was no impact on our financial position, results of operations or cash flows as a result of the adoption of this standard.
Effective April 2010, the Company adopted the provisions of FASB ASU No. 2010-14, “Accounting for Extractive Activities—Oil & Gas,” which amends ASC 932-10-S99-1 to provide definitions of some of the terms used in the standard. There was no impact on our financial position, results of operations or cash flows as a result of the adoption of this standard.
Note 3—Risks and Uncertainties
As an independent oil and gas producer, our revenue, profitability, cash flows, 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 material 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 long-term obligations.
9
Table of Contents
ATP OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Unaudited)
In addition, 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 the quantities of oil and natural gas that we ultimately produce. As of December 31, 2009, approximately 87% of our total proved reserves were undeveloped. We intend to continue to develop these reserves through the end of the year and beyond, but there can be 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 and our ability to meet the requirements of our financing obligations.
In addition to the numerous risks associated with offshore operations, some of which may not be covered by insurance, these properties are also characterized by rapid production declines, which require us to incur significant capital expenditures to maintain production rates. Unanticipated complications in the development of any single material well or infrastructure installation, including lack of sufficient capital or operational problems may materially affect our financial condition, results of operations and cash flows.
We are also vulnerable to certain concentrations that could expose our revenues, profitability, cash flows and access to capital to the risk of a near-term severe impact. 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 contributed from relatively few wells located offshore in the Gulf of Mexico and in the North Sea. In 2008, 2009 and thus far in 2010, a significant amount of time and money has been spent by us on our Telemark Hub development. Our results of operations, financial position and cash flows for the next twelve months, as well as longer term, will be significantly impacted by the timing and success at this development. This development commenced production from the Atwater Valley Block 63 #1 Well at the end of the first quarter of 2010 and production was enhanced in October 2010 when this development’s second well was put on production. Beginning in the second half of 2009, we have conveyed to certain vendors and financial parties dollar-denominated net profits interests and overriding royalty interests in our Telemark Hub and Gomez Hub 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 until after the beginning of production. These net profits interests and deferrals, while they allowed development to continue, will burden the net cash flows available to us from Telemark Hub and Gomez Hub production until the obligations have been satisfied.
Although we believe that we will have adequate liquidity to meet our future capital requirements, the factors described above create uncertainty. We consider the control and flexibility afforded by operating our properties under development to be key to our business plan and strategy. By operating our properties, we retain significant control over the development plans and their timing. Within certain constraints, we can conserve capital by delaying or eliminating capital expenditures. While postponing or eliminating capital projects will delay or reduce future cash flows from scheduled new production, this control and flexibility help us to match our capital commitments to our available capital resources.
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 the Minerals Managements Service (“MMS”) 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
10
Table of Contents
ATP OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Unaudited)
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 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 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.
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 Bureau of Ocean Energy Management, Regulation and Enforcement (“BOEM”), successor to the MMS, 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 BOEM. The DOI’s order lifting Moratorium II, however, also requires OCS lessees and operators to comply with BOEM’s 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 BOEM 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. Although Moratorium II has been lifted, we cannot predict with certainty when permits will be granted under the new requirements.
There is also legislation pending in both houses of the U.S. Congress that, if enacted, would significantly impact oil and gas operations on the OCS. In the U.S. House of Representatives, H.R. 3534 proposes to impose numerous new requirements on OCS operations, including increased performance standards for BOPs, disqualification of certain companies from bidding on federal leases or drilling OCS wells, and requirements for documented blowout scenarios in OCS exploration plans. There is also pending in the U.S. Senate a bill that contains some of the same provisions contained in the H.R. 3534. If ultimately enacted, these bills will require higher insurance levels, increased liability exposure, additional fees on production, as well as numerous additional operating constraints and procedures.
We cannot predict how federal and state authorities will further respond to the incident in the Gulf of Mexico or whether additional changes in laws and regulations governing oil and gas operations in the Gulf of Mexico will result. New regulations already issued will, and potential future regulations or additional statutory limitations, if enacted or issued, could, require a change in the way we conduct our business, increase our costs of doing business or ultimately prohibit us from drilling for or producing hydrocarbons in the Gulf of Mexico. We cannot predict if or how the governments of other countries in which we operate will respond to the accident in the Gulf of Mexico.
11
Table of Contents
ATP OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Unaudited)
We have ongoing and planned drilling operations in the deepwater Gulf of Mexico, some of which were permitted prior to April 20, 2010, and some of which are not yet permitted. Such permits, among other required approvals, are necessary prior to commencement of offshore drilling operations. Moratorium II has caused us to delay the third and fourth wells scheduled at our Telemark Hub and, even though Moratorium II has been lifted, any delays in the resumption of the permitting process may result in delays in our drilling operations scheduled in 2011 at our Gomez Hub. During June 2010, we agreed to terminate a contract for services of a drilling rig as a result of Moratorium I. Under the termination agreement, we obtained a full release from our obligations under the contract and incurred net costs of $8.7 million reflected as contract termination costs on the statement of operations.
We project a substantial increase in production over the next year as development wells are brought to production. Absent alternative funding sources, achieving our projected production growth is necessary to provide the cash flow required to fund our capital plan and meet our existing obligations, both over the next twelve months and on a longer-term basis. Our ability to execute our plan depends, in part, on our ability to continue drilling for and producing hydrocarbons in the Gulf of Mexico. Our plan is currently based upon obtaining necessary drilling permits, and successfully achieving commercial production from existing wells presently scheduled to commence during the remainder of 2010 and 2011. Delays from difficulties receiving necessary permits, reduced access to equipment and services, or bad weather, could have a material adverse effect on our financial position, results of operations and cash flows. In addition to the risks associated with achieving our projected production growth, additional regulatory requirements and increased costs for which funding must be secured, or a negative change in commodity prices and operating cost levels, could also have a material adverse effect on our financial position, results of operations and cash flows. While we are pursuing various other sources of funding, there is no assurance that these alternative sources will be available should any of the above risks or uncertainties materialize.
Note 4—Income Taxes
Income tax expense during interim periods is 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. We recognized income tax benefit of $19.9 million and $4.4 million for the three months ended September 30, 2010 and 2009, respectively. We recognized income tax benefit of $76.3 million and $4.1 million for the nine months ended September 30, 2010 and 2009, respectively. The worldwide effective tax rates for the three months ended September 30, 2010 and 2009 were 28% and 44%, respectively. The worldwide effective tax rates for the first nine months of 2010 and 2009 were 39% and 68%, respectively.
Note 5—Oil and Gas Properties
Acquisitions and Dispositions
During the nine months ended September 30, 2010, the MMS, which is now known as BOEM, awarded us leases for 100% of the working interests in the Ship Shoal (“SS”) Block 361 and the Garden Banks Block 782 (“Entrada”). SS Block 361 is in close proximity to our SS Block 358 Hub. Entrada is in the vicinity of existing infrastructure owned by others. We paid $0.4 million for these leases.
During January 2010, we consummated a nonmonetary exchange of our 10% nonoperated working interest in Mississippi Canyon (“MC”) Block 800, for an incremental 50% working interest in MC Block 754, both proved undeveloped 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.
12
Table of Contents
ATP OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Unaudited)
Also, during January 2010, we acquired a 100% working interest in MC Block 710, an exploratory prospect adjacent to our Gomez Hub in MC Block 711 and surrounding blocks, in exchange for the conveyance of an overriding royalty interest in this block.
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.
Impairment of Oil and Gas Properties
We recorded impairments during the nine months ended September 30, 2010 and 2009 of $15.1 million and $8.7 million, respectively. Of these amounts, $4.5 million and $0.7 million in the nine months ended September 30, 2010 and 2009, respectively, were related to unproved properties in the Gulf of Mexico. We recorded impairments of proved properties in the Gulf of Mexico during the nine months ended September 30, 2010 and 2009 of $10.6 million and $8.0 million, respectively.
Note 6—Long-term Debt
Long-term debt consisted of the following (in thousands):
September 30, 2010 | December 31, 2009 | |||||||
First lien term loans, net of $2,820 unamortized discount | $ | 147,180 | $ | — | ||||
Senior second lien notes, net of $6,420 unamortized discount | 1,493,580 | — | ||||||
Term loan facility—ATP Titanassets, net of $6,723 unamortized discount | 143,277 | — | ||||||
Term Loans, net of $28,266 unamortized discount | — | 1,216,685 | ||||||
Total debt | 1,784,037 | 1,216,685 | ||||||
Less current maturities | (10,867 | ) | (16,838 | ) | ||||
Total long-term debt | $ | 1,773,170 | $ | 1,199,847 | ||||
In April 2010, we entered into a first lien revolving credit facility (the “Original Credit Facility”) with an initial borrowing base of $100.0 million, due April 23, 2013, and issued senior second lien notes (the “Notes”) in an aggregate principal amount of $1.5 billion, due May 1, 2015. We used proceeds from the Notes to repay the entire amount due under our term loans previously outstanding and subsequently replaced the Original Credit Facility with the New Credit Facility, discussed below
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. In connection with the issuance of the Notes, we granted registration rights to the holders of the Notes and agreed to register the Notes with the SEC within 270 days of their initial issuance. The Notes were issued at 99.531% of their face amount to yield 12.0% and we incurred issuance costs of $38.2 million.
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.
13
Table of Contents
ATP OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Unaudited)
In June 2010, we entered into a new first lien credit agreement (the “New Credit Facility”) with an initial balance of $150.0 million, due May 15, 2014, to replace the Original Credit Facility. Proceeds of the New Credit Facility were $144.3 million, net of original issue discount and transaction fees. Principal outstanding under the term loans issued pursuant to the New Credit Facility bears interest at an annual rate of 11.0%. As security for the Company’s obligations under the New 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. Principal of $750,000 is due each June and December beginning December 18, 2010 until June 18, 2014. The remaining principal balance is due October 15, 2014. The New Credit Facility allows the Company to incur up to $350.0 million of additional indebtedness as Consolidated Net Tangible Assets (as defined in the New Credit Facility) increase, although the lender is not yet committed to fund additional amounts .
The Notes and New 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, and transferred to it our 100% ownership of theATP Titan platform and related infrastructure assets at their carryover cost basis. Simultaneous with the transfer, we entered into a $350.0 million term loan facility (the “ATP TitanFacility”), of which $150.0 million was drawn initially. At closing, we received proceeds of $140.8 million net of discount and direct issuance costs. There are provisions in theATP TitanFacility under which the undrawn balance may be funded upon our request and subject to lender approval based on first production from wells at our Telemark Hub as follows: $100.0 million from the second well and $50.0 million each from the third and fourth wells. TheATP TitanFacility is to be repaid quarterly as follows: annual principal reductions of 8% in the first year, 9% in the second year and 10% thereafter until maturity in September 2017. TheATP TitanFacility bears interest at LIBOR (floor of 0.75%) plus 8%. TheATPTitan 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 TitanFacility. TheATP TitanFacility 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. The Company does not guarantee the debt of Titan LLC. 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 New Credit Facility and the Notes contain customary events of default, and if certain of those events of default were to occur and remain incurred, such as a failure to pay principal or interest when due, our lenders could terminate future lending commitments under the New Credit Facility, and our lenders could declare the outstanding borrowings due and payable. The New 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 of our long-term debt was 12.3% at September 30, 2010. The fair value of the aggregate long-term debt as of September 30, 2010 was approximately $1.6 billion.
