10-Q 1 d10q.txt FOR THE QTR. ENDED SEPT. 30, 2001 ================================================================================ 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, 2001 OR [_] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934 COMMISSION FILE NUMBER: 000-32261 ATP OIL & GAS CORPORATION (EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER) TEXAS 76-0362774 (STATE OR OTHER JURISDICTION OF (I.R.S. Employer INCORPORATION OR ORGANIZATION) 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 [_] The number of shares outstanding of Registrant's common stock, par value $0.001, as of November 10, 2001, was 20,307,944. ================================================================================ ATP OIL & GAS CORPORATION TABLE OF CONTENTS PAGE ---- PART I. FINANCIAL INFORMATION ITEM 1. FINANCIAL STATEMENTS Consolidated Balance Sheets: September 30, 2001 and December 31, 2000.......................... 3 Consolidated Statements of Operations: For the three and nine months ended September 30, 2001 and 2000... 4 Consolidated Statements of Cash Flows: For the nine months ended September 30, 2001 and 2000............. 5 Notes to Consolidated Financial Statements.......................... 6 ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.............................. 11 ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK....... 18 PART II. OTHER INFORMATION............................................... 21 2 ITEM 1. FINANCIAL STATEMENTS ATP OIL & GAS CORPORATION AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (In Thousands, Except Share Data)
September 30, December 31, 2001 2000 ------------- ------------ (unaudited) ASSETS Current assets: Cash and cash equivalents.................................................... $ 9,511 $ 18,136 Accounts receivable (net of allowance of $1,174 and $443, respectively)...... 15,818 32,542 Deferred tax asset........................................................... 689 - Commodity contracts and other derivatives.................................... 2,690 - Other current assets......................................................... 3,862 2,597 --------- --------- Total current assets....................................................... 32,570 53,275 --------- --------- Oil and gas properties:....................................................... Oil and gas properties (using the successful efforts method of accounting)... 317,620 209,548 Less: Accumulated depletion and impairment................................... (164,648) (110,823) --------- --------- Oil and gas properties, net................................................ 152,972 98,725 --------- --------- Furniture and fixtures (net of accumulated depreciation)...................... 800 487 Deferred tax asset............................................................ 11,950 7,652 Other assets, net............................................................. 3,407 1,854 --------- --------- Total assets............................................................... $ 201,699 $ 161,993 ========= ========= LIABILITIES AND SHAREHOLDERS' EQUITY (DEFICIT) Current liabilities: Accounts payable and accruals................................................ $ 64,917 $ 49,799 Current maturities of long-term debt......................................... - - Commodity contracts and other derivatives.................................... - 7,248 Other deferred obligations................................................... 63 63 --------- --------- Total current liabilities.................................................. 64,980 57,110 Long-term debt................................................................ 80,046 27,750 Non-recourse borrowings....................................................... - 88,779 Commodity contracts and other derivatives..................................... 506 - Deferred revenue.............................................................. 1,343 1,481 Other long-term liabilities and deferred obligations.......................... 243 52 --------- --------- Total liabilities.......................................................... 147,118 175,172 --------- --------- Shareholders' equity (deficit): Preferred stock: $0.001 par value, 10,000,000 shares authorized; none issued and outstanding................................................ - - Common stock: $0.001 par value, 100,000,000 shares authorized; 20,383,784 issued and 20,307,944 outstanding at September 30, 2001 and 14,285,714 issued and outstanding at December 31, 2000................. 20 14 Additional paid in capital................................................... 80,036 38 Accumulated deficit.......................................................... (23,392) (13,231) Accumulated other comprehensive loss......................................... (1,172) - Treasury stock, at cost...................................................... (911) - --------- --------- Total shareholders' equity (deficit)....................................... 54,581 (13,179) --------- --------- Total liabilities and shareholders' equity (deficit)....................... $ 201,699 $ 161,993 ========= =========
See accompanying notes to the consolidated financial statements. 3 ATP OIL & GAS CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF OPERATIONS (In Thousands, Except Per Share Amounts) (UNAUDITED)
Three Months Ended Nine Months Ended September 30, September 30, ------------------- ------------------ 2001 2000 2001 2000 ---- ---- ---- ---- Revenue: Oil and gas production..................... $19,571 $18,357 $ 87,081 $ 55,090 Gas sold - marketing....................... 1,312 2,105 6,280 5,024 Gain on sale of oil and gas properties..... - - - 33 ------- ------- -------- -------- Total revenues............................ 20,883 20,462 93,361 60,147 ------- ------- -------- -------- Costs and operating expenses: Lease operating expenses................... 2,454 1,941 9,707 8,363 Gas purchased - marketing.................. 1,260 2,054 6,127 4,856 Geological and geophysical expenses........ 764 - 1,236 - General and administrative expenses........ 2,663 1,280 6,713 4,018 Non-cash compensation expense.............. 464 - 2,930 - Depreciation, depletion and amortization... 13,399 13,991 38,503 30,686 Impairment on oil and gas properties....... 3,655 783 17,838 7,038 ------- ------- -------- -------- Total costs and operating expenses........ 24,659 20,049 83,054 54,961 ------- ------- -------- -------- Net income (loss) from operations........... (3,776) 413 10,307 5,186 ------- ------- -------- -------- Other income (expense): Interest income............................ 60 78 853 333 Interest expense........................... (2,109) (3,299) (7,130) (8,445) Gain (loss) on derivative instruments...... (3,334) (3,729) (17,496) (6,242) ------- ------- -------- -------- Total other income (expense).............. (5,383) (6,950) (23,773) (14,354) ------- ------- -------- -------- Net loss before income taxes and extraordinary item......................... (9,159) (6,537) (13,466) (9,168) Income tax benefit - deferred............... 2,660 2,286 3,907 3,204 ------- ------- -------- -------- Net loss before extraordinary item.......... (6,499) (4,251) (9,559) (5,964) Extraordinary item, net of tax.............. - - (602) - ------- ------- -------- -------- Net loss.................................... $(6,499) $(4,251) $(10,161) $ (5,964) ======= ======= ======== ======== Basic and diluted earnings (loss) per common share: Loss before extraordinary item............ $ (0.32) $ (0.30) $ (0.49) $ (0.42) Extraordinary item, net of tax............ - - (0.03) - ------- ------- -------- -------- Net loss per common share................. $ (0.32) $ (0.30) $ (0.52) $ (0.42) ======= ======= ======== ======== Weighted average number of common shares: Basic and diluted 20,297 14,286 19,499 14,286 ======= ======= ======== =======
See accompanying notes to the consolidated financial statements. 4 ATP OIL & GAS CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (In Thousands) (UNAUDITED)
