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ATP Oil & Gas 10-Q 2008 Table of Contents
UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D. C. 20549
FORM 10-Q
For the quarterly period ended June 30, 2008 OR
Commission file number: 000-32261
ATP OIL & GAS CORPORATION (Exact name of registrant as specified in its charter)
4600 Post Oak Place, Suite 200 Houston, Texas 77027 (Address of principal executive offices) (Zip Code) (713) 622-3311 (Registrant's telephone number, including area code)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨ Indicate by check mark whether the Registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):
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 August 4, 2008, was 35,897,005.
Table of ContentsATP OIL & GAS CORPORATION AND SUBSIDIARIES TABLE OF CONTENTS
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Table of ContentsItem 1. Financial Statements ATP OIL & GAS CORPORATION AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (In Thousands, Except Share and Per Share Amounts) (Unaudited)
See accompanying notes to consolidated financial statements.
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Table of ContentsATP OIL & GAS CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF OPERATIONS (In Thousands, Except Per Share Amounts) (Unaudited)
See accompanying notes to consolidated financial statements.
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Table of ContentsATP OIL & GAS CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (In Thousands) (Unaudited)
See accompanying notes to consolidated financial statements.
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Table of ContentsATP OIL & GAS CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (In Thousands) (Unaudited)
See accompanying notes to consolidated financial statements.
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Table of ContentsATP OIL & GAS CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Unaudited) Note 1 — Organization ATP Oil & Gas Corporation 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 exploration-oriented independent oil and natural 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 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. All intercompany transactions are eliminated upon consolidation. The interim financial information and notes hereto should be read in conjunction with our 2007 Annual Report on Form 10-K. The results of operations for the quarter and six months ended June 30, 2008 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 the current classifications. Such reclassifications do not affect earnings. Note 2 — Recent Accounting Pronouncements During the first quarter of 2008, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards (“SFAS”) No. 161, “Disclosures about Derivative Instruments and Hedging Activities – an amendment of FASB Statement No. 133.” This statement requires enhanced disclosures about an entity’s derivative and hedging activities and is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008. We expect to adopt this standard in the first quarter of 2009 and do not anticipate that it will have a material effect on our financial statements. During the second quarter of 2008, the FASB issued SFAS No. 162, “The Hierarchy of Generally Accepted Accounting Principles.” This statement identifies a consistent framework, or hierarchy, for selecting accounting principles to be used in preparing financial statements that are presented in conformity with U.S. generally accepted accounting principles and is expected to be effective in the second half of 2008. We do not anticipate that it will have a material effect on our financial statements. Note 3 — 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 which are recorded in the period the specific item occurs. Our year to date interim effective tax rate is derived from our expectations of net income for the year, taking into consideration permanent differences. 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 carrying amounts and the tax basis of those assets and liabilities. We recognized income tax expense of approximately $13.2 million and $6.0 million for the six months ended June 30, 2008 and 2007, respectively. For the three months ended June 30, 2008 and 2007 we recognized income tax benefit of approximately $11.9 million and $1.1 million, respectively. The worldwide effective tax rates for the first six months of 2008 and 2007 were 27.4% and 15.3%, respectively. In 2007, the provision was offset by the release of a valuation allowance we had previously recorded related to our deferred tax assets in the United States jurisdiction. Note 4 — Oil and Gas Properties Acquisitions During the first half of 2008, we acquired a 100% working interest in Mississippi Canyon (“MC”) Block 304 and a 55% working interest in Green Canyon Blocks 299 and 300 (“Clipper”). Also during this period, we were awarded leases for 100% of the working interests in Viosca Knoll Block 863 and De Soto Canyon Block 355 by the U.S. Department of Interior Minerals Management Service. The total cash paid for these acquisitions was $1.2 million. During the first half of 2007, we completed the acquisition of a 100% working interest in the northwest quarter of MC Block 755, a 50% working interest in MC Block 754, and a 25% working interest in MC Block 800. A portion of the acquisition price of MC Block 755 was financed by granting an interest in its future net profits. As of June 30, 2008, the amount outstanding under the net profits interest was $13.7 million and is included in current liabilities on the consolidated balance sheet. During the first quarter of 2008, we reduced our working interests in MC Block 754 from 50% to 25% and in MC Block 800 from 25% to 10%.