14
Table of Contents
ATP OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Unaudited)
Note 7—Other Long-term Obligations
Other long-term obligations consisted of the following (in thousands):
September 30, 2010 | December 31, 2009 | |||||||
Net profits interests | $ | 275,300 | $ | 180,818 | ||||
Dollar-denominated overriding royalty interests | 81,073 | 14,941 | ||||||
Gomez pipeline obligation | 74,056 | 75,152 | ||||||
Vendor deferrals—Gulf of Mexico | 11,015 | 7,490 | ||||||
Vendor deferrals—North Sea | 79,803 | 17,053 | ||||||
Other | 2,582 | 2,582 | ||||||
Total | 523,829 | 298,036 | ||||||
Less current maturities | (28,639 | ) | (23,094 | ) | ||||
Other long-term obligations | $ | 495,190 | $ | 274,942 | ||||
Net Profits Interests
During 2009 and 2010, we granted dollar-denominated overriding royalty interests in the form of net profits interests (“NPIs”) in certain of our oil and gas properties in and around the Telemark Hub and Gomez Hub to certain of our vendors in exchange for oil and gas property development services. The interests earned by the vendors 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, there is no payment required. We accrue the present value of the NPIs as a liability on our consolidated balance sheet. As the NPI is earned, 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 Statement of Operations. The term of the NPIs will be dependent on the value of the services contributed by these vendors coupled with the estimated timing of production and future economic conditions, including commodity prices and operating costs. Because we have accounted for these NPI's as financing obligations on our Consolidated Balance Sheet, the reserves and production revenues associated with the NPIs are retained by the Company.
Dollar-denominated Overriding Royalty Interests
In October 2009, we sold a dollar-denominated overriding royalty interest (“Override”) in our Gomez Hub properties for $14.5 million, net of costs. During the nine months ended September 30, 2010, we sold Overrides (primarily dollar-denominated) in future production from the Gomez Hub properties for $140.0 million ($121.1 million net of transaction costs and fourth quarter 2009 royalty payments). These Overrides obligate us to deliver proceeds from the future sale of hydrocarbons from the specified properties equal to the purchasers’ original investments, plus an overall rate of 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, there is no payment required. The percentage of property revenues available to satisfy these obligations is dependent upon certain conditions specified in the agreement. Upon payment of the agreed dollar amounts, the ownership of the Overrides reverts to us. 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 and 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.
Gomez Pipeline Obligation
In 2009, we executed an asset purchase and sale agreement for net proceeds of $74.5 million pursuant to which the Company sold to a third party the oil and natural gas pipelines that service the Gomez Hub at MC Block 711. In conjunction with the sale, we entered into agreements with the third party to transport oil and
15
Table of Contents
ATP OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Unaudited)
natural gas production for the remaining production life of the fields serviced by theATP Innovator 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 the company 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 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 net profits interests 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 until after production has begun. 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 and we have arranged with the fabricator of the floating production and drilling facility to defer $99 million of payments until construction is complete, which is expected to be in the fourth quarter of 2011. As work is completed, we record obligations and related interest expense, net of amounts capitalized, on the Consolidated Statements of Operations.
The weighted average effective interest rate on other long-term obligations was 16.6% at September 30, 2010.
Note 8—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, | ||||||||
2010 | 2009 | |||||||
Asset retirement obligation, beginning of period | $ | 150,199 | $ | 132,108 | ||||
Liabilities incurred | 1,491 | 7,424 | ||||||
Liabilities settled | (2,890 | ) | (9,501 | ) | ||||
Property dispositions | (242 | ) | (292 | ) | ||||
Accretion of asset retirement obligation | 10,419 | 8,940 | ||||||
Changes in estimates | (182 | ) | 2,615 | |||||
Total asset retirement obligation | 158,795 | 141,294 | ||||||
Less current portion | (46,984 | ) | (30,156 | ) | ||||
Total long-term asset retirement obligation, end of period | $ | 111,811 | $ | 111,138 | ||||
Note 9—Stock–Based Compensation
We recognized stock option compensation expense of $0.7 million and $0.6 million for the three months ended September 30, 2010 and 2009, respectively, and $2.0 million and $2.2 million during the nine months ended September 30, 2010 and 2009, respectively. We recognized restricted stock compensation expense of $1.2 million and $1.2 million for the three months ended September 30, 2010 and 2009, respectively, and $3.3 million and $3.9 million during the nine months ended September 30, 2010 and 2009, respectively.
16
Table of Contents
ATP OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Unaudited)
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 September 30, | Nine Months Ended September 30, | |||||||||||||||
2010 | 2009 | 2010 | 2009 | |||||||||||||
Weighted average volatility | 84 | % | 76 | % | 84 | % | 74 | % | ||||||||
Expected term (in years) | 3.8 | 3.8 | 3.8 | 3.8 | ||||||||||||
Risk-free rate | 1.0 | % | 1.9 | % | 1.2 | % | 1.8 | % | ||||||||
Weighted average fair value of options—grant date | $ | 5.45 | $ | 9.84 | $ | 5.53 | $ | 6.79 |
The following table sets forth a summary of option transactions for the nine months ended September 30, 2010:
Number of Options | Weighted Average Grant Price | Aggregate Intrinsic Value (1) ($000) | Weighted Average Remaining Contractual Life | |||||||||||||
(in years) | ||||||||||||||||
Outstanding at beginning of period | 1,634,105 | $ | 24.69 | |||||||||||||
Granted | 297,250 | 9.47 | ||||||||||||||
Forfeited | (31,763 | ) | 21.60 | |||||||||||||
Expired | (262,114 | ) | 19.77 | |||||||||||||
Exercised | (64,897 | ) | 16.03 | $ | 384 | |||||||||||
Outstanding at end of period | 1,572,581 | 23.05 | $ | 3,653 | 3.1 | |||||||||||
Vested and expected to vest | 1,369,283 | 23.27 | $ | 3,127 | 3.0 | |||||||||||
Options exercisable at end of period | 527,569 | 33.97 | $ | 491 | 1.8 | |||||||||||
(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, 2010, unrecognized compensation expense related to nonvested stock option grants totaled $3.4 million. Such unrecognized expense will be recognized as vesting occurs over a weighted average period of 2.7 years. At September 30, 2010, unrecognized compensation expense related to restricted stock totaled $2.8 million. Such unrecognized expense will be recognized as vesting occurs over a weighted average period of 1.6 years. The following table sets forth the changes in nonvested restricted stock for the nine months ended September 30, 2010:
Number of Shares | Weighted Average Grant-date Fair Value | Aggregate Intrinsic Value (1) ($000) | ||||||||||
Nonvested at beginning of period | 419,293 | $ | 26.25 | |||||||||
Granted | 179,179 | 13.85 | ||||||||||
Forfeited | (2,181 | ) | 8.84 | |||||||||
Vested | (131,154 | ) | 24.87 | |||||||||
Nonvested at end of period | 465,137 | 21.95 | $ | 6,349 | ||||||||
(1) | Based upon the closing market price of the common stock on the last trading day of the period. |
17
Table of Contents
ATP OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Unaudited)
Note 10—Earnings Per Share
Basic earnings per share (“EPS”) is computed by dividing net income or loss attributable to common shareholders by the weighted average number of common shares (other than nonvested restricted stock) outstanding during the period. Weighted average shares outstanding for diluted EPS also includes a hypothetical number of additional shares (“Common Stock Equivalents”) calculated assuming the exercise or conversion of all in-the-money options, warrants and convertible preferred stock and full vesting of restricted stock awards. Common Stock Equivalents are excluded from the computation of weighted average common shares outstanding when the per share effect is antidilutive. The impact of assumed conversion of preferred stock on net income (loss) is excluded from the computation of EPS when its impact is antidilutive. For the three months ended September 30, 2010 and 2009, respectively, 1.3 million and 1.5 million Common Stock Equivalents were excluded from the diluted EPS calculation in the table below because their inclusion would have been antidilutive. For the nine months ended September 30, 2010 and 2009, respectively, 1.7 million and 1.3 million Common Stock Equivalents were excluded from the diluted EPS calculation in the table below because their inclusion would have been antidilutive. For the three and nine months ended September 30, 2010, preferred stock dividends of $2.8 million and $8.4 million, respectively, were excluded from the diluted EPS computation of net loss attributable to common shareholders for each such period because their inclusion would have been antidilutive. A total of 6.3 million potential shares from the assumed conversion of preferred stock have been excluded from each 2010 period because their effect would have been antidilutive. A total of 0.1 million and zero, respectively, potential shares from the assumed conversion of preferred stock have been excluded from the three and nine months ended September 30, 2009 periods because their effect would have been antidilutive.
18
Table of Contents
ATP OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Unaudited)
Basic and diluted net loss per share is computed based on the following information (in thousands, except per share amounts):
Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||
2010 | 2009 | 2010 | 2009 | |||||||||||||
Net loss attributable to common shareholders | $ | (58,350 | ) | $ | (9,121 | ) | $ | (142,155 | ) | $ | (11,851 | ) | ||||
Add impact of assumed preferred stock conversions (if-converted method) | — | — | — | — | ||||||||||||
Net loss attributable to common shareholders and impact of assumed conversions | $ | (58,350 | ) | $ | (9,121 | ) | $ | (142,155 | ) | $ | (11,851 | ) | ||||
Shares outstanding: | ||||||||||||||||
Weighted average shares outstanding—basic | 50,800 | 44,520 | 50,673 | 39,038 | ||||||||||||
Effect of potentially dilutive securities—stock options and warrants | — | — | — | — | ||||||||||||
Nonvested restricted stock | — | — | — | — | ||||||||||||
Preferred stock | — | — | — | — | ||||||||||||
Weighted average shares outstanding—diluted | 50,800 | 44,520 | 50,673 | 39,038 | ||||||||||||
Net loss per share attributable to common shareholders: | ||||||||||||||||
Basic | $ | (1.15 | ) | $ | (0.20 | ) | $ | (2.81 | ) | $ | (0.30 | ) | ||||
Diluted | $ | (1.15 | ) | $ | (0.20 | ) | $ | (2.81 | ) | $ | (0.30 | ) | ||||
Note 11—Derivative Instruments and Risk Management Activities
We periodically enter into commodity price derivative contracts and fixed-price physical contracts to manage our exposure to oil and natural gas price volatility. We primarily utilize fixed-price physical forward contracts, price swaps, price collars and put options which are generally placed with major financial institutions or with counterparties of high credit quality in order to minimize our credit risks. The oil and natural gas reference prices of these commodity derivative contracts are based upon oil and natural gas market exchanges which have a high degree of historical correlation with the actual prices we receive. All derivative instruments are recorded on the balance sheet at fair value.