Nine Months Ended September 30, ------------------------ 2001 2000 --------- --------- CASH FLOWS FROM OPERATING ACTIVITIES Net loss.................................................... $ (10,161) $ (5,964) Adjustments to reconcile net loss to net cash provided by operating activities - Depreciation, depletion and amortization.................. 38,503 30,686 Impairment of oil and gas properties...................... 17,838 7,038 Amortization of deferred financing costs.................. 494 237 Extraordinary item........................................ 926 - Deferred tax asset........................................ (4,298) (3,204) Non-cash compensation expense............................. 2,930 - Gain on sale of oil and gas properties.................... - (33) Other non-cash items...................................... 220 431 Changes in assets and liabilities - Accounts receivable and other.............................. 15,459 (13,437) Restricted cash............................................ - 471 Net (assets) liabilities from commodity contracts and other derivatives......................................... (11,401) 2,496 Accounts payable and accruals.............................. 15,045 17,291 Other long-term assets..................................... (3,523) (485) Other long-term liabilities and deferred credits........... 53 (208) --------- -------- Net cash provided by operating activities.................... 62,085 35,319 --------- -------- CASH FLOWS FROM INVESTING ACTIVITIES Additions and acquisitions of oil and gas properties........ (108,378) (50,558) Additions to furniture and fixtures......................... (480) (288) --------- -------- Net cash used in investing activities........................ (108,858) (50,846) --------- -------- CASH FLOWS FROM FINANCING ACTIVITIES Proceeds from initial public offering....................... 78,330 - Payment of offering costs................................... (893) (192) Proceeds from long-term debt................................ 95,000 15,800 Payments of long-term debt.................................. (42,750) (3,750) Proceeds from non-recourse borrowings....................... 3,359 24,924 Payments of non-recourse borrowings......................... (92,138) (19,857) Deferred financing costs.................................... (2,042) (111) Treasury stock purchases.................................... (911) - Other....................................................... 193 - --------- -------- Net cash provided by financing activities.................... 38,148 16,814 --------- -------- Increase (decrease) in cash and cash equivalents............. (8,625) 1,287 Cash and cash equivalents, beginning of period............... 18,136 17,779 --------- -------- Cash and cash equivalents, end of period..................... $ 9,511 $ 19,066 ========= ======== Supplemental disclosures of cash flow information: Cash paid during the period for interest.................... $ 2,054 $ 1,720 ========= ======== Cash paid during the period for taxes....................... $ - $ 497 ========= ========
See accompanying notes to the consolidated financial statements. 5 ATP OIL & GAS CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited) NOTE 1 -- ORGANIZATION ATP Oil & Gas Corporation ("ATP"), a Texas corporation, was formed on August 8, 1991 and is engaged primarily in the acquisition, development and operation of oil and gas properties. We operate in one business segment which is oil and gas development and production. The accompanying financial statements and related notes present our consolidated financial position as of September 30, 2001 and December 31, 2000, the results of our operations for the three months and nine months ended September 30, 2001 and 2000 and cash flows for the nine months ended September 30, 2001 and 2000. The financial statements have been prepared in accordance with the instructions to interim reporting as prescribed by the Securities and Exchange Commission ("SEC"). All adjustments, consisting only of normal recurring adjustments, that in the opinion of management were necessary for a fair statement of the results for the interim periods, have been reflected. All significant intercompany transactions have been eliminated. Certain reclassifications have been made to prior period amounts to conform to current period presentation. The results of operations for the three and nine months ended September 30, 2001 should not be taken as indicative of the results to be expected for the full year. The interim financial statements should be read in conjunction with our consolidated financial statements and notes thereto presented in our 2000 Annual Report on Form 10-K. Initial Public Offering On February 5, 2001, we priced our initial public offering of 6.0 million shares of common stock and commenced trading the following day. After payment of the underwriting discount we received net proceeds of $78.3 million on February 9, 2001, excluding offering costs of approximately $1.5 million. NOTE 2 -- ADOPTION OF SFAS 133 Effective January 1, 2001, we adopted the Financial Accounting Standards Board ("FASB") Statement of Financial Accounting Standard ("SFAS") No. 133, Accounting for Derivative Instruments and Hedging Activities ("SFAS 133") and SFAS No. 138, Accounting for Certain Derivative Instruments and Certain Hedging Activities ("SFAS 138"), an amendment to SFAS 133. SFAS 133 and 138 require that derivatives be reported on the balance sheet at fair value and, if the derivative is not designated as a hedging instrument, changes in fair value must be recognized in earnings in the period of change. If the derivative is designated as a hedge and to the extent such hedge is determined to be effective, changes in fair value are either (a) offset by the change in fair value of the hedged asset or liability (if applicable) or (b) reported as a component of other comprehensive income (loss) in the period of change, and subsequently recognized in earnings when the offsetting hedged transaction occurs. We use derivatives to hedge the price of crude oil and natural gas and effective January 1, 2001, we account for the changes in market value of these derivatives through current earnings. This method will result in increased earnings volatility associated with commodity price fluctuations. Gains and losses on all derivative instruments are included in other income (expense) on the consolidated financial statements. On January 1, 2001, in accordance with the transition provisions of SFAS 133, we recorded a non-cash loss of $52.7 million ($34.3 million after tax) in accumulated other comprehensive loss, representing the cumulative effect of an accounting change to recognize at fair value all cash flow type derivatives. Also on January 1, 2001, we recorded derivative liabilities of $52.7 million. During the first nine months of 2001, losses of $50.7 million ($33.0 million after tax) were reclassified from accumulated other comprehensive loss to earnings. The remaining after-tax loss of $1.3 million recorded in other comprehensive loss will be reclassified to earnings during the last three months of the year ended December 31, 2001 as the transactions 6 are settled. Prior to the adoption of this standard, we included gains and losses on hedging instruments as a component of revenue. As of September 30, 2001, the fair market value of our derivatives consisted of a $2.7 million current asset and a $0.5 million long-term liability. NOTE 3 -- RECENT ACCOUNTING PRONOUNCEMENTS In 2001, the FASB approved SFAS No. 141 "Business Combinations" ("SFAS 141"), No. 142 "Goodwill and Other Intangible Assets" ("SFAS 142"), No. 143 "Accounting for Asset Retirement Obligations" ("SFAS 143") and No. 144 "Accounting for the Impairment or Disposal of Long-Lived Assets" ("SFAS 144"). SFAS 141 requires all business combinations completed after June 30, 2001, be accounted for under the purchase method. This standard also establishes for all business combinations made after June 30, 2001, specific criteria for the recognition of intangible assets separately from goodwill. SFAS 141 also requires that the excess of fair value of acquired assets over cost (negative goodwill) be recognized immediately as an extraordinary gain, rather than deferred and amortized. SFAS 142 addresses the accounting for goodwill and other intangible assets after an acquisition. The most significant changes made by SFAS 142 are: 1) goodwill and intangible assets with indefinite lives will no longer be amortized; 2) goodwill and intangible assets with indefinite lives must be tested for impairment at least annually; and 3) the amortization period for the intangible assets with finite lives will no longer be limited to forty years. We will adopt SFAS 142 effective January 1, 2002, as required. Additionally, SFAS 142 requires that unamortized negative goodwill associated with investments accounted for under the equity method and acquired before July 1, 2001, be recognized in income as a cumulative effect of change in accounting principle. SFAS 143 provides accounting requirements for retirement obligations associated with tangible long-lived assets, including: 1) the timing of liability recognition; 2) initial measurement of the liability; 3) allocation of asset retirement cost to expense; 4) subsequent measurement of the liability; and 5) financial statement disclosures. SFAS 143 requires that an asset retirement cost should be capitalized as part of the cost of the related long- lived asset and subsequently allocated to expense using a systematic and rational method. We will adopt the Statement effective January 1, 2003. The transition adjustment resulting from the adoption of SFAS 143 will be reported as a cumulative effect of a change in accounting principle. SFAS 144 provides that long-lived assets to be disposed of by sale be measured at the lower of carrying amount or fair value less cost to sell, whether reported in continuing operations or in discontinued operations, and broadens the reporting of discontinued operations to include all components of an entity with operations that can be distinguished from the rest of the entity and that will be eliminated from the ongoing operations of the entity in a disposal transaction. SFAS 144 is effective for fiscal years beginning after December 15, 2001. SFAS 141 and SFAS 142 will not apply to us unless we enter into a future business combination. We are currently assessing the impact of SFAS 143 and SFAS 144 on our financial condition and results of operations. NOTE 4 -- ACQUISITION OF OIL & GAS PROPERTIES Gulf of Mexico. In the first nine months of 2001, we acquired fourteen properties in the Gulf of Mexico region. Nine of the properties were acquired in the first quarter, three in the second quarter and two in the third quarter. Eight of the above properties were producing when acquired, with additional development operations planned in 2002. Southern Gas Basin of the U.K. North Sea. In the first quarter of 2001 we acquired two of the three properties covered by an October 2000 letter of intent. We acquired the third property in the second quarter of 2001. None of these properties are currently producing. The total acquisition costs during 2001 for the above properties were approximately $25.2 million. 