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Table of ContentsATP OIL & GAS CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)
Dispositions During the second quarter of 2008, we completed the sale of 5.76 Bcfe of proved reserves in the form of a 15% limited-term overriding royalty interest for $82.0 million. The interest is carved out of our net revenue interests in production from MC Blocks 711, 754, 755 and 800. In accordance with SFAS No. 19, “Financial Accounting and Reporting by Oil & Gas Producing Companies,” the sale is accounted for as a volumetric production payment. The net proceeds received were recorded as deferred revenue to be recognized in earnings as the production is delivered and is presented on the consolidated statements of cash flows as proceeds from disposition of oil and gas properties. The reserves associated with the interest have been removed from our proved oil and natural gas reserves. Note 5 — Asset Retirement Obligation Following are reconciliations of the beginning and ending asset retirement obligation for the following periods (in thousands):
Note 6 — Supplemental Disclosures of Cash Flow Information Following are supplemental disclosures of cash flow information for the following periods (in thousands):
During the six months ended June 30, 2007, we completed the acquisition of a 100% working interest in the northwest quarter of MC Block 755 and a portion of the acquisition price was financed by granting an interest in its future net profits (a noncash transaction). Note 7 — Long-Term Debt Long-term debt consisted of the following (in thousands):
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Table of ContentsATP OIL & GAS CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)
We entered into new senior secured term loan facilities, effective June 27, 2008 (collectively, the “Term Loans”). Key components of the Term Loans include a tranche of $1.05 billion, maturing July 2014, and a tranche of $600.0 million (the “Asset Sale Facility”), maturing January 2011. The Term Loans were issued with an original issue discount of 2.5% and bear interest at LIBOR plus 5.25% (with a LIBOR floor of 3.25%). The $1.05 billion tranche requires a $2.63 million principal repayment per calendar quarter until September 2013, and four quarterly repayments of $249.4 million thereafter. The Asset Sale Facility is due in full at maturity and allows for prepayment at any time at par. The Term Loans are secured by substantially all of our oil and gas assets in the Gulf of Mexico and a pledge of 65% of the common stock of our wholly owned subsidiaries, ATP Oil & Gas (UK) Limited and ATP Oil and Gas (Netherlands) B.V. We also have a $50.0 million revolving credit facility which has the same interest obligations as the Term Loans and has a final maturity of January 2014. Available borrowing capacity at June 30, 2008 is $31.0 million due to outstanding letters of credit issued against the facility. The Term Loans carry the following restrictions and covenants, among others:
Capitalized terms in the foregoing restrictions and covenants have the meaning set forth in the credit agreement. The combined effective interest rate under the Term Loans at June 30, 2008 was approximately 9.4% per annum. Note 8 — Stock–Based Compensation We recognized stock option compensation expense of approximately $0.7 million and $0.3 million for the three months ended June 30, 2008 and 2007, respectively. We recognized stock option compensation expense of approximately $1.4 million and $0.7 million for the six months ended June 30, 2008 and 2007, respectively. The weighted average grant-date fair value of options granted during the six months ended June 30, 2008 and 2007 was $12.51 and $16.26, respectively. The fair values of options granted during the six months ended June 30, 2008 and 2007 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 following periods:
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Table of ContentsATP OIL & GAS CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)
The following table sets forth a summary of option transactions for the six-month period ended June 30, 2008:
At June 30, 2008, unrecognized compensation expense related to nonvested stock option grants totaled $3.3 million. Such unrecognized expense will be recognized as vesting occurs over the weighted average remaining vesting period of 2.3 years. At June 30, 2008, unrecognized compensation expense related to restricted stock totaled $9.2 million. Such unrecognized expense will be recognized as vesting occurs over a weighted average period of 1.9 years. The following table sets forth the restricted stock transactions for the six-month period ended June 30, 2008 during which we recognized $4.4 million of compensation expense:
Note 9 — Earnings Per Share Basic earnings per share (“EPS”) is computed by dividing net income or loss available to common shareholders by the weighted average number of shares of common stock (other than nonvested restricted stock) outstanding during the period. Weighted average shares outstanding for diluted EPS also includes a hypothetical number of shares assuming all in-the-money options and warrants would have been exercised and vesting of restricted stock. For purposes of computing EPS in a loss year, potential common shares are excluded from the computation of weighted average common shares outstanding as their effect is antidilutive.