Gains and losses for derivatives which have not been designated as hedges are recorded as components of derivative income (expense) in our Consolidated Statements of Operations. Gains and losses for derivatives which have been designated as hedges are recorded instead to accumulated other comprehensive income (loss) (“AOCI”) until the period in which the forecasted hedged transactions occur, at which time the gains and losses are reclassified from AOCI to the Consolidated Statements of Operations as components of the revenue items to which they relate. Settlements of commodity derivative instruments are included in cash flows from operating activities in our Consolidated Statements of Cash Flows.
19
Table of Contents
ATP OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Unaudited)
At September 30, 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 | ||||||||||||||||||
Remainder 2010 | Puts | 92,000 | 24.70 | $ | — | $ | — | |||||||||||
Remainder 2010 | Swaps | 414,000 | 77.83 | (1,363 | ) | — | ||||||||||||
2011 | Swaps | 1,987,500 | 81.60 | (4,174 | ) | (1,904 | ) | |||||||||||
2012 | Swaps | 479,750 | 89.07 | — | 754 | |||||||||||||
Remainder 2010 | Swaps (3) | 184,000 | 70.00 | (2,012 | ) | — | ||||||||||||
2011 | Swaps (3) | 911,000 | 78.41 | (3,328 | ) | (379 | ) | |||||||||||
Total | $ | (10,877 | ) | $ | (1,529 | ) | ||||||||||||
Natural Gas (MMBtu) | ||||||||||||||||||
North Sea | ||||||||||||||||||
Remainder 2010 | Fixed-price physicals | 276,000 | 6.96 | $ | (154 | ) | $ | — | ||||||||||
Remainder 2010 | Swaps | 460,000 | 5.74 | (805 | ) | — | ||||||||||||
2011 | Swaps | 1,641,000 | 7.37 | (703 | ) | (132 | ) | |||||||||||
2012 | Swaps | 1,464,000 | 8.38 | — | (234 | ) | ||||||||||||
Gulf of Mexico | ||||||||||||||||||
Remainder 2010 | Fixed-price physicals | 1,830,000 | 5.57 | 2,971 | — | |||||||||||||
2011 | Fixed-price physicals | 900,000 | 5.42 | 1,010 | — | |||||||||||||
Remainder 2010 | Collars | 1,380,000 | 4.75-7.95 | 1,137 | — | |||||||||||||
2011 | Collars | 1,350,000 | 4.75-7.95 | 861 | — | |||||||||||||
Total | $ | 4,317 | $ | (366 | ) | |||||||||||||
Derivative asset | $ | 5,979 | $ | — | ||||||||||||||
Derivative liability | (12,539 | ) | (1,895 | ) | ||||||||||||||
Total | $ | (6,560 | ) | $ | (1,895 | ) | ||||||||||||
(1) | Unit price for collars reflects the floor and the ceiling prices, respectively. |
(2) | None of the derivatives outstanding is designated as a hedge for accounting purposes. |
(3) | These swaps include call options to allow us to participate in per barrel price increases above $110 and $111 in remainder 2010 and 2011, respectively. |
20
Table of Contents
ATP OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Unaudited)
At December 31, 2009, 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 | ||||||||||||||||||
2010 | Puts | 365,000 | 24.70 | $ | 2 | $ | — | |||||||||||
2010 | Swaps | 733,000 | 79.76 | (2,212 | ) | — | ||||||||||||
2011 | Swaps | 1,095,000 | 80.17 | — | (5,625 | ) | ||||||||||||
2010 | Swaps (3) | 1,273,000 | 68.29 | (13,402 | ) | — | ||||||||||||
2011 | Swaps (3) | 181,000 | 72.00 | — | (1,508 | ) | ||||||||||||
Total | $ | (15,612 | ) | $ | (7,133 | ) | ||||||||||||
Natural Gas (MMBtu) | ||||||||||||||||||
North Sea | ||||||||||||||||||
2010 | Fixed-price physicals | 1,095,000 | 7.01 | $ | 1,321 | $ | — | |||||||||||
Gulf of Mexico | ||||||||||||||||||
2010 | Fixed-price physicals | 4,525,000 | 5.58 | (778 | ) | — | ||||||||||||
2010 | Collars | 4,575,000 | 4.68-7.86 | 173 | — | |||||||||||||
2011 | Collars | 1,350,000 | 4.75-7.95 | — | (512 | ) | ||||||||||||
Total | $ | 716 | $ | (512 | ) | |||||||||||||
Derivative asset | $ | 1,321 | $ | — | ||||||||||||||
Derivative liability | (16,216 | ) | (7,646 | ) | ||||||||||||||
Total | $ | (14,895 | ) | $ | (7,646 | ) | ||||||||||||
(1) | Unit price for collars reflects the floor and the ceiling prices, respectively. |
(2) | None of the derivatives outstanding is designated as a hedge for accounting purposes. |
(3) | These swaps include call options to allow us to participate in per barrel price increases above $99.34 and $115.00 in 2010 and 2011, respectively. |
There was no hedge AOCI during the nine months ended September 30, 2010. The following AOCI table shows where gains and losses (net of taxes) on cash flow hedge derivatives have been reported in the three months and nine months ended September 30, 2009 (in thousands):
Three Months Ended September 30, 2009 | Nine Months Ended September 30, 2009 | |||||||
AOCI for cash flow hedges—beginning of period | $ | 197 | $ | (2,877 | ) | |||
Derivative gains | 273 | 3,642 | ||||||
Losses reclassified from AOCI to oil and gas revenues | (453 | ) | (748 | ) | ||||
AOCI for cash flow hedges—end of period | $ | 17 | $ | 17 | ||||
21
Table of Contents
ATP OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Unaudited)
During the nine months ended September 30, 2010, we received net cash settlements of $0.7 million of our price hedge derivatives. Our derivative income for the nine months ended September 30, 2010 and 2009 is based entirely on nondesignated derivatives and consists of the following (in thousands):
Three Months Ended September 30, | ||||||||
2010 | 2009 | |||||||
Realized gains (losses) from: | ||||||||
Settlements of contracts | $ | 1,888 | $ | 1,476 | ||||
Unrealized losses on open contracts | (14,553 | ) | (4,934 | ) | ||||
Derivative expense | $ | (12,665 | ) | $ | (3,458 | ) | ||
Nine Months Ended September 30, | ||||||||
2010 | 2009 | |||||||
Realized gains (losses) from: | ||||||||
Settlements of contracts | $ | 439 | $ | 20,190 | ||||
Early terminations of contracts | — | 17,657 | ||||||
Unrealized gains (losses) on open contracts | 14,360 | (22,848 | ) | |||||
Derivative income | $ | 14,799 | $ | 14,999 | ||||
Note 12—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. 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.
During the term of the Platform Use Agreement governing theATP Innovator, we are obligated to pay to ATP-IP, our consolidated partnership, a per unit fee for all hydrocarbons processed by theATP Innovator, subject to a minimum throughput fee of $53,000 per day. We may also be subject to a minimum fee of $53,000 per day for up to 180 days under certain circumstances, including if we fail to provide the minimum notification period before the Gomez Hub fields ceases production. We are responsible for all of the operating costs and periodic maintenance of theATP Innovator. We could also 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
22
Table of Contents
ATP OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Unaudited)
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, 2010, the aggregate amount of such contingent commitments related to unmet operational milestones was $8.0 million.
In February 2010, Bison Capital Corporation filed suit against ATP alleging that fees totaling $102 million related to certain financing transactions had not been paid by ATP. We believe we have paid Bison Capital Corporation all amounts due under our 2004 agreement with them. ATP plans to vigorously defend against these allegations.
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, 2010, either individually or in the aggregate, will have a material adverse effect on our financial condition, results of operations or cash flows.
Note 13—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 Gulf of Mexico segment and its North Sea segment. The operations of both segments include natural gas and liquid hydrocarbon production and sales. Segment activity is as follows (in thousands):
For the Three Months Ended— | Gulf of Mexico | North Sea | Total | |||||||||
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 (expense) benefit | 19,942 | (70 | ) | 19,872 | ||||||||
Additions to oil and gas properties | 79,575 | 38,864 | 118,439 | |||||||||
September 30, 2009: | ||||||||||||
Revenues | $ | 70,668 | $ | 4,342 | $ | 75,010 | ||||||
Depreciation, depletion and amortization | 32,202 | 5,258 | 37,460 | |||||||||
Income (loss) from operations | 6,057 | (3,682 | ) | 2,375 | ||||||||
Interest income | 16 | 166 | 182 | |||||||||
Interest expense, net | 8,996 | 4 | 9,000 | |||||||||
Derivative income (expense) | (5,569 | ) | 2,111 | (3,458 | ) | |||||||
Income tax (expense) benefit | 4,537 | (143 | ) | 4,394 | ||||||||
Additions to oil and gas properties | 185,472 | 15,452 | 200,924 |
23
Table of Contents
ATP OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Unaudited)
For the Nine Months Ended— | Gulf of Mexico | North Sea | Total | |||||||||
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 (loss) | 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 | |||||||||
September 30, 2009: | ||||||||||||
Revenues | $ | 225,260 | $ | 12,567 | $ | 237,827 | ||||||
Depreciation, depletion and amortization | 101,870 | 18,563 | 120,433 | |||||||||
Impairment of oil and gas properties | 8,748 | — | 8,748 | |||||||||
Income (loss) from operations | 25,507 | (15,329 | ) | 10,178 | ||||||||
Interest income | 389 | 166 | 555 | |||||||||
Interest expense, net | 31,793 | 4 | 31,797 | |||||||||
Derivative income | 7,629 | 7,370 | 14,999 | |||||||||
Income tax (expense) benefit | 4,237 | (143 | ) | 4,094 | ||||||||
Additions to oil and gas properties | 467,999 | 91,552 | 559,551 | |||||||||
Total assets | 2,497,987 | 265,118 | 2,763,105 |
Note 14—Fair Value Measurements
Assets and Liabilities Measured at Fair Value on a Recurring Basis
The fair value of our derivative contracts is based on significant unobservable (or Level 3) 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, 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 income (expense) | 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 | ) | $ | (1 | ) | $ | 4,682 | |||||||||
24
Table of Contents
ATP OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Unaudited)
Gas Fixed- Price Physicals | Gas Swaps | Subtotal U.K. | Grand Total | |||||||||||||
U.K. | ||||||||||||||||
Balance at beginning of period | $ | 1,321 | $ | — | $ | 1,321 | $ | (22,541 | ) | |||||||
Derivative income (expense) | (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 | ) | $ | 2,688 | |||||
(1) | These swaps include call options to allow us to participate in price increases above certain levels. |
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, 2010, we recorded impairment expense of $15.1 million on proved and unproved properties and gain on nonmonetary property exchange of $12.0 million related to proved 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. 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 which is classified as Level 3 and which 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 potential purchasers to determine the fair value of the assets.