7 NOTE 5 -- LONG-TERM DEBT Our long-term debt as of September 30, 2001 and December 31, 2000 consisted of the following (in thousands): September 30, December 31, 2001 2000 ------------- ------------ Credit facility............................... $50,000 $ 27,750 Note payable, net of unamortized discount of $1,204.................................... 30,046 - Non-recourse borrowings....................... - 88,779 ------- -------- Total long-term debt......................... $80,046 $116,529 ======= ======== In March 2001, we repaid our then existing bank credit facility and in April 2001 we repaid the full amount borrowed under the non-recourse development program credit agreement. Concurrent with the repayment of our non-recourse agreement, we negotiated with the lender to terminate the overriding royalty interest on all properties previously financed by the lender in exchange for a lump-sum payment of approximately $5.6 million. Upon repayment of our former credit and non-recourse facilities, we entered into a new $100.0 million senior-secured revolving credit facility in April 2001. The amount available for borrowing under the facility is limited to the loan value, as determined by the bank, of oil and gas properties pledged under the facility. This facility is secured by substantially all of our oil and gas properties, as well as by approximately two-thirds of the capital stock of our U.K. subsidiary. If our outstanding balance exceeds our borrowing base at any time, we are required to repay such excess within 30 days and our interest rate during the time an excess exists is increased by 2.00%. Advances under the credit facility can be in the form of either base rate loans or Eurodollar loans. The interest on a base rate loan is a fluctuating rate equal to the higher of the Federal funds rate plus 0.5% and the bank base rate, plus a margin of 0.00%, 0.25% or 0.75% depending on the amount outstanding under the credit agreement. The interest on a Eurodollar loan is equal to the Eurodollar rate, plus a margin of 1.50%, 1.75%, 2.00%, 2.25% or 2.75% depending on the amount outstanding under the credit facility. The credit facility matures in December 2003. Our credit facility contains conditions and restrictive provisions, among other things, (1) prohibiting us to enter into any arrangement to sell or transfer any of our material property, (2) prohibiting a merger into or consolidation with any other person or sell or dispose of all or substantially all of our assets, and (3) maintaining certain financial ratios. On November 5, 2001 we amended our existing credit facility and increased our borrowing base to $70.0 million, thereby increasing our liquidity and flexibility. The margin on the bank base rate was increased to 0.25%, 0.50%, 0.75% or 1.00% depending on the amount outstanding under the credit agreement. The margin on a Eurodollar loan was also increased to 2.25%, 2.50%, 2.875% or 3.125% depending on the amount outstanding under the credit agreement. The amended facility matures in November 2003. Effective June 29, 2001, we issued a promissory note to a purchaser for a face principal amount of $31.3 million which matures in June 2005 and bears interest at a fixed rate of 11.5% per annum. The note is secured by second priority liens on substantially all of our oil and gas properties and is subordinated in right of payment to our existing senior indebtedness. We executed an agreement in connection with the note which contains conditions and restrictive provisions and requires the maintenance of certain financial ratios. Upon consent of the purchaser, which shall not be unreasonably withheld, the note may be repaid prior to the maturity date with an additional repayment premium based on the percentage of the principal amount paid, ranging from 4.5% during the first year to 16.5% in the final year of payment. If the note is paid at maturity, the maximum payment premium of 16.5% is required. The repayment premium is being amortized to interest expense straight-line, over the term of the note which approximates the effective interest method. The resulting liability is included in other long-term liabilities on the consolidated balance sheet. In July 2001, we received proceeds of $30.0 million in consideration for the issuance of the note. The discount of $1.3 million is being amortized to interest expense using the effective interest method. The amount available for borrowing under the note is limited to the loan value of oil and gas properties pledged under the note, as determined by the purchaser. The borrowing base is scheduled for redetermination at least once every six months. If our outstanding balance exceeds the borrowing base at any time, we are required to repay such excess within 10 days subject to the provisions of the agreement. 8 NOTE 6 -- EARNINGS PER SHARE Basic loss per share is computed by dividing net loss available to common shareholders by the weighted average number of common shares outstanding during the period. Diluted loss per share is determined on the assumption that outstanding stock options have been converted using the average price for the period. For purposes of computing diluted earnings per share in a period which a loss occurs, potential common shares have been excluded from the computation of weighted average common shares outstanding because their effect is antidilutive. Basic and diluted net loss per share is computed based on the following information (in thousands, except per share amounts):
Three Months Ended Nine Months Ended September 30, September 30, ------------------- ------------------ 2001 2000 2001 2000 ------- ------- ------- ------- Net loss.................................................. $(6,499) $(4,251) $(10,161) $(5,964) ======= ======= ======= ======= Weighted average shares outstanding - basic and diluted... 20,297 14,286 19,499 14,286 ======= ======= ======= ======= Net loss per share - basic and diluted.................... $ (0.32) $ (0.30) $ (0.52) $ (0.42) ======= ======= ======= =======
NOTE 7 -- STOCK OPTION COMPENSATION We recorded a non-cash charge to compensation expense of approximately $2.9 million for the nine months ended September 30, 2001, for options granted since September 1999 through the date of our initial public offering on February 5, 2001, as well as for certain options granted prior to September 1999 and exercised during the current period. The expense will be recognized in the periods in which the options vest. Each option is divided into three equal portions corresponding to the three vesting dates, with the related non-cash compensation expense amortized straight-line method over the period between the initial public offering and the vesting date of the options. During the second quarter, the first option vesting date occurred, allowing option holders the opportunity to exercise one-third of their options. Of the options exercised during the second quarter, certain optionees elected to receive cash upon exercise of their options, whereby we purchased 75,840 shares and recorded such purchase as treasury stock using the cost method. NOTE 8 -- EXTRAORDINARY ITEM For the nine months ended September 30, 2001, we recognized an extraordinary loss, net of tax of $0.3 million, related to the early extinguishment of our non-recourse borrowings. 9 NOTE 9 -- COMPREHENSIVE INCOME (LOSS) Comprehensive income (loss) consists of net income (loss), as reflected on the consolidated statement of operations, and other gains and losses affecting stockholders' equity that are excluded from net income (loss). We recorded other comprehensive income (loss) for the first time in the first quarter of 2001. Total comprehensive income (loss) for the three months and nine months ended September 30, 2001 is as follows (in thousands):