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Table of ContentsATP OIL & GAS CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)
For the three months ended June 30, 2008 and 2007, respectively, stock-based awards for 869,834 and 25,250 average shares of common stock, were excluded from the diluted EPS calculation because their inclusion would have been antidilutive. For the six months ended June 30, 2008 and 2007, respectively, stock-based awards for 316,323 and 30,250 average shares of common stock were excluded from the diluted EPS calculation because their inclusion would have been antidilutive. Basic and diluted net income per share is computed based on the following information (in thousands, except per share amounts):
Note 10 — Derivative Instruments and Risk Management Activities At June 30, 2008 and December 31, 2007, accumulated other comprehensive income included $23.2 million and $17.3 million of unrealized after-tax losses, respectively, on our cash flow hedges. In the period the forecasted hedged transactions occur, gains and losses are reclassified from accumulated other comprehensive income to the consolidated statement of operations as components of the revenue or expense items to which they relate. Hedge ineffectiveness is recorded directly to the consolidated statement of operations. At June 30, 2008, we had derivative contracts in place for the following natural gas and oil volumes:
As a result of the sale of the limited-term overriding royalty interest and changes in forecasts of production, we determined that it was no longer probable that forecasted production would be sufficient to
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Table of ContentsATP OIL & GAS CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)
satisfy amounts designated under certain of our cash flow commodity-price hedges. Consequently, we have de-designated some of these instruments as hedges, which resulted in reclassification of $40.5 million of net unrealized losses ($21.2 million after tax) from accumulated other comprehensive income to derivatives expense in the consolidated statement of operations. Subsequent changes to the fair value of these instruments and associated settlements will be reflected as derivatives income (expense) in the consolidated statement of operations. For the quarter and six months ended June 30, 2008, we recognized a loss of $9.6 million in derivatives expense for changes in fair value and settlements of derivatives no longer designated as cash flow hedges. Settlements on all of our commodity derivative instruments are included in cash flows from operating activities in our consolidated statement of cash flows. We also manage our exposure to oil and natural gas price risks by periodically entering into fixed-price physical forward sale contracts. These physical contracts qualified and have been designated for the normal purchase and sale exemption under SFAS No. 133, as amended. At June 30, 2008, we had fixed-price physical contracts in place for the following natural gas and oil volumes:
In January 2008, we entered into a cash flow hedge using an interest rate swap on, initially, $500.0 million of principal which locked the LIBOR portion of the interest rate on our then-outstanding first lien borrowings at 3.1% until February 15, 2010. As mentioned above, in the second quarter 2008, we refinanced the first lien borrowings and assumed different interest obligations. Accordingly, we have de-designated as a hedge the interest rate swap because we no longer expect it to be highly effective at offsetting the variability in the interest payments required under the new Term Loans. This resulted in reclassification of $49,000 of net unrealized losses ($32,000 after tax) from accumulated other comprehensive income to derivatives expense in the consolidated statement of earnings. At June 30, 2008, the fair value of the interest rate swap was a $49,000 net liability. During July 2008, we terminated the interest rate swap and received $50,000 cash consideration. Note 11 — Commitments and Contingencies 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.
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Table of ContentsATP OIL & GAS CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)
In the normal course of business, we acquire proved properties with little or no upfront costs, but with a commitment to make payments out of future production, if any. As initial production or designated production levels are achieved, the contingent consideration is paid and capitalized to the appropriate property. At June 30, 2008, our aggregate exposure under such arrangements totaled approximately $13.2 million. We are, from time to time, a party to various legal proceedings in the ordinary course of business. Management does not believe that the outcome of these legal proceedings, individually, or in the aggregate, will have a material adverse effect on our financial condition, results of operations or cash flows. Note 12 — Segment Information The Company’s operations are focused in the Gulf of Mexico and in the North Sea. Management reviews and evaluates separately the operations of its Gulf of Mexico segment and its North Sea segment. The operations of our segments include natural gas and liquid hydrocarbon production and sales. Segment activity for the three months and six months ended June 30, 2008 and 2007 is as follows (in thousands):
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Table of ContentsATP OIL & GAS CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)