Note 15—Subsequent Events
Our evaluation has identified no matters which require disclosure as events subsequent to September 30, 2010.
25
Table of Contents
ATP OIL & GAS CORPORATION AND SUBSIDIARIES
Item 2. | Management’s Discussion and Analysis of Financial Condition and Results of Operations |
Executive Overview
General
ATP Oil & Gas Corporation is engaged in the acquisition, development and production of oil and natural gas properties in the Gulf of Mexico and the U.K. and Dutch Sectors of 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 exploration-oriented independent 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. We believe that our strategy provides assets for us to develop and produce without the risk, cost or time of traditional exploration. Our management team has extensive engineering, geological, geophysical, technical and operational expertise in successfully developing and operating properties in both our current and planned areas of operation.
We seek to create value and reduce operating risks through the acquisition and subsequent development of properties in areas that have:
• | significant undeveloped reserves; |
• | 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. |
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 have an acquisition cost of a property that is less than the total development costs incurred by the previous owner. This strategy, coupled with our expertise in our areas of focus and our ability to develop projects, tend 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 a significant number of the properties in which we acquire a working interest, we are able to significantly influence the plans and timing of a project’s development. 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. We believe this strategy, combined with our strong technical abilities to evaluate and implement a project’s requirements, gives us an advantage over exploration-oriented operators and allows us to efficiently complete development projects and commence production.
Beginning in 2003, we made a concerted effort to expand our presence into the deeper water of the Gulf of Mexico. In 2003 we acquired Mississippi Canyon (“MC”) Block 711 (now part of our Gomez Hub) in 3,000
26
Table of Contents
feet of water; in 2005, we acquired MC Block 217 (now part of our Canyon Express Hub) in 7,000 feet of water; and in 2006, we acquired MC Block 941, MC Block 942 and Atwater Valley (“AT”) Block 63 (now part of our Telemark Hub) in 4,000 feet of water. The Telemark Hub was placed on production March 28, 2010 with the first well at AT 63. In October 2010, production began from the MC 941 #3 well, our second Telemark Hub development well. The third and fourth wells at our Telemark Hub were impacted by the U.S. Department of Interior drilling moratoriums and cannot be completed until additional permits for these wells are issued. These two development wells are drilled to approximately 12,000 feet and require additional drilling to reach the target depth of approximately 20,000 feet. With the acquisition and subsequent development of these properties, our proved reserves in the deep water Gulf of Mexico account for 62% of our total proved reserves as of December 31, 2009. Our proved reserves on the Gulf of Mexico Outer Continental Shelf account for 6% of our total proved reserves with the remaining 32% in the North Sea.
In conjunction with our move to the deeper water of the Gulf of Mexico, we also made the commitment to increase our investment in reusable floating infrastructure. We own interests in two floating production facilities, theATP Innovator(51%) and theATP Titan(100%). TheATP Innovator is operating in the Gulf of Mexico at our Gomez Hub and theATP Titan is operating in the Gulf of Mexico at our Telemark Hub. These floating production facilities are fundamental to our hub strategy and business plan. We believe the presence of these facilities allows us a competitive advantage for additional acquisitions in a large area surrounding each installation. A third floating production facility called an Octabuoy is under construction in China for initial deployment at our Cheviot Hub in the U.K. North Sea during 2012. We operate theATP Innovator and theATP Titan and also expect to operate the Octabuoy when it is placed in service. The floating production facilities have longer useful lives than the underlying reserves and are capable of redeployment to new productive locations upon depletion of the reserves. Accordingly, they are expected to be moved several times over their useful lives.
Risks and Uncertainties
As an independent oil and gas producer, our revenue, profitability, cash flows, 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 material 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 long-term obligations.
In addition, 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 the quantities of oil and natural gas that we ultimately produce. As of December 31, 2009, approximately 87% of our total proved reserves were undeveloped. We intend to continue to develop these reserves through the end of the year and beyond, but there can be 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 and our ability to meet the requirements of our financing obligations.
In addition to the numerous risks associated with offshore operations, some of which may not be covered by insurance, these properties are also characterized by rapid production declines, which require us to incur significant capital expenditures to maintain production rates. Unanticipated complications in the development of any single material well or infrastructure installation, including lack of sufficient capital or operational problems may materially affect our financial condition, results of operations and cash flows.
27
Table of Contents
We are also vulnerable to certain concentrations that could expose our revenues, profitability, cash flows and access to capital to the risk of a near-term severe impact. 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 contributed from relatively few wells located offshore in the Gulf of Mexico and in the North Sea. In 2008, 2009 and thus far in 2010, a significant amount of time and money has been spent by us on our Telemark Hub development. Our results of operations, financial position and cash flows for the next twelve months, as well as longer term, will be significantly impacted by the timing and success at this development. This development commenced production from the Atwater Valley Block 63 #1 Well at the end of the first quarter of 2010 and production was enhanced in October 2010 when this development’s second well was put on production. Beginning in the second half of 2009, we have conveyed to certain vendors and financial parties dollar-denominated net profits interests and overriding royalty interests in our Telemark Hub and Gomez Hub 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 until after the beginning of production. These net profits interests and deferrals, while they allowed development to continue, will burden the net cash flows available to us from Telemark Hub and Gomez Hub production until the obligations have been satisfied.
Although we believe that we will have adequate liquidity to meet our future capital requirements, the factors described above create uncertainty. We consider the control and flexibility afforded by operating our properties under development to be key to our business plan and strategy. By operating our properties, we retain significant control over the development plans and their timing. Within certain constraints, we can conserve capital by delaying or eliminating capital expenditures. While postponing or eliminating capital projects will delay or reduce future cash flows from scheduled new production, this control and flexibility help us to match our capital commitments to our available capital resources.
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 the Minerals Managements Service (“MMS”) 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 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 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.
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 Bureau of Ocean Energy Management, Regulation and Enforcement (“BOEM”), successor to the MMS, 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 BOEM. The DOI’s order lifting Moratorium II, however, also requires OCS lessees and operators to
28
Table of Contents
comply with BOEM’s 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 BOEM 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. Although Moratorium II has been lifted, we cannot predict with certainty when permits will be granted under the new requirements.
There is also legislation pending in both houses of the U.S. Congress that, if enacted, would significantly impact oil and gas operations on the OCS. In the U.S. House of Representatives, H.R. 3534 proposes to impose numerous new requirements on OCS operations, including increased performance standards for BOPs, disqualification of certain companies from bidding on federal leases or drilling OCS wells, and requirements for documented blowout scenarios in OCS exploration plans. There is also pending in the U.S. Senate a bill that contains some of the same provisions contained in the H.R. 3534. If ultimately enacted, these bills will require higher insurance levels, increased liability exposure, additional fees on production, as well as numerous additional operating constraints and procedures.
We cannot predict how federal and state authorities will further respond to the incident in the Gulf of Mexico or whether additional changes in laws and regulations governing oil and gas operations in the Gulf of Mexico will result. New regulations already issued will, and potential future regulations or additional statutory limitations, if enacted or issued, could, require a change in the way we conduct our business, increase our costs of doing business or ultimately prohibit us from drilling for or producing hydrocarbons in the Gulf of Mexico. We cannot predict if or how the governments of other countries in which we operate will respond to the accident in the Gulf of Mexico.
We have ongoing and planned drilling operations in the deepwater Gulf of Mexico, some of which were permitted prior to April 20, 2010, and some of which are not yet permitted. Such permits, among other required approvals, are necessary prior to commencement of offshore drilling operations. Moratorium II has caused us to delay the third and fourth wells scheduled at our Telemark Hub and, even though Moratorium II has been lifted, any delays in the resumption of the permitting process may result in delays in our drilling operations scheduled in 2011 at our Gomez Hub. During June 2010, we agreed to terminate a contract for services of a drilling rig as a result of Moratorium I. Under the termination agreement, we obtained a full release from our obligations under the contract and incurred net costs of $8.7 million reflected as contract termination costs on the statement of operations.
We project a substantial increase in production over the next year as development wells are brought to production. Absent alternative funding sources, achieving our projected production growth is necessary to provide the cash flow required to fund our capital plan and meet our existing obligations, both over the next twelve months and on a longer-term basis. Our ability to execute our plan depends, in part, on our ability to continue drilling for and producing hydrocarbons in the Gulf of Mexico. Our plan is currently based upon obtaining necessary drilling permits, and successfully achieving commercial production from existing wells presently scheduled to commence during the remainder of 2010 and 2011. Delays from difficulties receiving necessary permits, reduced access to equipment and services, or bad weather, could have a material adverse effect on our financial position, results of operations and cash flows. In addition to the risks associated with achieving our projected production growth, additional regulatory requirements and increased costs for which funding must be secured, or a negative change in commodity prices and operating cost levels, could also have a material adverse effect on our financial position, results of operations and cash flows. While we are pursuing various other sources of funding, there is no assurance that these alternative sources will be available should any of the above risks or uncertainties materialize.
29
Table of Contents
Results of Operations
Three Months Ended September 30, 2010 Compared to Three Months Ended September 30, 2009
For the three months ended September 30, 2010 and 2009 we reported net loss attributable to common shareholders of $58.4 million and $9.1 million, or $1.15 and $0.20 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 related to the second quarter 2008 sale of the limited-term overriding royalty interest. We do not reflect any production volumes associated with those revenues.