Three Nine Months Months Ended Ended September 30, September 30, 2001 2001 ------------ ------------ Net loss.................................................................. $( 6,499) $(10,161) -------- -------- Other comprehensive income (loss), net of tax: Cumulative effect of change in accounting principle - January 1, 2001... - (34,252) Reclassification adjustment for settled contracts....................... 3,991 32,972 Foreign currency translation adjustment................................. 172 108 ------- -------- Other comprehensive income (loss)...................................... 4,163 (1,172) ------- -------- Comprehensive loss........................................................ $( 2,336) $(11,333) ======== ========
There were no items in other comprehensive income (loss) during 2000. NOTE 10 -- LIQUIDITY, COMMITMENTS AND CONTINGENCIES Our working capital position has improved since September 30, 2001 as a result of the renegotiation of our existing credit facility, cash flows from operations and a reduction of expenditures related to the curtailment of current development activity. The borrowing base under the $100.0 million credit facility was increased from $50.0 million as of September 30, 2001 to $70.0 million on November 5, 2001. As a result of recent increases in our oil and gas reserves and production levels, we expect that the borrowing base will be increased from its current level at the next scheduled borrowing base review on or about January 1, 2002, further improving our working capital position. In response to our working capital deficit of $32.4 million as of September 30, 2001, and lower gas prices prevailing in the third quarter and softening development costs which we expect will continue into 2002, we have significantly reduced our planned development activities in the third and fourth quarters of 2001 and postponed these activities until 2002. We are currently in negotiations with several lenders and potential investors to provide significant additional private capital. Although there can be no assurance we will be successful in negotiating these transactions, we believe these transactions, combined with our current credit facility and cash flow from operating activities will provide us with additional flexibility and liquidity, including liquidity to meet our future development plans. If we are not successful in closing these transactions, our ability to develop and produce our oil and gas properties as planned will be negatively impacted. On August 28, 2001, we signed an agreement to acquire an offshore block in the Outer Continental Shelf of the Gulf of Mexico. Principal assets to be acquired included interests in proved oil and gas reserves and associated wells, platforms and facilities. The agreement contemplated a closing date of September 28, 2001. However, due to certain circumstances including events which transpired on September 11, 2001, we were unable to obtain necessary financing and consummate the transaction by that date. On October 9, 2001, we entered into an amendment to extend the agreement and scheduled closing date to October 31, 2001 to allow us to complete our financing arrangements. As contemplated by the agreement, we released to the seller $2.0 million previously deposited in escrow, which amount is nonrefundable, and reduced the purchase price by a corresponding amount. In addition, we paid $1.0 million to the seller on October 23, 2001, which is non refundable. To date, the closing of the transaction has not occurred. We are currently in discussions with the seller to complete the transaction and are seeking to obtain the necessary financing. Included in other current assets on the consolidated balance sheet at September 30, 2001 is $2.0 million paid into escrow prior to the end of the third quarter and subsequently released to the seller. If the transaction is not ultimately consummated by year end, or likely to occur, all amounts paid to the seller will be charged to expense. In addition, we would be required to pay the seller the sum of the difference, if any, between the purchase price, as adjusted at the date of closing and any lower purchase price paid by a third party to acquire the block from the seller and the costs and expenses incurred by the seller. The amount of any such additional payment is presently not ascertainable, but would be an expense which would reduce earnings in the period in which the obligation is incurred. Any such payment to the seller could be material and if so, would have a substantial negative impact on our financial position, results of operations and cash flows. In August 2001, Burlington Resources Inc. filed suit against us alleging formation of a contract with us and our breach of the alleged contract. The complaint seeks compensatory damages of approximately $1.1 million. We believe that this claim is without merit, and we intend to defend it vigorously. We are, in the ordinary course of business, a claimant and/or defendant in various legal proceedings. Management does not believe that the outcome of these legal proceedings, individually, and in the aggregate will have a materially adverse effect on our financial condition, results of operations or cash flows. 10 ATP OIL & GAS CORPORATION AND SUBSIDIARIES ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Overview ATP Oil & Gas Corporation ("ATP") was incorporated in Texas in 1991. We are engaged in the acquisition, development and production of natural gas and oil properties in the outer continental shelf of the Gulf of Mexico, in the shallow- deep waters of the Gulf of Mexico and in the Southern Gas Basin of the U.K. North Sea. We primarily focus our efforts on natural gas and oil properties with proved undeveloped reserves that are economically attractive to us but are not strategic to major or exploration-oriented independent oil and gas companies. We attempt to achieve a high return on our investment in these properties by limiting our up-front acquisition costs and by developing our acquisitions quickly. On February 5, 2001, we priced our initial public offering of 6.0 million shares of common stock and commenced trading the following day. After payment of the underwriting discount we received net proceeds of $78.3 million on February 9, 2001, excluding offering costs of approximately $1.5 million. We used the net proceeds from our initial public offering, together with the proceeds from our new credit facility, to repay all of our outstanding debt under our development program credit agreement and our prior bank credit facility and to acquire natural gas and oil properties. Results of Operations Prior to the January 1, 2001 adoption of Financial Accounting Standards Board ("FASB") Statement of Financial Accounting Standard ("SFAS") No. 133, Accounting for Derivative Instruments and Hedging Activities ("SFAS 133") and SFAS No. 138, Accounting for Certain Derivative Instruments and Certain Hedging Activities ("SFAS 138"), an amendment to SFAS 133, we previously included the effects of our risk management activities as an offset to revenue. Upon adoption of the standard, any gains or losses from these activities are now included in other income (expense), as we have elected not to account for our hedging activities under the hedge accounting provisions allowed in the standard. For comparative purposes though, the following table sets forth selected financial and operating information for our natural gas and oil operations inclusive of the effects of risk management activities:
Three Months Ended Nine Months Ended September 30, September 30, ------------------- --------------------- 2001 2000 2001 2000 ------- ------- -------- -------- Production: Natural gas (MMcf)................................. 5,512 5,498 16,298 17,302 Oil and condensate (MBbls)......................... 165 96 368 275 ------- ------- -------- -------- Total (Mmcfe).................................... 6,504 6,079 18,505 18,953 Revenues (in thousands): Natural gas........................................ $15,574 $24,524 $ 77,699 $ 62,082 Effects of risk management activities (1).......... 2,040 (8,711) (26,669) (13,794) ------- ------- -------- -------- Total............................................ $17,614 $15,813 $ 51,030 $ 48,288 ======= ======= ======== ======== Oil and condensate................................. $ 3,997 $ 2,965 $ 9,382 $ 7,954 Effects of risk management activities.............. - (421) - (1,152) ------- ------- -------- -------- Total............................................ $ 3,997 $ 2,544 $ 9,382 $ 6,802 ======= ======= ======== ======== Natural gas, oil and condensate.................... $19,571 $27,489 $ 87,081 $ 70,036 Effects of risk management activities (1).......... 2,040 (9,132) (26,669) (14,946) ------- ------- -------- -------- Total............................................ $21,611 $18,357 $ 60,412 $ 55,090 ======= ======= ======== ========
Table continued on following page 11