Note 13 — Fair Value Measurements We adopted SFAS No. 157, “Fair Value Measurements,” effective January 1, 2008 for financial assets and liabilities measured on a recurring basis. SFAS No. 157 applies to all financial assets and financial liabilities that are being measured and reported on a fair value basis. In February 2008, the FASB issued FSP No. 157-2, which delayed the effective date of SFAS No. 157 by one year for nonfinancial assets and liabilities, except those measured on a recurring basis. We will adopt SFAS No. 157 with respect to asset retirement obligations and non-recurring impairments of oil and gas properties in the first quarter of 2009. Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). SFAS No. 157 requires disclosure that establishes a framework for measuring fair value and expands disclosure about fair value measurements. The statement requires fair value measurements be classified and disclosed in one of the following categories:
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Table of ContentsATP OIL & GAS CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)
Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and determines the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels. The following table summarizes, according to their inputs, financial assets and liabilities that are being measured on a fair value basis at June 30, 2008 (in thousands):
The following table sets forth a reconciliation of changes in the fair value of financial assets (liabilities) classified as Level 3 at June 30, 2008 (in thousands):
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Table of ContentsATP OIL & GAS CORPORATION AND SUBSIDIARIES
Executive Overview General ATP Oil & Gas Corporation is engaged in the acquisition, development and production of oil and natural gas properties in the Gulf of Mexico and the North Sea. We seek to acquire and develop properties with 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 SEC definition of proved reserves. We may also acquire offshore lease blocks that surround our existing developments in order to expand our acreage position in the development. This expansion may lead to added drilling opportunities, potentially new reserves or additional production. We believe that our strategy of focusing on development with an occasional exposure to exploration opportunities near our existing developments provides assets for us without the risk, cost or time of traditional exploration. We seek to create value and reduce operating risks through the acquisition and subsequent development of properties in areas that have:
Our focus is on acquiring properties that have become noncore or nonstrategic to their original owners for a variety of reasons. For example, larger oil companies from time to time adjust their capital spending or shift their focus to exploration prospects which they believe may offer greater reserve potential. Some projects may provide lower economic returns to a company due to its changing cost structure or constraints within that company. Also, due to timing, budget constraints or a change in a company’s ownership or management structure, a company may be unwilling or unable to develop a property before the expiration of the lease. Because of our cost structure, expertise in our areas of focus and ability to develop projects, the properties may be more financially attractive to us than the seller. We focus on developing projects in the shortest time possible between initial major investment and first revenue generated in order to maximize our rate of return. Since we operate most of the properties in which we acquire a working interest, we are able to significantly influence the development concept and timing of a project's development. We 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, allows us to efficiently complete the development project and commence production. To enhance the economics and return on investment of a project, we sometimes develop the project to a value creation point and either sell an interest or bring in partners on a promoted basis. In the second quarter of 2008, we announced plans to offer for sale partial working interests in a number of our properties both producing and under development. Second Quarter 2008 Highlights Our financial and operating performance for the second quarter of 2008 included the following highlights:
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Table of ContentsAdditional discussion of 2008 expectations can be found in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our 2007 Annual Report on Form 10-K. Results of Operations Three Months Ended June 30, 2008 Compared to Three Months Ended June 30, 2007 For the three months ended June 30, 2008 and 2007 we reported net loss of $11.8 million and net income of $6.1 million, or net loss of $0.33 and net income of $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. Production sold under fixed-price delivery contracts which have been designated for the normal purchase and sale exemption under Statement of Financial Accounting Standards (“SFAS”) No. 133 are also included in these amounts as well as the effects of financial cash flow hedges. Deliveries under the fixed-price contracts are approximately 85% and 34% of our oil production for the three months ended June 30, 2008 and 2007, respectively. Approximately 82% and 48% of our natural gas production was sold under these fixed-price delivery contracts for the comparable periods. The realized prices below may differ from the market prices in effect during the periods depending on when the fixed-price delivery contract was executed. The table also reflects oil and gas production revenues from amortization of deferred revenue related to the sale of the limited-term overriding royalty interest. We do not reflect any production associated with those revenues.
