UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 FORM 10-Q (Mark One) [X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 1997 OR [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE TRANSITION PERIOD FROM . . . . . . . . . TO . . . . . . . . . COMMISSION FILE NUMBER 1-3473 TESORO PETROLEUM CORPORATION (Exact Name of Registrant as Specified in Its Charter) DELAWARE 95-0862768 (State or Other Jurisdiction of (I.R.S. Employer Incorporation or Organization) Identification No.) 8700 TESORO DRIVE, SAN ANTONIO, TEXAS 78217-6218 (Address of Principal Executive Offices) (Zip Code) 210-828-8484 (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 ------- ------ ============================= There were 26,750,314 shares of the Registrant's Common Stock outstanding at October 31, 1997. TESORO PETROLEUM CORPORATION AND SUBSIDIARIES QUARTERLY REPORT ON FORM 10-Q FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 1997 TABLE OF CONTENTS Page PART I. FINANCIAL INFORMATION Item 1. Financial Statements (Unaudited) Condensed Consolidated Balance Sheets - September 30, 1997 and December 31, 1996. . . . . . . . . . . . . . . . . . . . . . . . . . 3 Condensed Statements of Consolidated Operations - Three Months and Nine Months Ended September 30, 1997 and 1996. . . . . . . . . . 4 Condensed Statements of Consolidated Cash Flows - Nine Months Ended September 30, 1997 and 1996. . . . . . . . . . . . . . . . . . . . . 5 Notes to Condensed Consolidated Financial Statements. . . . . . . . . 6 Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations . . . . . . . . . . . . . . . . . . . . . . 9 PART II. OTHER INFORMATION Item 1. Legal Proceedings. . . . . . . . . . . . . . . . . . . . . . . 21 Item 6. Exhibits and Reports on Form 8-K . . . . . . . . . . . . . . . 21 SIGNATURES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22 EXHIBIT INDEX. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23 2 PART I - FINANCIAL INFORMATION ITEM 1. FINANCIAL STATEMENTS TESORO PETROLEUM CORPORATION AND SUBSIDIARIES CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) (Dollars in thousands except per share amounts) September 30, December 31, 1997 1996<FN1> ---- ---- ASSETS CURRENT ASSETS Cash and cash equivalents . . . . . . . . . . . . . . . . . . . $ 7,379 22,796 Receivables, less allowance for doubtful accounts of $1,420 ($1,515 at December 31, 1996). . . . . . . . . . . . . . . . . 83,899 128,013 Inventories: Crude oil and wholesale refined products, at LIFO. . . . . . . 55,431 55,858 Merchandise and other refined products . . . . . . . . . . . . 14,333 13,539 Materials and supplies . . . . . . . . . . . . . . . . . . . . 5,138 5,091 Prepayments and other . . . . . . . . . . . . . . . . . . . . . 9,452 12,046 -------- -------- Total Current Assets. . . . . . . . . . . . . . . . . . . . . 175,632 237,343 -------- -------- PROPERTY, PLANT AND EQUIPMENT Refining and marketing. . . . . . . . . . . . . . . . . . . . . 358,792 328,522 Exploration and production (full-cost method of accounting) . . 257,003 198,480 Marine services . . . . . . . . . . . . . . . . . . . . . . . . 38,953 33,820 Corporate . . . . . . . . . . . . . . . . . . . . . . . . . . . 13,170 12,531 -------- -------- 667,918 573,353 Less accumulated depreciation, depletion and amortization. . . 291,113 256,842 -------- -------- Net Property, Plant and Equipment . . . . . . . . . . . . . . 376,805 316,511 -------- -------- OTHER ASSETS . . . . . . . . . . . . . . . . . . . . . . . . . . 35,377 28,733 -------- -------- TOTAL ASSETS . . . . . . . . . . . . . . . . . . . . . . . $ 587,814 582,587 ======== ======== LIABILITIES AND STOCKHOLDERS' EQUITY CURRENT LIABILITIES Accounts payable. . . . . . . . . . . . . . . . . . . . . . . . $ 57,473 80,747 Accrued liabilities . . . . . . . . . . . . . . . . . . . . . . 30,567 33,256 Current income taxes payable. . . . . . . . . . . . . . . . . . 1,951 13,822 Current maturities of long-term debt and other obligations. . . 9,778 10,043 -------- -------- Total Current Liabilities. . . . . . . . . . . . . . . . . . . 99,769 137,868 -------- -------- DEFERRED INCOME TAXES. . . . . . . . . . . . . . . . . . . . . . 24,552 19,151 -------- -------- OTHER LIABILITIES. . . . . . . . . . . . . . . . . . . . . . . . 45,786 42,243 -------- -------- LONG-TERM DEBT AND OTHER OBLIGATIONS, LESS CURRENT MATURITIES. . . . . . . . . . . . . . . . . . . . . . . 90,104 79,260 -------- -------- COMMITMENTS AND CONTINGENCIES (Note 4) STOCKHOLDERS' EQUITY Common Stock, par value $.16-2/3; authorized 50,000,000 shares; 26,498,745 shares issued (26,414,134 in 1996). . . . . . . . . 4,416 4,402 Additional paid-in capital. . . . . . . . . . . . . . . . . . . 