Three Months Ended Nine Months Ended September 30, September 30, ------------------- --------------------- 2001 2000 2001 2000 ------- ------- -------- -------- Average sales price per unit: Natural gas (per Mcf).............................. $ 2.83 $ 4.46 $ 4.77 $ 3.59 Effects of risk management activities (per Mcf).... 0.37 (1.58) (1.64) (0.80) ------- ------- -------- -------- Total............................................ $ 3.20 $ 2.88 $ 3.13 $ 2.79 ======= ======= ======== ======== Oil and condensate (per Bbl)....................... $ 24.20 $ 30.61 $ 25.50 $ 28.89 Effects of risk management activities (per Bbl).... - (4.35) - (4.18) ------- ------- -------- -------- Total............................................ $ 24.20 $ 26.26 $ 25.50 $ 24.71 ======= ======= ======== ======== Natural gas, oil and condensate (per Mcfe)......... $ 3.01 $ 4.52 $ 4.71 $ 3.70 Effects of risk management activities (per Mcfe)... 0.31 (1.50) (1.44) (0.79) ------- ------- -------- -------- Total............................................ $ 3.32 $ 3.02 $ 3.27 $ 2.91 ======= ======= ======== ======== Expenses (per Mcfe): Lease operating expense............................ $ 0.38 $ 0.32 $ 0.52 $ 0.44 General and administrative......................... 0.41 0.21 0.36 0.21 Depreciation, depletion and amortization........... 2.06 2.30 2.08 1.62
--------------- (1) For 2001, represents the net loss on the settlement of derivatives attributable to production of 6,504 Mmcfe and 18,505 Mmcfe for the three and nine months ended September 30, 2001, respectively. Three Months Ended September 30, 2001 Compared with Three Months Ended September 30, 2000 For the three months ended September 30, 2001, we reported a net loss of $6.5 million, or $0.32 per basic and diluted share, on total revenue of $20.9 million, as compared with a net loss of $4.3 million, or $0.30 per basic and diluted share, on total revenue of $29.6 million (excluding hedging effects) in the third quarter of 2000. Adjusted EBITDA in the third quarter of 2001 was $15.8 million compared with $14.2 million in the third quarter of 2000. Adjusted EBITDA means earnings before interest expense, income taxes, depreciation, depletion and amortization, impairments on oil and gas properties, unrealized gains and losses, non-cash compensation expense and extraordinary items. Our Adjusted EBITDA margin was 69% in the third quarter of 2001 and 2000. Adjusted EBITDA margin represents Adjusted EBITDA divided by revenues which are inclusive of any realized derivative gains and losses. Adjusted EBITDA is not a calculation based on generally accepted accounting principles and may not be comparable to other similarly titled measures of other companies. Oil and Gas Revenue. Excluding the effects of risk management activities, our revenue from natural gas and oil production for the third quarter of 2001 decreased from the same period in 2000 from $27.5 million to $19.6 million. This decrease was primarily due to an approximate 37% decrease in natural gas prices partially offset by an 8% increase in production. The increase in production volumes from 6.1 Bcfe to 6.5 Bcfe was attributable to additional properties acquired in 2001 and development activities completed in 2001. Risk management activities, which were included in oil and gas revenues in 2000 but excluded in compliance with SFAS 133 in 2001, would have increased oil and natural gas revenues by $2.0 million, or $0.31 per Mcfe in the third quarter of 2001 and decreased oil and natural gas revenues by $9.1 million, or $1.50 per Mcfe, in the third quarter of 2000. Marketing Revenue. Revenues from natural gas marketing activities decreased to $1.3 million in the third quarter of 2001 as compared to $2.1 million in the third quarter of 2000. This decrease was due to a decrease in the sales price per MMBtu. The average sales price per MMBtu decreased from $4.58 in the third quarter of 2000 to $2.85 in the third quarter of 2001. 12 Lease Operating Expense. Our lease operating expenses for the third quarter of 2001 increased to $2.5 million from $1.9 million in the third quarter of 2000. This increase was primarily the result of an increased number of properties. Gas Purchased-Marketing. Our cost of purchased gas was $1.3 million for the third quarter of 2001 compared to $2.1 million for the third quarter of 2000. The average cost decreased from $4.47 per MMBtu in 2000 to $2.74 per MMBtu in 2001. Geological and Geophysical Expense. In the third quarter of 2001, we recorded $0.8 million of costs related to the acquisition of 3-D seismic data purchased for development purposes on our recently acquired properties located in the UK. General and Administrative Expense. General and administrative expense increased to $2.7 million for the third quarter of 2001 compared to $1.3 million for the same period in 2000. The primary reason for the increase was the result of higher compensation and related expenses due to an increase in the number of employees from 31 at the end of the third quarter of 2000 to 44 at the end of the third quarter of 2001. Non-Cash Compensation Expense. In the third quarter of 2001, we recorded a non-cash charge to compensation expense of approximately $0.5 million for options granted since September 1999 through the date of our initial public offering on February 5, 2001. The total expected expense as of the measurement date will be recognized in the periods in which the option vests. Each option is divided into three equal portions corresponding to the three vesting dates (April 10, 2001, February 9, 2002, and February 9, 2003), with the related compensation cost for each portion amortized straight-line over the period to the vesting date. Depreciation, Depletion and Amortization Expense. Depreciation, depletion and amortization expense decreased 4% from $14.0 million in the third quarter 2000 to $13.4 million in the third quarter 2001 due to impairments taken in previous quarters. Impairment Expense. As of September 30, 2001, the future undiscounted cash flows were less than their individual net book value on two of our properties. As a result, we recorded impairments of $3.7 million in the third quarter of 2001. These impairments were primarily the result of reductions in expected future undiscounted cash flows on each property due to reserve adjustments at September 30, 2001. For the third quarter of 2000, we recorded an impairment of $0.8 million related to one property as a result of a reduction in recoverable reserves. Other Income (Expense). In the third quarter of 2001, we recorded a loss on derivative instruments of $3.3 million comprised of a realized gain of $2.0 million and an unrealized loss of $5.3 million. The realized gain represents derivative contracts settled in the third quarter of 2001, while the offsetting loss represents the change in the fair market value of the open derivative positions at September 30, 2001. Prior to the adoption of SFAS 133, realized gains or losses were recorded as a component of revenue. Interest expense for the third quarter of 2001 decreased to $2.1 million from $3.3 million in the comparable quarter of 2000 primarily due to lower borrowing levels in 2001. We did not capitalize any interest for the three months ended September 30, 2001 or 2000. Nine Months Ended September 30, 2001 Compared with Nine Months Ended September 30, 2000 For the nine months ended September 30, 2001, we reported a net loss of $10.2 million, or $0.52 per basic and diluted share, on total revenue of $93.4 million, as compared with a net loss of $6.0 million, or $0.42 per basic and diluted share, on total revenue of $75.1 million (excluding hedging effects) in the first nine months of 2000. Adjusted EBITDA in the first nine months of 2001 was $44.2 million compared with $41.7 million in the first nine months of 2000. Our Adjusted EBITDA margin was 66% in the first nine months of 2001 and 69% in the comparable period in 2000. 13 Oil and Gas Revenue. Excluding the effects of risk management activities, our revenue from natural gas and oil production for the first nine months of 2001 increased approximately 24% over the same period in 2000, from $70.0 million to $87.1 million. This increase was primarily due to an approximate 33% increase in natural gas prices, partially offset by a 2% decrease in production. The decrease in production volumes from 18.9 Bcfe to 18.5 Bcfe was attributable to natural declines in our producing properties. Risk management activities, which were included in oil and gas revenues in 2000 but excluded in compliance with SFAS 133 in 2001, would have reduced oil and natural gas revenues by $26.7 million, or $1.44 per Mcfe in the first nine months of 2001 compared with $14.9 million, or $0.79 per Mcfe in the first nine months of 2000. Marketing Revenue. Revenues from natural gas marketing activities increased to $6.3 million in the first nine months of 2001 as compared to $5.0 million in the first nine months of 2000. This increase was due to an increase in the sales price per MMBtu. The average sales price per MMBtu increased from $3.67 in the first nine months of 2000 to $4.60 in the first nine months of 2001. Lease Operating Expense. Our lease operating expenses for the first nine months of 2001 increased to $9.7 million from $8.4 million in the first nine months of 2000. This increase was primarily the result of an increased number of properties. Gas Purchased-Marketing. Our cost of purchased gas was $6.1 million for the first nine months of 2001 compared to $4.9 million for the first nine months of 2000. The average cost increased from $3.54 per MMBtu in 2000 to $4.49 per MMBtu in 2001. Geological and Geophysical Expense. In the first nine months of 2001, we