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Table of ContentsRevenues from production increased 45% in the second quarter of 2008 compared to the second quarter of 2007. During the second quarter of 2008, our production increased 26% compared to the second quarter of 2007 primarily due to greater production in the Gulf of Mexico from the Gomez Hub and due to U.K. production from the Wenlock property, which was brought online in the fourth quarter of 2007. The increased revenues were also attributable to a 15% increase in average sales price. Lease Operating Lease operating expenses for the second quarter of 2008 increased to $23.8 million ($1.29 per Mcfe) from $20.1 million ($1.38 per Mcfe) in the second quarter of 2007. The increase was primarily attributable to the production increases noted above. The per unit cost has decreased primarily due to the effect of fixed costs. In second quarter 2008, lease operating expense per Mcfe in the Gulf of Mexico and the North Sea was $1.29 and 1.27, respectively. In the second quarter 2007, lease operating expense per Mcfe in the Gulf of Mexico and North Sea was $1.25 and $2.45, respectively. General and Administrative General and administrative expense for the second quarter of 2008 increased to $8.8 million from $6.6 million in the second quarter of 2007. The increase is primarily attributable to higher stock-based compensation costs. Depreciation, Depletion and Amortization Depreciation, Depletion and Amortization (“DD&A”) expense increased during the second quarter of 2008 to $79.9 million from $52.6 million for the second quarter of 2007. The increase was due to the increased production noted above and to an increased depletion rate. The second quarter of 2008 DD&A rates for the Gulf of Mexico and North Sea were $3.59 per Mcfe and $6.57 per Mcfe, respectively. The second quarter of 2007 DD&A rates for the Gulf of Mexico and North Sea were $3.52 per Mcfe and $4.32 per Mcfe, respectively. The average depletion rate increased 20% to $4.33 per Mcfe in the second quarter of 2008 compared to $3.61 per Mcfe in the second quarter of 2007. This per unit increase is primarily a result of higher costs incurred on our new developments relative to some of our older properties. Impairment of Oil and Gas Properties In the second quarter of 2007, we recorded an impairment of oil and gas properties totaling $5.8 million due to unfavorable operating performance on one property in the Gulf of Mexico. Accretion of Asset Retirement Obligation Accretion expense increased to $4.3 million in the second quarter of 2008 compared to 3.0 million in second quarter 2007 primarily due to increased asset retirement obligations associated with increased oil and gas property development and overall vendor price increases. Loss on Abandonment During second quarter 2008, we recognized an aggregate loss on abandonment of $1.0 million due to unanticipated vendor price increases in the Gulf of Mexico. Interest Expense Interest expense decreased to $24.2 million for the second quarter of 2008 compared to $31.0 million for the second quarter of 2007 primarily due to overall lower interest rates and their effect on our floating-rate borrowings and $7.2 million of capitalized 2008 interest related to the construction of a floating production system at the Telemark Hub, partially offset by outstanding 11.25% Subordinated Notes of $210.0 million face value which were issued in the second half of 2007.
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Table of ContentsDerivatives Expense Derivatives expense in the second quarter of 2008 is $50.2 million (Gulf of Mexico $16.2 million and North Sea $34.0 million). As a result of the limited-term overriding royalty interest and changes in forecasts of production, we determined that it was no longer probable that forecasted production would be sufficient to satisfy amounts designated under certain of our cash flow commodity-price hedges. Consequently, we have de-designated some of these instruments as hedges. Also, we have de-designated as a hedge the interest rate swap because we no longer expect it to be highly effective at offsetting the variability in the interest payments for the new Term Loans. The total expense related to de-designation of these cash flow hedges is $40.5 million. The balance of the derivatives expense is related primarily to changes in fair value and settlements of derivatives no longer designated as cash flow hedges. Loss on Debt Extinguishment Loss on debt extinguishment in the second quarter of 2008 is $24.2 million. As discussed below, during the second quarter of 2008, we refinanced the Term Loans and Subordinated Notes and recorded losses for the remaining unamortized deferred financing costs, debt discount related to the retired debt and for repayment premiums associated with the Subordinated Notes. Income Taxes We recorded income tax benefit of $11.9 million during the quarter ended June 30, 2008 resulting in an overall effective tax rate of 50.3% for the quarter. In each jurisdiction, the rates were determined based on our expectations of net income for the year, taking into consideration permanent differences. In the comparable quarter of 2007 we recorded a tax benefit of $1.1 million resulting in an overall effective tax rate of 22.7% for the quarter. The provision for the quarter results from the application of the current expected tax rate for the year applied to the year-to-date pre-tax income. In 2007, the tax provision recorded in the U.S. based upon our second quarter 2007 book income was entirely offset by a release of a valuation allowance contributing to the lower overall effective tax rate when compared to the same period in 2008. Six Months Ended June 30, 2008 Compared to Six Months Ended June 30, 2007 For the six months ended June 30, 2008 and 2007 we reported net income of $35.1 million and $33.6 million, or $0.97 and $1.10 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. Production sold under fixed-price delivery contracts which have been designated for the normal purchase and sale exemption under SFAS No. 133 are also included in these amounts as well as the effects of financial cash flow hedges. Deliveries under the fixed-price contracts are approximately 78% and 32% of our oil production for the six months ended June 30, 2008 and 2007, respectively. Approximately 83%, and 50% of our natural gas production was sold under these fixed-price delivery contracts for the comparable periods. The realized prices below may differ from the market prices in effect during the periods depending on when the fixed-price delivery contract was executed. The table also reflects oil and gas production revenues from amortization of deferred revenue related to the sale of the limited-term overriding royalty interest. We do not reflect any production associated with those revenues.