Three Months Ended September 30, | % Change from 2009 to 2010 | |||||||||||
2010 | 2009 | |||||||||||
Production: | ||||||||||||
Oil and condensate (MBbl) | 1,127 | 792 | 42 | % | ||||||||
Natural gas (MMcf) | 4,900 | 3,689 | 33 | % | ||||||||
Total (MBoe) | 1,944 | 1,406 | 38 | % | ||||||||
Gulf of Mexico (MBoe) | 1,849 | 1,279 | 45 | % | ||||||||
North Sea (MBoe) | 95 | 128 | (26 | %) | ||||||||
Revenues from production (in thousands): | ||||||||||||
Oil and condensate | $ | 78,102 | $ | 50,907 | 53 | % | ||||||
Amortization of deferred revenue | 852 | 7,931 | ||||||||||
Total | $ | 78,954 | $ | 58,838 | 34 | % | ||||||
Natural gas | $ | 23,167 | $ | 13,479 | 72 | % | ||||||
Effects of cash flow hedges | — | 904 | ||||||||||
Amortization of deferred revenue | — | 1,789 | ||||||||||
Total | $ | 23,167 | $ | 16,172 | 43 | % | ||||||
Oil, condensate and natural gas | $ | 101,269 | $ | 64,386 | 57 | % | ||||||
Effects of cash flow hedges | — | 904 | ||||||||||
Amortization of deferred revenue | 852 | 9,720 | ||||||||||
Total | $ | 102,121 | $ | 75,010 | 36 | % | ||||||
Average realized sales price: | ||||||||||||
Oil and condensate average realized price (per Bbl) | $ | 69.30 | $ | 64.28 | 8 | % | ||||||
Natural gas (per Mcf) | $ | 4.73 | $ | 3.67 | 29 | % | ||||||
Effects of cash flow hedges (per Mcf) | — | 0.25 | ||||||||||
Average realized price (per Mcf) | $ | 4.73 | $ | 3.92 | 21 | % | ||||||
Gulf of Mexico (per Mcf) | 4.50 | 3.54 | ||||||||||
North Sea (per Mcf) | 6.46 | 5.38 | ||||||||||
Oil, condensate and natural gas (per Boe) | $ | 52.09 | $ | 45.84 | 14 | % | ||||||
Effects of cash flow hedges (per Boe) | — | 0.66 | ||||||||||
Average realized price (per Boe) | $ | 52.09 | $ | 46.50 | 12 | % | ||||||
Gulf of Mexico (per Boe) | 52.76 | 47.75 | ||||||||||
North Sea (per Boe) | 39.01 | 33.92 |
30
Table of Contents
Revenues from production increased in 2010 compared to 2009 due to a 38% increase in production and a 12% increase in average realized sales price. The production increase occurred primarily in the Gulf of Mexico where our Canyon Express property has been returned to production and where we now have production at the Telemark Hub. 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 2009 to 2010 | |||||||||||
2010 | 2009 | |||||||||||
Recurring operating expenses | $ | 21,575 | $ | 17,081 | 26 | % | ||||||
Workover expenses | 5,918 | 5,810 | 2 | % | ||||||||
Lease operating | $ | 27,493 | $ | 22,891 | 20 | % | ||||||
Recurring operating expenses per Boe | $ | 11.10 | $ | 12.12 | (8 | )% | ||||||
Gulf of Mexico | 10.92 | 12.24 | (11 | )% | ||||||||
North Sea | 15.18 | 11.10 | 37 | % |
Lease operating expense for the third quarter of 2010 increased $4.6 million compared to the third quarter of 2009. The increase in recurring operating expense was primarily due to the new production from the Telemark and Canyon Express Hubs and due to additional insurance costs. The workover expenses during the third quarter of 2010 were primarily due to pipeline and facilities inspection activities on our Gomez Hub and other Gulf of Mexico properties. The Gulf of Mexico per unit cost has decreased primarily due to the effect of fixed costs spread over higher production. The North Sea per unit cost has increased primarily due to the effect of fixed costs spread over lower production.
General and Administrative
General and administrative expenses are overhead-related expenses, including employee compensation, legal and accounting fees, insurance (other than that included in lease operating expense) and investor relations expenses. General and administrative expense was as follows:
Three Months Ended September 30, | % Change from 2009 to 2010 | |||||||||||
2010 | 2009 | |||||||||||
General and administrative (in thousands) | $ | 9,644 | $ | 6,945 | 39 | % | ||||||
Per Boe | 4.96 | 4.92 | 1 | % |
General and administrative expense increased $2.7 million compared to the third quarter of 2009. The increase was primarily due to higher net compensation expense and professional fees. The per-unit cost has decreased primarily due to the effect of fixed costs spread over higher production.
31
Table of Contents
Depreciation, Depletion and Amortization
Depreciation, depletion and amortization (“DD&A”) expense was as follows:
Three Months Ended September 30, | % Change from 2009 to 2010 | |||||||||||
2010 | 2009 | |||||||||||
DD&A (in thousands) | $ | 62,505 | $ | 37,460 | 67 | % | ||||||
Per Boe | 32.15 | 26.64 | 21 | % | ||||||||
Gulf of Mexico | 31.85 | 25.20 | 26 | % | ||||||||
North Sea | 37.98 | 41.16 | (8 | %) |
DD&A expense for the third quarter of 2010 increased $25.0 million compared to the third quarter of 2009 primarily due to the commencement of production at the 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 decrease in the North Sea is primarily due to increases in reserves.
Impairment of Oil and Gas Properties
We recorded impairment during the three months ended September 30, 2010 of $3.0 million. This amount represented the remaining carrying cost of a proved property that is no longer economic as a result of lower gas prices. No impairment was recorded for the same period during the prior year.
Accretion of Asset Retirement Obligation
Accretion expense in the third quarter of 2010 increased to $3.6 million compared to $3.0 million in the third quarter of 2009 primarily due to the addition of the future retirement obligations associated with our Telemark Hub.
Loss on Abandonment
No significant loss on abandonment was recorded in the third quarter of 2010, compared to $1.9 million in the third quarter of 2009. The 2009 amount was 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, was $69.2 million in the third quarter of 2010 compared to $9.0 million in the third quarter of 2009. In the third quarter of 2010, we capitalized interest of $3.3 million (related to our Cheviot development in the U.K.) compared to the third quarter of 2009 capitalized interest of $27.7 million ($25.7 million related to our Telemark Hub development and $2.0 million related to Cheviot). Interest expense has increased primarily for three reasons: (i) production commenced at Telemark Hub and we ceased capitalizing related interest costs as a consequence, (ii) due to higher other long-term obligations, (iii) in the second quarter of 2010, we refinanced our long-term debt and increased our outstanding debt balance.
Derivative Income
Derivative income (expense) during the third quarter of 2010 was ($12.7) million consisting of ($14.9) million in the Gulf of Mexico and $2.2 million in the North Sea. Derivative income (expense) during the third quarter of 2009 was ($3.5) million consisting of ($5.6) million and $2.1 million in the Gulf of Mexico and North Sea, respectively. This expense is related to net losses associated with our oil and gas price derivative contracts.
32
Table of Contents
Income Tax (Expense) Benefit
We recorded income tax benefit of $19.9 million during the third quarter of 2010 resulting in an overall effective tax rate of 28%. In each jurisdiction, the rates were determined based on our expectations of net income or loss for the year, taking into consideration permanent differences. In the comparable quarter of 2009 we recorded income tax benefit of $4.4 million resulting in an overall effective tax rate of 44%.
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 in 2010 represent declared dividends payable in cash due for the three months ended September 30, 2010. The outstanding shares of convertible preferred stock accrue cumulative preferred dividends at the annual rate of 8% of the $140.0 million aggregate liquidation value.
33
Table of Contents
Nine Months Ended September 30, 2010 Compared to Nine Months Ended September 30, 2009
For the nine months ended September 30, 2010 and 2009 we reported net loss attributable to common shareholders of $142.2 million and $11.9 million, or $2.81 and $0.30 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 related to the second quarter 2008 sale of the limited-term overriding royalty interest. We do not reflect any production volumes associated with those revenues.
Nine Months Ended September 30, | % Change from 2009 to 2010 | |||||||||||
2010 | 2009 | |||||||||||
Production: | ||||||||||||
Oil and condensate (MBbl) | 2,933 | 2,605 | 13 | % | ||||||||
Natural gas (MMcf) | 14,665 | 12,113 | 21 | % | ||||||||
Total (MBoe) | 5,377 | 4,623 | 16 | % | ||||||||
Gulf of Mexico (MBoe) | 4,964 | 4,233 | 17 | % | ||||||||
North Sea (MBoe) | 413 | 390 | 6 | % | ||||||||
Revenues from production (in thousands): | ||||||||||||
Oil and condensate | $ | 206,070 | $ | 139,333 | 48 | % | ||||||
Amortization of deferred revenue | 17,819 | 26,350 | ||||||||||
Total | $ | 223,889 | $ | 165,683 | 35 | % | ||||||
Natural gas | $ | 70,843 | $ | 50,942 | 39 | % | ||||||
Effects of cash flow hedges | — | 1,493 | ||||||||||
Amortization of deferred revenue | 1,517 | 6,045 | ||||||||||
Total | $ | 72,360 | $ | 58,480 | 24 | % | ||||||
Oil, condensate and natural gas | $ | 276,913 | $ | 190,275 | 46 | % | ||||||
Effects of cash flow hedges | — | 1,493 | ||||||||||
Amortization of deferred revenue | 19,336 | 32,395 | ||||||||||
Total | $ | 296,249 | $ | 224,163 | 32 | % | ||||||
Average realized sales price: | ||||||||||||
Oil and condensate average realized price (per Bbl) | $ | 70.26 | $ | 53.49 | 31 | % | ||||||
Natural gas (per Mcf) | $ | 4.83 | $ | 4.21 | 15 | % | ||||||
Effects of cash flow hedges (per Mcf) | — | 0.12 | ||||||||||
Average realized price (per Mcf) | $ | 4.83 | $ | 4.33 | 12 | % | ||||||
Gulf of Mexico (per Mcf) | 4.65 | 4.08 | ||||||||||
North Sea (per Mcf) | 5.72 | 5.39 | ||||||||||
Oil, condensate and natural gas (per Boe) | $ | 51.50 | $ | 41.16 | 25 | % | ||||||
Effects of cash flow hedges (per Boe) | — | 0.30 | ||||||||||
Average realized price (per Boe) | $ | 51.50 | $ | 41.46 | 24 | % | ||||||
Gulf of Mexico (per Boe) | 52.87 | 42.33 | ||||||||||
North Sea (per Boe) | 35.02 | 32.14 |
Revenues from production increased in 2010 compared to 2009 due to a 24% increase in average realized sales price and a 16% increase in production. The higher average realized sales price is due to increased commodity market prices. The production increase occurred primarily in the Gulf of Mexico where our Canyon Express property has been returned to production and where we now have production at the Telemark Hub.
34
Table of Contents
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):
Nine Months Ended September 30, | % Change from 2009 to 2010 | |||||||||||
2010 | 2009 | |||||||||||
Recurring operating expenses | $ | 65,391 | $ | 44,318 | 48 | % | ||||||
Workover expenses | 24,032 | 16,145 | 48 | % | ||||||||
Lease operating | $ | 89,423 | $ | 60,463 | 48 | % | ||||||
Recurring operating expenses per Boe | $ | 12.18 | $ | 9.60 | 27 | % | ||||||
Gulf of Mexico | 12.24 | 9.90 | 24 | % | ||||||||
North Sea | 11.22 | 5.88 | 91 | % |
Lease operating expense for the first nine months of 2010 increased $29.0 million compared to the first nine months of 2009. The increase in recurring operating expense was primarily due to the new production from the Telemark and Canyon Express Hubs. The workover expenses during the first nine months of 2010 were primarily due to inspection activities on many of our Gulf of Mexico properties and hydrate remediation activities on our Canyon Express Hub property, which enabled us to commence production at our new well at Kings Peak (MC Block 217) and to re-establish production from two wells at Aconcagua (MC Block 305). The workover expenses for the first nine months of 2009 included Hurricane Ike repairs and non-routine surveys for properties in the North Sea. Per unit costs for both the Gulf of Mexico and North Sea have increased primarily due to increased operating costs, as discussed above.