recorded $1.2 million of costs related to the acquisition of 3-D seismic data purchased for development purposes on our properties located in the Gulf of Mexico ($0.5 million) and U.K. ($0.7 million). General and Administrative Expense. General and administrative expense increased to $6.7 million for the first nine months of 2001 compared to $4.0 million for the same period in 2000. The primary reason for the increase was the result of higher compensation and related expenses due to an increase in the number of employees from 31 at the end of the first nine months of 2000 to 44 at the end of first nine months of 2001. In addition, our U.K. office was opened in the third quarter of 2000. Non-cash Compensation Expense. In the first nine months of 2001, we recorded a non-cash charge to compensation expense of approximately $2.9 million for options granted since September 1999 through the date of our initial public offering on February 5, 2001, as well as for certain options granted prior to September 1999 and exercised during the current period. The total expected expense as of the measurement date will be recognized in the periods in which the option vests. Each option is divided into three equal portions corresponding to the three vesting dates (April 10, 2001, February 9, 2002, and February 9, 2003), with the related compensation cost for each portion amortized straight- line over the period to the vesting date. Depreciation, Depletion and Amortization Expense. Depreciation, depletion and amortization expense increased 25% from $30.7 million in the first nine months of 2000 to $38.5 million in the first nine months of 2001. Impairment Expense. As of September 30, 2001, the future undiscounted cash flows were less than their individual net book value on six of our properties. As a result, we recorded impairments of $17.8 million in the first nine months of 2001. These impairments were primarily the result of drilling a non- commercial development well at our Main Pass 282 property ($8.3 million) and a reduction in expected future undiscounted cash flows on the other properties due to reserve adjustments. For the first nine months of 2000, we recorded an impairment of $7.0 million related to one property as a result of a reduction in recoverable reserves. 14 Other Income (Expense). In the first nine months of 2001, we recorded a loss on derivative instruments of $17.5 million comprised of a realized loss of $26.3 million and an unrealized gain of $8.8 million. The realized loss represents derivative contracts settled in the first nine months of 2001, while the offsetting gain represents the change in the fair market value of the open derivative positions at September 30, 2001. Prior to the adoption of SFAS 133, realized gains or losses were recorded as a component of revenue. Interest expense decreased $1.3 million from $8.4 million in the first nine months of 2000 to $7.1 million in the first nine months of 2001. We capitalized none and $0.7 million of interest for the nine months ended September 30, 2001 and 2000, respectively. Income Tax Benefit - Deferred. Income tax benefit of $3.9 million was recognized for the nine months ended September 30, 2001 compared to an income tax benefit of $3.2 million for the nine months ended September 30, 2000. The effective income tax rates were approximately 29% and 35% for the first nine months of 2001 and 2000, respectively. The difference in the income tax rate is the result of permanent tax differences related to our U.K. subsidiary. LIQUIDITY AND CAPITAL RESOURCES General We have financed our acquisition and development activity through a combination of project-based development arrangements, bank borrowings and proceeds from our February 2001 initial public offering, as well as cash from operations. We believe that our capital resources, cash flow from operations and borrowings under our existing or new credit facilities will be sufficient to fund short-term liquidity as well as fund ongoing capital expenditures for the foreseeable future. However, future cash flows are subject to a number of variables including the level of production and oil and natural gas prices. No assurance can be given that operations and other capital resources will provide cash in sufficient amounts to maintain planned levels of operations and capital expenditures. Cash Flows Nine Months Ended, September 30, ------------------ 2001 2000 ------- ------ (in millions) Cash provided by (used in) Operating activities....... $ 62.1 $ 35.3 Investing activities....... (108.8) (50.8) Financing activities....... 38.1 16.8 Cash provided by operating activities in the first nine months of 2001 primarily reflects increased price realizations, partially offset by net cash used in price risk management activities. Cash used in investing activities totaled $108.8 million in the first nine months of 2001 as compared to $50.8 million in the same period of 2000. The 2001 amount includes expenditures on oil and gas properties of $108.4 million, of which $25.2 million was used for the acquisition of 17 properties in the Gulf of Mexico and Southern Gas Basin area of the U.K. North Sea, $5.6 million was used to purchase the overriding royalty interests associated with our non- recourse debt and $77.6 million was used for development. Comparable expenditures for acquisition and development in 2000 were $2.6 million and $48.0 million, respectively. Cash provided from financing activities includes the proceeds from our initial public offering in February 2001 of $78.3 million including the underwriters' discount. We also incurred costs of approximately $0.9 million in connection with the offering, which in addition to costs incurred in the fourth quarter of 2000, totaled approximately $1.5 million. Financing activities also included proceeds of $65.0 million from our new credit facility and $30.0 million from a promissory note (see Credit Agreements). Financing activities also included the repayment of our prior credit facilities of $119.9 million and $15.0 million of our current facility and promissory note. 15 Credit Agreements In March 2001, we repaid our then existing bank credit facility and in April 2001 we repaid the full amount borrowed under the non-recourse development program credit agreement. Concurrent with the repayment, we negotiated with the lender to terminate the overriding royalty interest on all properties previously financed by the lender in exchange for a lump-sum payment of approximately $5.6 million. Upon repayment of our former credit and non-recourse facilities, we entered into a new $100.0 million senior-secured revolving credit facility in April 2001. The amount available for borrowing under the facility is limited to the loan value, as determined by the bank, of oil and gas properties pledged under the facility. The borrowing base at September 30, 2001 was $50.0 million. This facility is secured by substantially all of our oil and gas properties, as well as by approximately two-thirds of the capital stock of our U.K. subsidiary. If our outstanding balance exceeds our borrowing base at any time, we are required to repay such excess within 30 days and our interest rate during the time an excess exists is increased by 2.00%. Advances under the credit facility can be in the form of either base rate loans or Eurodollar loans. The interest on a base rate loan is a fluctuating rate equal to the higher of the Federal funds rate plus 0.5% and the bank base rate, plus a margin of 0.00%, 0.25% or 0.75% depending on the amount outstanding under the credit agreement. The interest on a Eurodollar loan is equal to the Eurodollar rate, plus a margin of 1.50%, 1.75%, 2.00%, 2.25% or 2.75% depending on the amount outstanding under the credit facility. The credit facility matures in December 2003. Our credit facility contains conditions and restrictive provisions, among other things, (1) prohibiting us to enter into any arrangement to sell or transfer any of our material property, (2) prohibiting a merger into or consolidation with any other person or sell or dispose of all or substantially all of our assets, and (3) maintaining certain financial ratios. On November 5, 2001 we amended our existing credit facility and increased our borrowing base from $50.0 million to $70.0 million, thereby increasing our liquidity and flexibility. The margin on the bank base rate was increased to 0.25%, 0.50%, 0.75% or 1.00% depending on the amount outstanding under the credit agreement. The margin on a Eurodollar loan was also increased to 2.25%, 2.50%, 2.875% or 3.125% depending on the amount outstanding under the credit agreement. The amended facility matures in November 2003. Effective June 29, 2001, we issued a promissory note to a purchaser for a face principal amount of $31.3 million which matures in June 2005 and bears interest at a fixed rate of 11.5% per annum. The note is secured by third priority liens on substantially all of our oil and gas properties and is subordinated in right of payment to our existing senior indebtedness. We executed an agreement in connection with the note which contains conditions and restrictive provisions and requires the