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Table of Contents
Revenues from production increased 51% in the first half of 2008 compared to the first half of 2007. During the first half of 2008, our production increased 31% compared to the first half of 2007 primarily due to greater production in the Gulf of Mexico from the Gomez Hub and due to U.K. production from the Wenlock property, which was brought online in the fourth quarter of 2007. The increased revenues were also attributable to a 15% increase in average sales price. Lease Operating Lease operating expenses for the first half of 2008 increased to $48.4 million ($1.21 per Mcfe) from $41.2 million ($1.35 per Mcfe) in the first half of 2007. The increase was primarily attributable to the production increases noted above. The per unit cost has decreased primarily due to the effect of fixed costs. In the first half of 2008, lease operating expense per Mcfe in the Gulf of Mexico and the North Sea was $1.19 and 1.28, respectively. In the first half of 2007, lease operating expense per Mcfe in the Gulf of Mexico and North Sea was $1.26 and $1.77, respectively. General and Administrative General and administrative expense for the first half of 2008 increased to $18.1 million from $15.3 million in the first half of 2007. The increase is primarily attributable to higher stock-based compensation costs. Depreciation, Depletion and Amortization DD&A expense increased during the first half of 2008 to $169.3 million from $106.0 million for the first half of 2007. The increase was due to the increased production noted above and to an increased depletion rate. The first half of 2008 DD&A rates for the Gulf of Mexico and North Sea were $3.53 per Mcfe and $6.31 per Mcfe, respectively. The first half of 2007 DD&A rates for the Gulf of Mexico and North Sea were $3.32 per Mcfe and $4.22 per Mcfe, respectively. The average depletion rate increased 22% to $4.23 per Mcfe in the first half of 2008 compared to $3.48 per Mcfe in the first half of 2007. This per unit increase is primarily a result of higher costs incurred on our new developments relative to some of our older properties. Impairment of Oil and Gas Properties In the first half of 2007, we recorded an impairment of oil and gas properties totaling $5.8 million due to unfavorable operating performance on one property in the Gulf of Mexico. Accretion of Asset Retirement Obligation Accretion expense increased to $8.6 million in the first half of 2008 compared to 6.0 million in the first half of 2007 primarily due to increased asset retirement obligations associated with increased oil and gas property development and overall vendor price increases.
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Table of ContentsLoss on Abandonment During the first half of 2008, we recognized an aggregate loss on abandonment of $1.4 million due to unanticipated vendor price increases in the Gulf of Mexico. Interest Expense Interest expense decreased to $52.4 million for the first half of 2008 compared to $57.8 million for the first half of 2007 primarily due to $13.1 million of capitalized 2008 interest related to the construction of a floating production system at the Telemark Hub and lower overall interest rates and their effect on our floating-rate borrowings, partially offset by outstanding Subordinated Notes of $210.0 million face value, which were issued in 2007 and the outstanding net $200.0 million increase in borrowings under our Term Loans beginning in the second quarter of 2007. Derivatives Expense Derivatives expense in the first half of 2008 is $50.2 million (Gulf of Mexico $16.2 million and North Sea $34.0 million). As a result of the limited-term overriding royalty interest and changes in forecasts of production, we determined that it was no longer probable that forecasted production would be sufficient to satisfy amounts designated under certain of our cash flow commodity-price hedges. Consequently, we have de-designated some of these instruments as hedges. Also, we have de-designated as a hedge the interest rate swap because we no longer expect it to be highly effective at offsetting the variability in the interest payments for the new Term Loans. The total expense related to de-designation of these cash flow hedges is $40.5 million. The balance of the derivatives expense is related primarily to changes in fair value and settlements of derivatives no longer designated as cash flow hedges. Loss on Debt Extinguishment Loss on debt extinguishment in the first half of 2008 is $24.2 million. As discussed below, during the second quarter of 2008, we refinanced the Term Loans and Subordinated Notes and recorded losses for the remaining unamortized deferred financing costs, debt discount related to the retired debt and for repayment premiums associated with the Subordinated Notes. Income Taxes We recorded income tax expense of $13.2 million during the six months ended June 30, 2008 resulting in an overall effective tax rate of 27.4% for the period. In each jurisdiction, the rates were determined based on our expectations of net income for the year, taking into consideration permanent differences. In the comparable period of 2007 we recorded tax expense of $6.0 million resulting in an overall effective tax rate of 15.3% for the period. The