190,093 189,368 Retained earnings . . . . . . . . . . . . . . . . . . . . . . . 134,043 110,295 Treasury stock, 66,998 shares at cost . . . . . . . . . . . . . (949) - -------- -------- Total Stockholders' Equity . . . . . . . . . . . . . . . . . . 327,603 304,065 -------- -------- TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY. . . . . . . . . . $ 587,814 582,587 ======== ======== <FN> The accompanying notes are an integral part of these condensed consolidated financial statements. <FN1> The balance sheet at December 31, 1996 has been taken from the audited consolidated financial statements at that date and condensed. 3 TESORO PETROLEUM CORPORATION AND SUBSIDIARIES CONDENSED STATEMENTS OF CONSOLIDATED OPERATIONS (Unaudited) (In thousands except per share amounts) Three Months Ended Nine Months Ended September 30, September 30, ------------------- ------------------- 1997 1996 1997 1996 ---- ---- ---- ---- REVENUES Refining and marketing. . . . . . . . . . . . . . . $ 198,815 203,661 534,986 563,767 Exploration and production. . . . . . . . . . . . . 19,821 26,476 61,769 83,933 Marine services . . . . . . . . . . . . . . . . . . 32,433 32,660 98,266 87,467 Other income. . . . . . . . . . . . . . . . . . . . 403 (725) 4,609 4,378 -------- -------- -------- -------- Total Revenues . . . . . . . . . . . . . . . . . . 251,472 262,072 699,630 739,545 -------- -------- -------- -------- OPERATING COSTS AND EXPENSES Refining and marketing. . . . . . . . . . . . . . . 188,014 194,156 508,926 545,303 Exploration and production. . . . . . . . . . . . . 3,054 2,416 8,836 8,767 Marine services . . . . . . . . . . . . . . . . . . 29,691 30,273 93,406 82,153 Depreciation, depletion and amortization. . . . . . 11,357 10,026 34,183 29,797 -------- -------- -------- -------- Total Operating Costs and Expenses . . . . . . . . 232,116 236,871 645,351 666,020 -------- -------- -------- -------- OPERATING PROFIT . . . . . . . . . . . . . . . . . . 19,356 25,201 54,279 73,525 General and Administrative . . . . . . . . . . . . . (3,416) (3,056) (9,599) (8,960) Interest Expense, Net of Capitalized Interest in 1997 (1,481) (4,142) (4,634) (12,142) Interest Income. . . . . . . . . . . . . . . . . . . 135 7,100 1,459 7,681 Other Expense, Net . . . . . . . . . . . . . . . . . (1,233) (1,254) (3,465) (8,802) -------- -------- -------- -------- EARNINGS BEFORE INCOME TAXES AND EXTRAORDINARY ITEM. . . . . . . . . . . . . . . . . 13,361 23,849 38,040 51,302 Income Tax Provision . . . . . . . . . . . . . . . . 5,382 7,686 14,292 17,159 -------- -------- -------- -------- EARNINGS BEFORE EXTRAORDINARY ITEM . . . . . . . . . 7,979 16,163 23,748 34,143 Extraordinary Loss on Extinguishment of Debt, Net of Income Tax Benefit of $886 in 1996. . . . . . . . . - (2,290) - (2,290) -------- -------- -------- -------- NET EARNINGS . . . . . . . . . . . . . . . . . . . . $ 7,979 13,873 23,748 31,853 ======== ======== ======== ======== EARNINGS PER SHARE Earnings Before Extraordinary Item. . . . . . . . . $ .30 .61 .88 1.30 Extraordinary Loss, Net of Income Tax Benefit . . . - (.09) - (.09) -------- -------- -------- -------- Net Earnings. . . . . . . . . . . . . . . . . . . . $ .30 .52 .88 1.21 ======== ======== ======== ======== WEIGHTED AVERAGE COMMON AND COMMON EQUIVALENT SHARES . . . . . . . . . . . . . . . . . 26,938 26,816 26,857 26,370 ======== ======== ======== ======== <FN> The accompanying notes are an integral part of these condensed consolidated financial statements. 4 TESORO PETROLEUM CORPORATION AND SUBSIDIARIES CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS (Unaudited) (In thousands) Nine Months Ended September 30 ----------------- 1997 1996 ---- ---- CASH FLOWS FROM (USED IN) OPERATING ACTIVITIES Net earnings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 23,748 31,853 Adjustments to reconcile net earnings to net cash from operating activities: Extraordinary loss on extinguishment of debt, net of income tax benefit . . - 2,290 Depreciation, depletion and amortization. . . . . . . . . . . . . . . . . . 34,643 30,386 Loss on sale of assets. . . . . . . . . . . . . . . . . . . . . . . . . . . 30 678 Amortization of deferred charges and other. . . . . . . . . . . . . . . . . 622 1,316 Changes in operating assets and liabilities: Receivable from Tennessee Gas Pipeline Company. . . . . . . . . . . . . . - 50,680 Receivables, other trade. . . . . . . . . . . . . . . . . . . . . . . . . 45,882 (6,228) Inventories . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 358 16,901 Other assets. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (3,219) 793 Accounts payable and other current liabilities. . . . . . . . . . . . . . (38,557) 8,066 Obligation payments to State of Alaska. . . . . . . . . . . . . . . . . . (3,406) (3,145) Deferred income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . 5,401 12,051 Other liabilities and obligations . . . . . . . . . . . . . . . . . . . . 5,569 2,760 -------- -------- Net cash from operating activities . . . . . . . . . . . . . . . . . . 71,071 148,401 -------- -------- CASH FLOWS FROM (USED IN) INVESTING ACTIVITIES Capital expenditures . . . . . . . . . . . . . . . . . . . . . . . . . . . . (95,082) (46,050) Acquisition of Coastwide Energy Services, Inc. . . . . . . . . . . . . . . . - (7,720) Other. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (3,155) (3,259) -------- -------- Net cash used in investing activities. . . . . . . . . . . . . . . . . (98,237) (57,029) -------- -------- CASH FLOWS FROM (USED IN) FINANCING ACTIVITIES Borrowings, net of repayments of $28,500 in 1997 and $112,000 in 1996, under revolving credit facilities. . . . . . . . . . . . . . . . . 15,828 - Payments of long-term debt . . . . . . . . . . . . . . . . . . . . . . . . . (3,287) (2,885) Purchase of treasury stock . . . . . . . . . . . . . . . . . . . . . . . . . (1,098) - Other. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 306 1,144 -------- -------- Net cash from (used in) financing activities . . . . . . . . . . . . . 11,749 (1,741) -------- -------- INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS . . . . . . . . . . . . . . . (15,417) 89,631 CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD . . . . . . . . . . . . . . . . 22,796 13,941 -------- -------- CASH AND CASH EQUIVALENTS, END OF PERIOD . . . . . . . . . . . . . . . . . . . $ 7,379 103,572 ======== ======== SUPPLEMENTAL CASH FLOW DISCLOSURES Interest paid, net of $313 capitalized in 1997 . . . . . . . . . . . . . . . $ 1,654 8,879 ======== ======== Income taxes paid. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 20,764 3,925 ======== ======== <FN> The accompanying notes are an integral part of these condensed consolidated financial statements. 5 TESORO PETROLEUM CORPORATION AND SUBSIDIARIES NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited) NOTE 1 - BASIS OF PRESENTATION The interim condensed consolidated financial statements and notes thereto of Tesoro Petroleum Corporation and its subsidiaries (collectively, the "Company" or "Tesoro") have been prepared by management without audit pursuant to the rules and regulations of the Securities and Exchange Commission ("SEC"). Accordingly, the accompanying financial statements reflect all adjustments that, in the opinion of management, are necessary for a fair presentation of results for the periods presented. Such adjustments are of a normal recurring nature. Certain information and notes normally included in financial statements prepared in accordance with generally accepted accounting principles have been condensed or omitted pursuant to the SEC's rules and regulations. However, management believes that the disclosures presented herein are adequate to make the information not misleading. The accompanying condensed consolidated financial statements and notes should be read in conjunction with the consolidated financial statements and notes thereto contained in the Company's Annual Report on Form 10-K for the year ended December 31, 1996. The preparation of these condensed consolidated financial statements required the use of management's best estimates and judgment that affect the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the periods. Actual results could differ from those estimates. The results of operations for any interim period are not necessarily indicative of results for the full year. Certain reclassifications have been made to amounts previously reported to conform to the current presentation of financial information. NOTE 2 - ACQUISITION In July 1997, the Company purchased the interests held by Zapata Exploration Company ("Zapata"), a wholly-owned subsidiary of Zapata Corporation, in two jointly held contract blocks (Block 18 and Block 20) in southern Bolivia. Zapata held a 25% interest in Block 18 and a 27.4% interest in Block 20. The purchase price was approximately $20 million, which included working capital and assumption of certain liabilities. The assignment of interests has been approved by the Bolivian government. The Company's net proved Bolivian reserves, which were estimated to be 253 billion cubic feet equivalent at 1996 year-end, increased more than 30% as a result of the acquisition. NOTE 3 - LONG-TERM DEBT In September 1997, the Company negotiated an amendment to its $150 million corporate revolving credit facility ("Credit Facility"). The amendment reduces the rate on cash borrowings under the Credit