maintenance of certain financial ratios. Upon consent of the purchaser, which shall not be unreasonably withheld, the note may be repaid prior to the maturity date with an additional repayment premium based on the percentage of the principal amount paid, ranging from 4.5% during the first year to 16.5% in the final year of payment. If the note is paid at maturity, the maximum payment premium of 16.5% is required. The repayment premium is being amortized to interest expense straight-line, over the term of the note which approximates the effective interest method. The resulting liability is included in other long-term liabilities on the consolidated balance sheet. In July 2001, we received proceeds of $30.0 million in consideration for the issuance of the note. The discount of $1.3 million is being amortized to interest expense using the effective interest method. The amount available for borrowing under the note is limited to the loan value of oil and gas properties pledged under the note, as determined by the purchaser. The borrowing base is scheduled for redetermination at least once every six months. If our outstanding balance exceeds the borrowing base at any time, we are required to repay such excess within 10 days subject to the provisions of the agreement. Working Capital Our working capital position has improved since September 30, 2001 as a result of the renegotiation of our existing credit facility, cash flow from operations and a reduction of expenditures related to the curtailment of current development activity. The borrowing base under the $100.0 million credit facility was increased from $50.0 million as of September 30, 2001 to $70.0 million on November 5, 2001. As a result of recent increases in our oil and gas reserves and production levels, we expect that the borrowing base will be increased from its current level at the 16 next scheduled borrowing base review on or about January 1, 2002, further improving our working capital position. In response to our working capital deficit of $32.4 million as of September 30, 2001, and lower gas prices prevailing in the third quarter and softening development costs which we expect will continue into 2002, we have significantly reduced our planned development activities in the third and fourth quarters of 2001 and postponed activity until 2002. We are currently in negotiations with several lenders and potential investors to provide significant additional private capital. Although there can be no assurance we will be successful in negotiating these transactions, we believe these transactions, combined with our current credit facility and cash flow from operating activities will provide us with additional flexibility and liquidity, including liquidity to meet our future development plans. If we are not successful in closing these transactions, our ability to develop and produce our oil and gas properties will be negatively impacted. Commitments and Contingencies On August 28, 2001, we signed an agreement to acquire an offshore block in the Outer Continental Shelf of the Gulf of Mexico. Principal assets to be acquired included interests in proved oil and gas reserves and associated wells, platforms and facilities. The agreement, as amended, contemplated a closing date of October 31, 2001. However, due to certain circumstances including events which transpired on September 11, 2001, we were unable to obtain necessary financing and consummate the transaction by that date. We are currently in discussions with the seller to complete the transaction and are seeking to obtain the necessary financing. If we are unable to consummate this acquisition, we may be required to pay additional amounts which would reduce earnings in the period such obligation is incurred. Any such reduction could be material to our financial position, results of operations and cash flows in such period. See Note 10 in the notes to the consolidated financial statements located elsewhere in this report for further information. In August 2001, Burlington Resources Inc. filed suit against us alleging formation of a contract with us and our breach of the alleged contract. The complaint seeks compensatory damages of approximately $1.1 million. We believe that this claim is without merit, and we intend to defend it vigorously. We are, in the ordinary course of business, a claimant and/or defendant in various legal proceedings. Management does not believe that the outcome of these legal proceedings, individually, and in the aggregate will have a materially adverse effect on our financial condition, results of operations or cash flows. Adoption of SFAS 133 Effective January 1, 2001, we adopted SFAS No. 133 and SFAS No. 138, an amendment to SFAS 133. SFAS 133 and 138 require that derivatives be reported on the balance sheet at fair value and, if the derivative is not designated as a hedging instrument, changes in fair value must be recognized in earnings in the period of change. If the derivative is designated as a hedge and to the extent such hedge is determined to be effective, changes in fair value are either (a) offset by the change in fair value of the hedged asset or liability (if applicable) or (b) reported as a component of other comprehensive income (loss) in the period of change, and subsequently recognized in earnings when the offsetting hedged transaction occurs. We use derivatives to hedge the price of crude oil and natural gas and effective January 1, 2001, we account for the changes in market value of these derivatives through current earnings. This method will result in increased earnings volatility associated with commodity price fluctuations. Gains and losses on all derivative instruments are included in other income (expense) on the consolidated financial statements. On January 1, 2001, in accordance with the transition provisions of SFAS 133, we recorded a non-cash loss of $52.7 million ($34.3 million after tax) in accumulated other comprehensive loss, representing the cumulative effect of an accounting change to recognize at fair value all cash flow type derivatives. Also on January 1, 2001, we recorded derivative liabilities of $52.7 million. During the first nine months of 2001, losses of $50.7 million ($33.0 million after tax) were reclassified from accumulated other comprehensive loss to earnings. The remaining after-tax loss of $1.3 million recorded in other comprehensive loss will be reclassified to earnings during the last three months of the year ended December 31, 2001 as the transactions are settled. Prior to the adoption of this standard, we included gains and losses on hedging instruments as a component of revenue. As of September 30, 2001, the fair market value of our derivatives consisted of a $2.7 million current asset and a $0.5 million long-term liability. 17 Recent Accounting Pronouncements In 2001, the FASB approved SFAS No. 141 "Business Combinations" ("SFAS 141"), No. 142 "Goodwill and Other Intangible Assets" ("SFAS 142") No. 143 "Accounting for Asset Retirement Obligations" ("SFAS 143") and No. 144 "Accounting for the Impairment or Disposal of Long-Lived Assets" ("SFAS 144"). SFAS 141 requires all business combinations completed after June 30, 2001, be accounted for under the purchase method. This standard also establishes for all business combinations made after June 30, 2001, specific criteria for the recognition of intangible assets separately from goodwill. SFAS 141 also requires that the excess of fair value of acquired assets over cost (negative goodwill) be recognized immediately as an extraordinary gain, rather than deferred and amortized. SFAS 142 addresses the accounting for goodwill and other intangible assets after an acquisition. The most significant changes made by SFAS 142 are: 1) goodwill and intangible assets with indefinite lives will no longer be amortized; 2) goodwill and intangible assets with indefinite lives must be tested for impairment at least annually; and 3) the amortization period for the intangible assets with finite lives will no longer be limited to forty years. We will adopt SFAS 142 effective January 1, 2002, as required. Additionally, SFAS 142 requires that unamortized negative goodwill associated with investments accounted for under the equity method and acquired before July 1, 2001, be recognized in income as a cumulative effect of change in accounting principle. SFAS 143 provides accounting requirements for retirement obligations associated with tangible long-lived assets, including: 1) the timing of liability recognition; 2) initial measurement of the liability; 3) allocation of asset retirement cost to expense; 4) subsequent measurement of the liability; and 5) financial statement disclosures. SFAS 143 requires that an asset retirement cost should be capitalized as part of the cost of the related long- lived asset and subsequently allocated to expense using a systematic and rational method. We will adopt the Statement effective January 1, 2003. The transition adjustment resulting from the adoption of SFAS 143 will be reported as a cumulative effect of a change in accounting principle. SFAS 144 provides that long-lived assets to be disposed of by sale be measured at the lower of carrying amount or fair value less cost to sell, whether reported in continuing operations or in discontinued operations, and broadens the reporting of discontinued operations to include all components of an entity with operations that can be distinguished from the rest of the entity and that will be eliminated from the ongoing operations of the entity in a disposal transaction. SFAS 144 is effective for fiscal years beginning after December 15, 2001. SFAS 141 and SFAS 142 will not apply to us unless we enter into a future business combination. We are currently assessing the impact of SFAS 143 and SFAS 144 on our financial condition and results of operations. ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS We are exposed to various market risks, including volatility in natural gas and oil commodity prices and interest rates. To manage such exposure, we monitor our expectations of future commodity prices and interest rates when making decisions with respect to risk management. All of our derivative contracts are entered into with major financial or oil and gas institutions and the risk of credit loss is considered insignificant. Commodity Price Risk. Our revenues, profitability and future growth depend substantially on prevailing prices for natural gas and oil. Prices also affect the amount of cash flow available for capital expenditures and our ability to borrow and raise additional capital. The amount we can borrow under our bank credit facility is subject to periodic redetermination based in part on changing expectations of future prices. Lower prices may also reduce the amount of natural gas and oil that we can economically produce. We currently sell most of our natural gas and oil production under price sensitive or market price contracts. To reduce exposure to fluctuations in natural gas and oil prices and to achieve more predictable cash flow, we periodically enter into derivative arrangements that usually consist of swaps or price collars that are settled in cash. However, these contracts also limit the benefits we would realize if commodity prices increase. We generally acquire properties at prices that are below the value of estimated reserves at the then current natural gas and oil prices. We may enter into short term derivative arrangements if 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. All of our commodity derivative financial instruments are accounted for on a mark-to-market basis beginning January 1, 2001 upon adoption of SFAS 133 and SFAS 138 discussed previously. 18 As of September 30, 2001, we had the following financial hedges on natural gas in place: Swaps Collars and Options ------------------- ------------------------- Average Average Average Average MMBtu/Day $/MMBtu MMBtu/Day $/MMBtu --------- ------- --------- ------------ Period: Fourth quarter 2001...... 16,100 2.92 3,100 5.10 to 6.15 2002..................... 10,000 3.00 - - January - October 2003... 10,000 3.00 - - In addition to the above financial hedges on natural gas, we also have in place a written call option contract that provides us a price for natural gas above the then prevailing market price, but with a ceiling price. For October 2001, we received NYMEX settlement plus $0.15 with a ceiling price of $3.50 per MMBtu on 10,000 MMBtu per day. In October 2001, we entered into additional natural gas swaps beginning November 1, 2001 and terminating at varying future dates. The volumes contracted are 5,000 and 10,000 MMBtu per day at prices ranging from $2.83 to $3.07. Interest Rate Risk. We are exposed to changes in interest rates. Changes in interest rates affect the interest earned on our cash and cash equivalents and the interest rate paid on borrowings under the credit agreements. Under our current policies, we do not use interest rate derivative instruments to manage exposure to interest rate changes. FORWARD-LOOKING STATEMENTS AND ASSOCIATED RISKS Some of the information included in this quarterly report includes assumptions, expectations, projections, intentions or beliefs about future events. These statements are intended as "forward-looking statements" under the Private Securities Litigation Reform Act of 1995. We caution that assumptions, expectations, projections, intentions and beliefs about future events may and often do vary from actual results and the differences can be material. All statements in this document that are not statements of historical fact are forward looking statements. Forward looking statements include, but are not limited to: . projected operating or financial results; . budgeted or projected capital expenditures; . statements about pending or recent acquisitions, including the anticipated closing dates; . statements regarding financing which may be obtained in the future; . expectations regarding our planned expansions and the availability of acquisition opportunities; . statements about the expected drilling of wells and other planned development activities; . expectations regarding natural gas and oil markets in the United States and the United Kingdom; and . timing and amount of future production of natural gas and oil. When used in this document, the words "anticipate," "estimate," "project," "forecast," "may," "should," and "expect" reflect forward-looking statements. 19 There can be no assurance that actual results will not differ materially from those expressed or implied in such forward looking statements. Some of the key factors which could cause actual results to vary from those expected include: . the timing and extent of changes in natural gas and oil prices; . the timing of planned capital expenditures and availability of acquisitions; . timing and availability of adequate financing upon acceptable terms; . the inherent uncertainties in estimating proved reserves and forecasting production results; . operational factors affecting the commencement or maintenance of producing wells, including catastrophic weather related damage, unscheduled outages or repairs, or unanticipated changes in drilling equipment costs or rig availability; . the condition of the capital markets generally, which will be affected by interest rates, foreign currency fluctuations and general economic conditions; . cost and other effects of legal and administrative proceedings, settlements, investigations and claims, including environmental liabilities which may not be covered by indemnity or insurance; and . other U.S. or United Kingdom regulatory or legislative developments which affect the demand for natural gas or oil generally, increase the environmental compliance cost for our production wells or impose liabilities on the owners of such wells. 20 PART II. OTHER INFORMATION ITEM 1. LEGAL PROCEEDINGS We are, in the ordinary course of business, a claimant and/or defendant in various legal proceedings. Management does not believe that the outcome of these legal proceedings, individually, and in the aggregate will have a materially adverse effect on our financial condition, results of operations or cash flows. See Note 10 in the notes to our consolidated financial statements located elsewhere in this report. ITEM 2. CHANGES IN SECURITIES AND USE OF PROCEEDS On September 18, 2000, we filed a registration statement on Form S-1 (File No. 333-46034) relating to an initial public offering of 6,000,000 shares of our common stock for an aggregate offering price of $84.0 million. On February 5, 2001, the registration statement on Form S-1 was declared effective. The public offering price was $14.00 per share of common stock, and the underwriting discounts and commissions were $0.94 per share of common stock. The offering closed on February 9, 2001. The proceeds from the offering, after deducting the underwriting discounts and commissions, but before deducting expenses associated with the offering, were $78.3 million. Our net offering proceeds, after deducting the underwriting discounts, commissions and expenses associated with the offering, were $76.8 million. We used the net proceeds from our initial public offering, together with the proceeds from our new credit facility, to repay all of our outstanding debt under our development program credit agreement and our prior bank credit facility and to acquire natural gas and oil properties. The managing underwriters for the offering were Lehman Brothers, CIBC World Markets Corp., Dain Rauscher Incorporated, Raymond James & Associates, Inc. and Fidelity Capital Markets, a division of National Financial Services LLC. ITEMS 3, 4 & 5 ARE NOT APPLICABLE AND HAVE BEEN OMITTED. ITEM 6 - EXHIBITS AND REPORTS ON FORM 8-K A. Exhibits 10.1 Fourth Amendment to Credit Agreement dated October 1, 2001, among ATP Oil & Gas Corporation and BNP Paribas, as Agent, and the Lenders Signatory thereto. 10.2 Fifth Amendment to Credit Agreement dated November 5, 2001, among ATP Oil & Gas Corporation and BNP Paribas, as Agent, and the Lenders Signatory thereto. B. Reports on Form 8-K - None. 21 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 14, 2001 By: /s/ Albert L. Reese, Jr. ---------------------------------- Albert L. Reese, Jr. Senior Vice President and Chief Financial Officer 22