General and Administrative
General and administrative expenses are overhead-related expenses, including employee compensation, legal and accounting fees, insurance (other than that included in lease operating expense) and investor relations expenses. General and administrative expense was as follows:
Nine Months Ended September 30, | % Change from 2009 to 2010 | |||||||||||
2010 | 2009 | |||||||||||
General and administrative (in thousands) | $ | 29,213 | $ | 25,153 | 16 | % | ||||||
Per Boe | 5.43 | 5.46 | (1 | %) |
General and administrative expense increased $4.1 million from the first nine months of 2009. The increase was primarily due to a net increase in compensation expense and higher professional fees.
Depreciation, Depletion and Amortization
Depreciation, depletion and amortization (“DD&A”) expense was as follows:
Nine Months Ended September 30, | % Change from 2009 to 2010 | |||||||||||
2010 | 2009 | |||||||||||
DD&A (in thousands) | $ | 158,621 | $ | 120,433 | 32 | % | ||||||
Per Boe | 29.50 | 26.04 | 13 | % | ||||||||
Gulf of Mexico | 28.96 | 24.07 | 20 | % | ||||||||
North Sea | 35.99 | 47.48 | (24 | %) |
35
Table of Contents
DD&A expense for the first nine months of 2010 increased $38.2 million compared to the first nine months of 2009 primarily due to the commencement of production at 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 decrease in the North Sea is primarily due to increases in reserves.
Impairment of Oil and Gas Properties
We recorded impairments during the nine months ended September 30, 2010 and 2009 of $15.1 million and $8.7 million, respectively. Of these amounts, $4.5 million and $0.7 million in the nine months ended September 30, 2010 and 2009, respectively, were related to unproved properties in the Gulf of Mexico. The 2010 amounts were associated with leases which were approaching their expiration dates and became unlikely to be drilled. We recorded impairments of proved properties during the nine months ended September 30, 2010 and 2009 of $10.6 million and $8.0 million, respectively. These amounts represented the excess of the carrying costs over the fair value of two and one Gulf of Mexico properties in the first nine months of 2010 and 2009, respectively.
Accretion of Asset Retirement Obligation
Accretion expense in the first nine months of 2010 increased to $10.4 million compared to $8.9 million in the first nine months of 2009 primarily due to the addition of the future retirement obligations associated with our Telemark Hub.
Contract Termination Costs
During June 2010, we terminated a contract for services of a drilling rig as a result of Moratorium I discussed above. We obtained a full release from our obligations under the contract. We incurred net costs of $8.7 million as a result of terminating this contract.
Loss on Abandonment
Loss on abandonment was $0.2 million and $2.9 million during the first nine months of 2010 and 2009, 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 undeveloped 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 was $146.1 million in the first nine months of 2010 compared to $31.8 million in the first nine months of 2009. In the first nine months of 2010, we capitalized interest of $49.6 million ($40.4 million related to the construction of our Telemark Hub development in the Gulf of Mexico and $9.2 million related to our Cheviot development in the U.K.) compared to the first nine months of 2009 capitalized interest of $71.5 million ($66.7 million related to Telemark Hub and $4.8 million related to Cheviot). Interest expense has increased primarily for three reasons: (i) production commenced at Telemark Hub and we ceased capitalizing related interest costs as a consequence, (ii) due to higher other long-term obligations, (iii) in the second quarter of 2010, we refinanced our long-term debt and increased our outstanding debt balance.
36
Table of Contents
Derivative Income
Derivative income (expense) during the first nine months of 2010 was $14.8 million consisting of $18.0 million in the Gulf of Mexico and ($3.2) million in the North Sea. Derivative income during the first nine months of 2009 was $15.0 million consisting of $7.6 million and $7.4 million in the Gulf of Mexico and North Sea, respectively. This income is related to net gains associated with our oil and gas price derivative contracts.
Loss on Debt Extinguishment
Loss on debt extinguishment was $78.2 million for the first nine months of 2010. As discussed below, during the second quarter of 2010 we refinanced our previously outstanding term loans and charged to expense the remaining unamortized deferred financing costs, debt discount related to the retired debt and repayment premiums.
Income Tax (Expense) Benefit
We recorded income tax benefit of $76.3 million during the nine months ended September 30, 2010 resulting in an overall effective tax rate of 39%. In each jurisdiction, the rates were determined based on our expectations of net income or loss for the year, taking into consideration permanent differences. In the comparable period of 2009 we recorded income tax benefit of $4.1 million resulting in an overall effective tax rate of 68%. The effective tax rate for both periods differs from the statutory rates primarily because taxes are not provided for the noncontrolling interest of ATP-IP.
Income Attributable to the Redeemable Noncontrolling Interest
Income attributable to the redeemable noncontrolling interest represents the 49% Class A limited partner interest in the earnings of ATP-IP. The amount of $12.4 million in the first nine months of 2010 is higher than the amount of $9.8 million in the first nine months of 2009 primarily because of the inception of this arrangement in the middle of the first quarter of 2009.
Convertible Preferred Stock Dividends
Convertible preferred stock dividends in 2010 represent declared dividends payable in cash due for the nine months ended September 30, 2010. The outstanding shares of convertible preferred stock accrue cumulative preferred dividends at the annual rate of 8% of the $140.0 million aggregate liquidation value.
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. The disarray in the credit markets that began in 2008 has continued into 2010. Capital market transactions are limited and when they can be completed they are more expensive than similar transactions prior to 2008. Despite this, so far in 2010, we have refinanced our long-term debt and obtained additional financing from other transactions, all of which are discussed below.
We project a substantial increase in production over the next year as development wells are brought to production. Absent alternative funding sources, achieving our projected production growth is necessary to provide the cash flow required to fund our capital plan and meet our existing obligations, both over the next twelve months and on a longer-term basis. Our ability to execute our plan depends, in part, on our ability to continue drilling for and producing hydrocarbons in the Gulf of Mexico. Our plan is currently based upon obtaining necessary drilling permits, and successfully achieving commercial production from existing wells presently scheduled to commence during the remainder of 2010 and 2011. Delays from difficulties receiving necessary permits, reduced access to equipment and services, or bad weather, could have a material adverse effect on our financial position, results of operations and cash flows. In addition to the risks associated with achieving our projected production growth, additional regulatory requirements and increased costs for which funding must be secured, or a negative change in commodity prices and operating cost levels, could also have a material adverse effect on our financial position, results of operations and cash flows. While we are pursuing various other sources of funding, there is no assurance that these alternative sources will be available should any of the above risks or uncertainties materialize.
We have conveyed to certain vendors and financial parties dollar-denominated net profits interests and overriding royalty interests in our Telemark Hub and Gomez Hub 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 until after the beginning of production. These net profits interests and deferrals allow us to match our development cost cash flows with those from production.
In April 2010, we entered into a first lien revolving credit facility (the “Original Credit Facility”) with an initial borrowing base of $100.0 million, due April 23, 2013, and issued senior second lien notes (the “Notes”) in an aggregate principal amount of $1.5 billion, due May 1, 2015. We used proceeds from the Notes to repay the entire amount due under our term loans previously outstanding.
In June 2010, we entered into a new first lien credit agreement (the “New Credit Facility”) for $150.0 million, due October 15, 2014, to replace the Original Credit Facility. Proceeds of the New Credit Facility
37
Table of Contents
were $144.3 million, net of original issue discount and transaction fees. The New Credit Facility allows the Company to incur up to $350.0 million of additional indebtedness as Consolidated Net Tangible Assets increase.
In September 2010, we formed ATP Titan LLC (“Titan LLC”), a wholly owned and operated subsidiary, and transferred to it our 100% ownership of theATP Titan platform and related infrastructure assets at their carryover cost basis. Simultaneous with the transfer, we entered into a $350.0 million term loan facility (the “ATP TitanFacility”), of which $150.0 million was drawn initially. At closing, we received proceeds of $140.8 million net of discount and direct issuance costs. There are provisions in theATP TitanFacility under which the undrawn balance may be funded upon our request and subject to lender approval based on first production from wells at Telemark Hub as follows: $100.0 million from the second well and $50.0 million each from the third and fourth wells.
During the first nine months of 2010, we sold overriding royalty interests which are primarily dollar denominated in future production from our Gomez Hub properties for cash proceeds of $121.1 million, net of costs. The dollar-denominated overriding royalty interests obligate us to deliver proceeds from the future sale of hydrocarbons from the specified properties equal to the purchasers’ original investment, plus an overall rate of return. The percentage of property revenues available to satisfy these obligations is dependent upon certain conditions specified in the agreement. Upon payment of the agreed dollar amounts, the ownership of the dollar-denominated interests reverts to us.
Also during the first nine months of 2010, we granted dollar-denominated overriding royalty interests in the form of net profits interests in certain of our oil and gas properties in and around the Telemark Hub and Gomez Hub to certain of our vendors in exchange for oil and gas property development services and cash. The interests earned by the vendors 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, there is no payment required.
In the Gulf of Mexico, in addition to the net profits interests exchanged for development services and cash described above, we have negotiated with certain other vendors involved in the development of the Telemark and Gomez Hubs to partially defer payments until after production has begun. In the U.K. North Sea, development of our interest in the Cheviot field continues and we have arranged with the fabricator of the floating production and drilling facility to defer $99 million of payments until construction is complete, which is expected to be in the fourth quarter of 2011.
For the remainder of 2010, we anticipate incurring $60 to $70 million in total capital expenditures of which $45 to $50 million will be cash with the balance contributed by suppliers through existing NPI programs or deferral programs. Because of the uncertainty associated with the regulatory environment, our capital expenditures could increase or decrease from these levels. 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. Due to that control, we believe we have sufficient liquidity to enable us to meet our future capital and debt service requirements.
In the near term, our revenues, profitability and cash flows are highly dependent upon many factors, particularly our ability to bring other major development projects at Telemark Hub on production, performance of other properties and the price of oil and natural gas. To mitigate future price volatility, we may continue to hedge the sales price of a portion of our future production.
For the longer term, we will continue to deploy the same or similar strategies. Operating our properties has always been a significant focus of our strategy. We believe operating our properties provides us the ability to control expenditures and adjust development timing and programs where needed. We do not expect to see a significant change in this focus over the next several years.