provision for the period results from the application of the current expected tax rate for the year applied to the year to date pre-tax income. In 2007, the tax provision recorded in the U.S. based upon our first half 2007 book income was entirely offset by a release of a valuation allowance contributing to the lower overall effective tax rate when compared to the same period in 2008. Liquidity and Capital Resources At June 30, 2008, we had working capital of $154.7 million, an increase of $57.8 million from December 31, 2007. Additionally, under the Term Loans, we have a $50.0 million revolving credit facility (“Revolver”), with available borrowing capacity reduced to $31.0 million due to outstanding letters of credit as of June 30, 2008. Our credit agreement covenants specify a minimum liquidity ratio under which we include the availability under the Revolver, and exclude current maturities of long-term debt, the current portion of assets and liabilities from derivatives and the current portion of asset retirement obligations. Historically, we have financed our acquisition and development activities through a combination of bank borrowings, proceeds from equity offerings, cash from operations and the sale of interests in selected properties. In the second quarter of 2008, we announced plans to offer for sale partial working interests in a number of our properties, both producing and under development. We intend to reduce our debt by up to $600.0 million with the expected proceeds from any such sales. We intend to continue to finance our near-term development projects utilizing cash on hand and the potential sources of capital mentioned above. As operator of most of our projects under development, we have the ability to significantly control the timing of most of our capital expenditures. Coupled with that control, we believe our cash flows from operating activities and potential for available third-party capital will enable us to meet our future capital requirements.
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Table of ContentsCash Flows
Cash provided by operating activities during the first half of 2008 and 2007 was $164.8 million and $177.5 million, respectively. Cash flow from operations increased primarily due to higher oil and gas production revenues during 2008 compared to 2007. The increase in sales revenue was attributable to higher oil and gas production and higher oil and gas prices during 2008. The increase in cash flows from revenues was partially offset by the timing of payments and receipts in payables and receivables. Cash used in investing activities was $266.7 million and $390.2 million during the first half of 2008 and 2007, respectively. Cash expended in the Gulf of Mexico and North Sea for additions to oil and gas properties was approximately $245.2 million and $103.8 million, respectively, in the first half of 2008. Cash expended in the Gulf of Mexico and North Sea for additions to oil and gas properties was approximately $279.6 million and $110.3 million, respectively, in the first half of 2007. During the second quarter of 2008, we completed the sale of 5.76 Bcfe of proved reserves in the form of a 15% limited-term overriding royalty interest for $82.0 million. Cash provided by financing activities was $180.9 million and $162.4 million during first half 2008 and 2007, respectively. Payments of long-term debt for the first half of 2008 are comprised of $1,202.2 million of repayment of borrowings under our former credit agreement and of $199.5 million related to our former subordinated notes. Proceeds from long-term debt are comprised of $1,593.4 million (net of issuance costs) of proceeds from the Term Loans. During the first half of 2007, financing cash flow was primarily due to the increase in our term loans of $366.6 million (net of issuance costs), partially offset by the $175.0 million repayment of our former second lien term loans and other debt and lease payments. Long-term Debt Long-term debt consisted of the following (in thousands):
We entered into a new senior secured term loan facility, effective June 27, 2008 (collectively, the “Term Loans”). Proceeds of the Term Loans were used to refinance the $1.2 billion senior secured term loan scheduled to mature in April 2010 and $210.0 million of unsecured subordinated notes scheduled to mature in September 2011, and for general corporate purposes. Key components of the Term Loans include a tranche of $1.05 billion, maturing July 2014, and a tranche of $600.0 million (the “Asset Sale Facility”), maturing January 2011. The Term Loans were issued with an original issue discount of 2.5% and bear interest at LIBOR plus 5.25% (with a LIBOR floor of 3.25%). The $1.05 billion tranche requires a $2.63 million principal repayment per calendar quarter until September 2013, and four quarterly repayments of $249.4 million thereafter. The Asset Sale Facility is due in full at maturity and allows for prepayment at any time at par. The Term Loans are secured by substantially all of our oil and gas assets in the Gulf of Mexico and a pledge of 65% of the common stock of our wholly owned subsidiaries, ATP Oil & Gas (UK) Limited and ATP Oil and Gas (Netherlands) B.V. We have a $50.0 million revolving credit facility (of which $31.0 million was available as of June 30, 2008).