Cash Flows
Nine Months Ended September 30, | ||||||||
2010 | 2009 | |||||||
Cash provided by (used in) (in thousands): | ||||||||
Operating activities | $ | 2,389 | $ | 125,232 | ||||
Investing activities | (498,422 | ) | (472,643 | ) | ||||
Financing activities | 593,800 | 442,498 |
We had working capital deficits of approximately $26.8 million and $26.4 million as of September 30, 2010 and December 31, 2009, respectively.
Cash provided by operating activities during the nine months ended September 30, 2010 and 2009 was $2.4 million and $125.2 million, respectively. Cash flow from operating activities has decreased primarily due to increased interest expense, costs related to extinguishment of the long-term debt and lease operating expenses and decreased favorable derivative settlements partially offset by increased oil and gas revenues discussed above and changes in working capital.
Cash used in investing activities was $498.4 million and $472.6 million during the nine months ended September 30, 2010 and 2009, respectively. 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, in 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 $391.0 million and $74.1 million, respectively, in the first nine months of 2009.
38
Table of Contents
Cash provided by financing activities was $593.8 million and $442.5 million during the nine months ended September 30, 2010 and 2009, respectively. The amount in the first nine months of 2010 is primarily related to $336.4 million net proceeds from the debt refinancing and 140.8 million net proceeds from the term loan facility—Titanassets discussed in Note 6, “Long-term Debt” to the Consolidated Financial Statements, $46.0 million net proceeds from our prior revolving credit facility, $170.6 million proceeds net of costs from sales of limited-term overriding royalty interests and net profit interests discussed in Note 7, “Other Long-term Obligations,” to the Consolidated Financial Statements, partially offset by principal payments toward our other long-term obligations and previously outstanding term loans. The amount in the first nine months of 2009 is from the sale of redeemable noncontrolling interest in ATP-IP for $148.8 million, the issuance of common and preferred stock for $297.1 million and the monetization of the Gomez Hub pipeline for $74.5 million partially offset by $61.3 million of debt repayments and $15.4 million of distributions to the limited partners in ATP-IP.
Long-term Debt
Long-term debt consisted of the following (in thousands):
September 30, 2010 | December 31, 2009 | |||||||
First lien term loans, net of $2,820 unamortized discount | $ | 147,180 | $ | — | ||||
Senior second lien notes, net of $6,420 unamortized discount | 1,493,580 | — | ||||||
Term loan facility—ATP Titanassets, net of $6,723 unamortized discount | 143,277 | — | ||||||
Term Loans, net of $28,266 unamortized discount | — | 1,216,685 | ||||||
Total debt | 1,784,037 | 1,216,685 | ||||||
Less current maturities | (10,867 | ) | (16,838 | ) | ||||
Total long-term debt | $ | 1,773,170 | $ | 1,199,847 | ||||
In April 2010, we entered into a first lien revolving credit facility (the “Original Credit Facility”) with an initial borrowing base of $100.0 million, due April 23, 2013, and issued senior second lien notes (the “Notes”) in an aggregate principal amount of $1.5 billion, due May 1, 2015. We used proceeds from the Notes to repay the entire amount due under our term loans previously outstanding and subsequently replaced the Original Credit Facility with the New Credit Facility, discussed below
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. In connection with the issuance of the Notes, we granted registration rights to the holders of the Notes and agreed to register the Notes with the SEC within 270 days of their initial issuance. The Notes were issued at 99.531% of their face amount to yield 12.0% and we incurred issuance costs of $38.2 million.
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 new first lien credit agreement (the “New Credit Facility”) with an initial balance of $150.0 million, due May 15, 2014, to replace the Original Credit Facility. Proceeds of the New Credit Facility were $144.3 million, net of original issue discount and transaction fees. Principal outstanding under the term loans issued pursuant to the New Credit Facility bears interest at an annual rate of 11.0%. As security for the Company’s obligations under the New Credit Facility, the Company granted the lenders a
39
Table of Contents
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. Principal of $750,000 is due each June and December beginning December 18, 2010 until June 18, 2014. The remaining principal balance is due October 15, 2014. The New Credit Facility allows the Company to incur up to $350.0 million of additional indebtedness as Consolidated Net Tangible Assets (as defined in the New Credit Facility) increase, although the lender is not yet committed to fund additional amounts .
The Notes and New 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 Titan LLC, a wholly owned and operated subsidiary, and transferred to it our 100% ownership of theATP Titan platform and related infrastructure assets at their carryover cost basis. Simultaneous with the transfer, we entered into a $350.0 million term loan facility (the “ATP TitanFacility”), of which $150.0 million was drawn initially. At closing, we received proceeds of $140.8 million net of discount and direct issuance costs. There are provisions in theATP Titan Facility under which the undrawn balance may be funded upon our request and subject to lender approval based on first production from wells at our Telemark Hub as follows: $100.0 million from the second well and $50.0 million each from the third and fourth wells. TheATP Titan Facility is to be repaid quarterly as follows: annual principal reductions of 8% in the first year, 9% in the second year and 10% thereafter until maturity in September 2017. TheATP Titan Facility bears interest at LIBOR (floor of 0.75%) plus 8%. 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 TitanFacility 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. The Company does not guarantee the debt of Titan LLC. 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 New Credit Facility and the Notes contain customary events of default, and if certain of those events of default were to occur and remain incurred, such as a failure to pay principal or interest when due, our lenders could terminate future lending commitments under the New Credit Facility, and our lenders could declare the outstanding borrowings due and payable. The New 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 of our long-term debt was 12.3% at September 30, 2010. The fair value of the aggregate long-term debt as of September 30, 2010 was approximately $1.6 billion.
40
Table of Contents
Contractual Obligations
The following table summarizes certain contractual obligations at September 30, 2010 (in thousands):
Total | Less than 1 year | 1–3 years | 3–5 years | More than 5 years | ||||||||||||||||
First lien term loans | $ | 150,000 | $ | 1,500 | $ | 3,000 | $ | 145,500 | $ | — | ||||||||||
Interest on first lien term loans (1) | 65,341 | 16,418 | 32,340 | 16,583 | — | |||||||||||||||
Senior second lien notes | 1,500,000 | — | — | 1,500,000 | — | |||||||||||||||
Interest on senior second lien notes (1) | 816,406 | 178,125 | 356,250 | 282,031 | — | |||||||||||||||
Term loan facility—Titan assets | 150,000 | 9,367 | 27,904 | 30,000 | 82,729 | |||||||||||||||
Interest on term loan facility—ATP Titan assets (1) | 61,963 | 12,710 | 21,172 | 17,025 | 11,056 | |||||||||||||||
Other long-term obligations (2) | 208,048 | 45,401 | 124,314 | 20,000 | 18,333 | |||||||||||||||
Other trade commitments | 15,570 | 13,320 | 2,250 | — | — | |||||||||||||||
Noncancelable operating leases | 1,112 | 821 | 291 | — | — | |||||||||||||||
Total contractual obligations | $ | 2,968,440 | $ | 277,662 | $ | 567,521 | $ | 2,011,139 | $ | 112,118 | ||||||||||
(1) | Interest is based on rates and principal repayment requirements in effect at September 30, 2010. |
(2) | Omitted from other long-term obligations in this table are $275.3 million of net profits interests payable and overriding royalty interests of $81.1 million as of September 30, 2010 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. Included in the table above are $24.5 million of contractual commitments that are expected to be paid that are not yet incurred. |
Our liabilities include asset retirement obligations (“ARO”) ($47.0 million current and $111.8 million long-term) that represent our estimate of the amount at September 30, 2010 of our obligations with respect to the retirement/plugging and abandonment of our oil and gas properties. The ultimate settlement amounts and the timing of the settlements of such obligations are uncertain because they are subject to, among other things, federal, state and local regulation, economic and operational factors. Consequently, ARO is not reflected in the table above.
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. Although it is difficult to predict the ultimate outcome of these matters, we are not aware of any amounts that need to be recorded as of September 30, 2010. See Note 12, “Commitments and Contingencies” to Consolidated Financial Statements in Item 1 for additional discussion.
Accounting Pronouncements
See Note 2, “Recent Accounting Pronouncements” to Consolidated Financial Statements in Item 1 for a discussion of recently issued accounting pronouncements.
Critical Accounting Policies
Our discussion and analysis of our financial condition and results of operations are based on consolidated financial statements which have been prepared in accordance with generally accepted accounting principles in the United States of America. The preparation of these financial statements requires us to make estimates and
41
Table of Contents
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 2009 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 our Term loan facility—Titanassets as described in Management’s Discussion and Analysis of Financial Condition and Results of Operations: Liquidity and Capital Resources and in Note 6, “Long-term Debt” to Consolidated Financial Statements in Item 1. Otherwise we have no exposure to changes in interest rates because the interest rate 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 and operations due to fluctuations in the value of the local currency relative to the U.S. dollar arising from the process of re-measuring the local 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. See Note 11, “Derivative Instruments and Risk Management Activities” to Consolidated Financial Statements in Item 1.
We may enter into short-term hedging arrangements if (1) we are able to obtain commodity contracts at prices sufficient to secure an acceptable internal rate of return on a particular property or on a group of properties, or (2) if deemed necessary by the terms of our credit agreements. We do not hold or issue derivative instruments for speculative purposes.
Item 4. | Controls and Procedures |
Evaluation of Disclosure Controls and Procedures
Our management, under the supervision of and with the participation of our chief executive officer and chief financial officer has 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, 2010 (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 not effective as of the Evaluation Date due to the material weakness in internal control over financial reporting identified at December 31, 2009 as described below which continues to exist as of the Evaluation Date. Disclosure controls and procedures are those controls and procedures designed to provide reasonable assurance 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.
42
Table of Contents
In preparing our Exchange Act filings, including this Quarterly Report on Form 10-Q, we implemented additional processes and procedures to provide reasonable assurance that the identified material weakness in our internal control over financial reporting was mitigated with respect to the information that we are required to disclose. As a result, we believe the Company’s consolidated financial statements included in this Quarterly Report on Form 10-Q present fairly, in all material respects, the Company’s financial position, results of operations and cash flows for the periods presented.
Material Weakness in Internal Control over Financial Reporting
A material weakness is a deficiency, or combination of deficiencies, such that there is a reasonable possibility that a material misstatement of the annual or interim financial statements will not be prevented or detected on a timely basis. At December 31, 2009, we identified the following material weakness which continues to exist as of the Evaluation Date:
We did not maintain effective controls over accounting for outstanding liabilities. Specifically, our procedures were not adequate to ensure proper cut-off associated with goods received or services rendered by our vendors and that liabilities and the associated capital additions were recorded in the appropriate periods.
Changes in Internal Control Over Financial Reporting
During the three months ended September 30, 2010, 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.
Remediation Plan
We believe that the material weakness identified at December 31, 2009 was attributable to factors caused by the substantial activity at year-end 2009 focused on the completion of our major development project at our Telemark Hub. During the first quarter, we emphasized the importance of the accrual process with all employees who are integral to the accruals process and we enhanced our processes to address such changes in activity by implementing new procedures to seek out sufficient information related to major vendor activities at each balance sheet date to ensure that we have proper cut-off when preparing capital accruals. We also implemented secondary reviews of the accruals to ensure the reasonableness of the accruals as of the balance sheet date. In the second quarter we refined the changes introduced in the prior quarter and further introduced a process to increase accountability from certain key employees in the accrual process. We believe those process changes have adequately improved our controls over accounting for outstanding liabilities but will perform additional tests in future periods to ensure the controls around this area are operating effectively. After performing additional tests, we will evaluate the effectiveness of those controls in order to conclude if the material weakness has been remediated.
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 2009 Annual Report on Form 10-K with additional factors discussed in Item 1A of this Quarterly Report.
43
Table of Contents
Items 2, 3, 4 and 5 are not applicable and have been omitted.
Item 1. | Legal Proceedings |
No material changes in any legal proceeding have occurred since our last report.
Item 1A. | Risk Factors |
As of the date of this filing, there have been no material changes from the risk factors previously disclosed in Part 1, Item 1A, of the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2009, except as follows:
The U.S. governmental and regulatory response to the Deepwater Horizon drilling rig accident and resulting oil spill could have a prolonged and material adverse impact on our Gulf of Mexico operations.
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 the Minerals Managements Service (“MMS”) 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 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 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.
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 Bureau of Ocean Energy Management, Regulation and Enforcement (“BOEM”), successor to the MMS, 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 BOEM. The DOI’s order lifting Moratorium II, however, also requires OCS lessees and operators to comply with BOEM’s 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 BOEM in September 2010. The Final Workplace Safety Rule requires all OCS operators to implement all of the
44
Table of Contents
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. Although Moratorium II has been lifted, we cannot predict with certainty when permits will be granted under the new requirements.
There is also legislation pending in both houses of the U.S. Congress that, if enacted, would significantly impact oil and gas operations on the OCS. In the U.S. House of Representatives, H.R. 3534 proposes to impose numerous new requirements on OCS operations, including increased performance standards for BOPs, disqualification of certain companies from bidding on federal leases or drilling OCS wells, and requirements for documented blowout scenarios in OCS exploration plans. There is also pending in the U.S. Senate a bill that contains some of the same provisions contained in the H.R. 3534. If ultimately enacted, these bills will require higher insurance levels, increased liability exposure, additional fees on production, as well as numerous additional operating constraints and procedures.
We cannot predict how federal and state authorities will further respond to the incident in the Gulf of Mexico or whether additional changes in laws and regulations governing oil and gas operations in the Gulf of Mexico will result. New regulations already issued will, and potential future regulations or additional statutory limitations, if enacted or issued, could, require a change in the way we conduct our business, increase our costs of doing business or ultimately prohibit us from drilling for or producing hydrocarbons in the Gulf of Mexico. We cannot predict if or how the governments of other countries in which we operate will respond to the accident in the Gulf of Mexico.
We have ongoing and planned drilling operations in the deepwater Gulf of Mexico, some of which were permitted prior to April 20, 2010, and some of which are not yet permitted. Such permits, among other required approvals, are necessary prior to commencement of offshore drilling operations. Moratorium II has caused us to delay the third and fourth wells scheduled at our Telemark Hub and, even though Moratorium II has been lifted, any delays in the resumption of the permitting process may result in delays in our drilling operations scheduled in 2011 at our Gomez Hub. During June 2010, we agreed to terminate a contract for services of a drilling rig as a result of Moratorium I. Under the termination agreement, we obtained a full release from our obligations under the contract and incurred net costs of $8.7 million reflected as contract termination costs on the statement of operations.
We project a substantial increase in production over the next year as development wells are brought to production. Absent alternative funding sources, achieving our projected production growth is necessary to provide the cash flow required to fund our capital plan and meet our existing obligations, both over the next twelve months and on a longer-term basis. Our ability to execute our plan depends, in part, on our ability to continue drilling for and producing hydrocarbons in the Gulf of Mexico. Our plan is currently based upon obtaining necessary drilling permits, and successfully achieving commercial production from existing wells presently scheduled to commence during the remainder of 2010 and 2011. Delays from difficulties receiving necessary permits, reduced access to equipment and services, or bad weather, could have a material adverse effect on our financial position, results of operations and cash flows. In addition to the risks associated with achieving our projected production growth, additional regulatory requirements and increased costs for which funding must be secured, or a negative change in commodity prices and operating cost levels, could also have a material adverse effect on our financial position, results of operations and cash flows. While we are pursuing various other sources of funding, there is no assurance that these alternative sources will be available should any of the above risks or uncertainties materialize.
45
Table of Contents
Potential regulations under the Dodd-Frank Act regarding derivatives could adversely impact our ability to engage in commodity price risk management activities.
We enter into commodity derivative contracts in order to hedge a portion of our natural gas production. On July 21, 2010, Congress enacted the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”), which imposes a comprehensive regulatory scheme significantly impacting companies engaged in over-the-counter (“OTC”) swap transactions. The Dodd-Frank Act generally applies to “swaps” entered into by “major swap participants” and/or “swap dealers”, each as defined in the Dodd-Frank Act. A swap is very broadly defined in the Dodd-Frank Act and includes an energy commodity swap. A swap dealer includes an entity that regularly enters into swaps with counterparties as an “ordinary course of business for its own account.” Furthermore, a person may qualify as a major swap participant if it maintains a “substantial position” in outstanding swaps, other than swaps used for “hedging or mitigating commercial risk” or whose positions create substantial exposure to its counterparties or the U.S. financial system. The Dodd-Frank Act subjects swap dealers and major swap participants to substantial supervision and regulation by the Commodity Futures Trading Commission (“CFTC”), including capital standards, margin requirements, business conduct standards, and recordkeeping and reporting requirements. It also requires most regulated swaps to be cleared through a derivatives clearing organization (“DCO”) registered with the CFTC. By clearing through a DCO, each party to a swap will be required to provide collateral to the DCO to settle, on a daily basis, any credit exposure resulting from fluctuations in market prices. The CFTC also has the authority to impose position limits on companies trading in OTC derivatives markets. Although the Dodd-Frank Act provides a framework for regulating OTC swap transactions, the substance of the Act will be set forth in numerous rules subsequently promulgated by the CFTC and other agencies. Because the CFTC has not yet clearly articulated the scope of key definitions in the Dodd-Frank Act, such as “swap”, “swap dealer” and “major swap participant”, and because the parameters of Dodd-Frank Act requirements are still shifting, it is impossible to know exactly how the Dodd-Frank Act will impact our business. However, the issuance of any rules or regulations relating to the Dodd-Frank Act that subject us to additional business conduct standards, position limits and/or reporting, capital, margin or clearing requirements with respect to our energy commodity swap risk management positions could have an adverse effect on our ability to hedge risks associated with our business or on the cost of our hedging activities. If we are required to post collateral as a result of new rules, we would have to do so by utilizing cash or letters of credit, which would reduce our liquidity position and increase costs. These changes could materially reduce our hedging opportunities and increase the costs associated with our hedging programs, both of which could negatively affect our cash flow.
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 | 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 | 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. | |
4.2 | 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. |
46
Table of Contents
4.3 | 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. | |
10.1 | 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. | |
10.2 | 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. | |
10.3 | 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. | |
†10.4 | ATP Oil & Gas Corporation 2010 Stock Plan incorporated by reference to Appendix A to ATP’s Schedule 14A dated April 29, 2010. | |
10.5 | 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. | |
10.6 | 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. | |
†10.7 | Employment Agreement between ATP and Pauline H. van der Sman-Archer, dated December 29, 2005, incorporated by reference to Exhibit 10.1 to ATP’s Form 8-K dated December 30, 2005. | |
†10.8 | Employment Agreement between ATP and John E. Tschirhart, dated December 29, 2005, incorporated by reference to Exhibit 10.2 to ATP’s Form 8-K dated December 30, 2005. | |
†10.9 | Employment Agreement between ATP and Leland E. Tate, dated December 29, 2005, incorporated by reference to Exhibit 10.3 to ATP’s Form 8-K dated December 30, 2005. | |
†10.10 | Employment Agreement between ATP and Robert M. Shivers, III, dated December 29, 2005, incorporated by reference to Exhibit 10.4 to ATP’s Form 8-K dated December 30, 2005. | |
†10.11 | Employment Agreement between ATP and Mickey W. Shaw, dated December 29, 2005, incorporated by reference to Exhibit 10.5 to ATP’s Form 8-K dated December 30, 2005. | |
†10.12 | Employment Agreement between ATP and Albert L. Reese, Jr., dated December 29, 2005, incorporated by reference to Exhibit 10.7 to ATP’s Form 8-K dated December 30, 2005. | |
†10.13 | Employment Agreement between ATP and Isabel M. Plume, dated December 29, 2005, incorporated by reference to Exhibit 10.8 to ATP’s Form 8-K dated December 30, 2005. | |
†10.14 | Employment Agreement between ATP and Scott D. Heflin, dated December 29, 2005, incorporated by reference to Exhibit 10.9 to ATP’s Form 8-K dated December 30, 2005. | |
†10.15 | Employment Agreement between ATP and Keith R. Godwin, dated December 29, 2005, incorporated by reference to Exhibit 10.10 to ATP’s Form 8-K dated December 30, 2005. | |
†10.16 | Employment Agreement between ATP and George Ross Frazer, dated December 29, 2005, incorporated by reference to Exhibit 10.11 to ATP’s Form 8-K dated December 30, 2005. | |
†10.17 | Employment Agreement between ATP and T. Paul Bulmahn, dated December 29, 2005, incorporated by reference to Exhibit 10.12 to ATP’s Form 8-K dated December 30, 2005. | |
†10.18 | Employment Agreement between ATP and George R. Morris, dated May 27, 2008, incorporated by reference to Exhibit 99.1 to ATP’s Form 8-K dated May 21, 2008. | |
†10.19 | 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. | |
†10.20 | 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. |
47
Table of Contents
10.21 | Purchase Agreement dated September 23, 2009 among the Company, J.P. Morgan Securities Inc. and Credit Suisse Securities (USA) LLC, as representatives of the several Initial Purchasers named therein, incorporated by reference to Exhibit 10.1 of ATP’s Form 8-K dated September 29, 2009. | |
*21.1 | Subsidiaries of ATP. | |
*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 |
† | Management contract or compensatory plan or arrangement |
* | Filed herewith |
48
Table of Contents
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, 2010
| By: | /s/ ALBERT L. REESE JR. | |||
Albert L. Reese Jr. | ||||||
Chief Financial Officer |
49