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Table of ContentsThe Term Loans carry the following restrictions and covenants, among others:
Capitalized terms in the foregoing restrictions and covenants have the meaning set forth in the credit agreement dated June 27, 2008, which is Exhibit 10.2 to this document. We were in compliance with our credit agreement covenants at June 30, 2008. Contractual Obligations The following table summarizes certain contractual obligations at June 30, 2008 (in thousands):
Our liabilities also include asset retirement obligations (“ARO”) ($19.0 million current and $169.5 million long-term) that represent the amount at June 30, 2008 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 unknown 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.
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Table of ContentsCommitments and Contingencies Management is periodically faced with uncertainties, the outcomes of which are not within its control and will not be known for a long time. We are involved in actions from time to time, which if determined adversely, could have a material negative impact on our financial position, results of operations and cash flows. Management, with the assistance of counsel makes estimates, if determinable, of ATP's probable liabilities and records such amounts in the consolidated financial statements. Such estimates may be the minimum amount of a range of probable loss when no single best estimate is determinable. Disclosure is made, when determinable, of any additional possible amount of loss on these claims, or if such estimate cannot be made, that fact is disclosed. Along with our counsel, we monitor developments related to these legal matters and, when appropriate, we make adjustments to recorded liabilities to reflect current facts and circumstances. Although it is difficult to predict the ultimate outcome of these matters, management is not aware of any amounts that need to be recorded and believes that the recorded amounts, if any, are reasonable. See Note 11 to the consolidated financial statements for additional discussion of commitments and contingencies. Accounting Pronouncements See Note 2 to our Consolidated Financial Statements for a discussion of recently issued accounting pronouncements. Critical Accounting Policies Our discussion and analysis of our financial condition and results of operations are based on consolidated financial statements which have been prepared in accordance with generally accepted accounting principles in the United States. The preparation of these financial statements requires us to make estimates and judgments that affect the reported amounts or assets, liabilities, revenues and expenses. We believe that certain accounting policies affect our more significant judgments and estimates used in the preparation of our consolidated financial statements. Our 2007 Annual Report on Form 10-K, includes a discussion of our critical accounting policies.
Interest Rate Risk We are exposed to changes in interest rates on our Term Loans and on the earnings from cash and cash equivalents. See the discussion of our Term Loans in Note 7 to the consolidated financial statements. Foreign Currency Risk The net assets, net earnings and cash flows from our wholly owned subsidiaries in the U.K. and the Netherlands are based on the U.S. dollar equivalent of such amounts measured in the applicable functional currency. These foreign operations have the potential to impact our financial position due to fluctuations in the local currency arising from the process of re-measuring the local currency in U.S. dollars. 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 and fixed-price physical contracts to hedge our commodity prices. See Derivative Instruments and Risk Management Activities Note 10. We may enter into short-term hedging arrangements if (1) we are able to obtain commodity contracts at prices sufficient to secure an acceptable internal rate of return on a particular property or on a group of properties or (2) if deemed necessary by the terms of our existing credit agreements. We do not initially hold or issue derivative instruments for speculative purposes.
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Evaluation of Disclosure Controls and Procedures Our principal executive officer and principal financial officer have reviewed and evaluated the effectiveness of our disclosure controls and procedures, as defined in Exchange Act Rules 13a-15(e) and 15d-15(e), as of June 30, 2008 (the “Evaluation Date”). Based on this evaluation, the principal executive officer and principal financial officer have concluded that ATP's disclosure controls and procedures were effective as of the Evaluation Date to ensure that information that is required to be disclosed by ATP in the reports it files or submits under the Exchange Act is (i) recorded, processed, summarized and reported, within the time periods specified in the Securities and Exchange Commission's rules and forms and (ii) accumulated and communicated to ATP's management, including our principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding required disclosure. Changes in Internal Control Over Financial Reporting During the three months ended June 30, 2008, we have made no change to our internal controls over financial reporting that has materially affected, or is reasonably likely to materially affect, our internal controls over financial reporting. Forward-Looking Statements and Associated Risks This Quarterly Report contains projections and other forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934. These projections and statements reflect the Company's current views with respect to future events and financial performance. No assurances can be given, however, that these events will occur or that these projections will be achieved and actual results could differ materially from those projected as a result of certain factors. A discussion of these factors is included in the Company's 2007 Annual Report on Form 10-K.
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Table of ContentsItems 1, 1A, 2, 3 and 5 are not applicable and have been omitted.
The following items were presented for approval to stockholders of record on April 10, 2008 at the Company's annual meeting of stockholders which was held on June 9, 2008 in Houston, Texas:
All matters received the required number of votes for approval.
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Table of ContentsSIGNATURES 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.
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