Facility to (i) the London Interbank Offered Rate ("LIBOR") plus 1.0% or (ii) the prime rate. Fees on outstanding letters of credit are reduced to 1.0%. The amendment also increases the Company's borrowing base and makes certain covenants in the Credit Facility less restrictive. Additionally, the Company is now permitted to utilize unsecured letters of credit outside of the Credit Facility up to $40 million (none outstanding at September 30, 1997). Under the Credit Facility, the Company had letters of credit of $33.9 million, primarily for royalty crude oil purchases from the State of Alaska, and cash borrowings of $11.9 million outstanding at September 30, 1997. In early October 1997, the Company completed an expansion of the hydrocracker unit at its Alaska refinery. The expansion, together with the addition of a new, high-yield jet fuel catalyst, has an estimated cost of approximately $19 million and is expected to improve the Company's refinery feedstock and product slate beginning in the fourth quarter of 1997. In October 1997, the National Bank of Alaska ("NBA") and the Alaska Industrial Development and Export Authority ("AIDEA"), under a loan agreement ("Hydrocracker Loan") entered into between the Company and NBA, provided a $16.2 million loan to the Company towards the cost of the hydrocracker expansion. One-half of the loan was funded by NBA and the other half was funded by AIDEA. The Hydrocracker Loan matures on or before April 1, 2005 and requires 28 equal quarterly principal payments beginning April 1998 together with interest at the unsecured 90-day commercial paper rate (5.55% at October 30, 1997) plus (i) 2.6% per annum on 50% of the amount borrowed and (ii) 2.35% per annum on the other 50% borrowed, each to be 6 adjusted quarterly. The Hydrocracker Loan is secured by a second lien on the refinery. Under the terms of the Hydrocracker Loan, the Company is required to maintain specified levels of working capital and tangible net worth. NOTE 4 - COMMITMENTS AND CONTINGENCIES The Company is subject to extensive federal, state and local environmental laws and regulations. These laws, which change frequently, regulate the discharge of materials into the environment and may require the Company to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites or install additional controls or other modifications or changes in use for certain emission sources. The Company is currently involved with a waste disposal site near Abbeville, Louisiana, at which it has been named a potentially responsible party under the Federal Superfund law. Although this law might impose joint and several liability upon each party at the site, the extent of the Company's allocated financial contributions to the cleanup of the site is expected to be limited based upon the number of companies, volumes of waste involved and an estimated total cost of approximately $500,000 among all of the parties to close the site. The Company is currently involved in settlement discussions with the Environmental Protection Agency and other potentially responsible parties at the Abbeville, Louisiana site. The Company expects, based on these discussions, that its liability will not exceed $25,000. The Company is also involved in remedial responses and has incurred cleanup expenditures associated with environmental matters at a number of sites, including certain of its own properties. At September 30, 1997, the Company's accruals for environmental expenses amounted to $8.7 million, which included a noncurrent liability of approximately $3.1 million for remediation of Kenai Pipe Line Company's ("KPL") properties that has been funded by the former owners of KPL through a restricted escrow deposit. Based on currently available information, including the participation of other parties or former owners in remediation actions, the Company believes these accruals are adequate. In addition, to comply with environmental laws and regulations, the Company currently anticipates that it will make capital improvements of approximately $3 million in 1997 and $8 million in 1998. The Company also expects to spend approximately $6 million by the year 2002 for secondary containment systems for existing storage tanks in Alaska. Conditions that require additional expenditures may exist for various Company sites, including, but not limited to, the Company's refinery, retail gasoline outlets (current and closed locations) and petroleum product terminals, and for compliance with the Clean Air Act. The amount of such future expenditures cannot currently be determined by the Company. NOTE 5 - STOCKHOLDERS' EQUITY STOCK REPURCHASE PROGRAM On May 7, 1997, the Company's Board of Directors authorized the repurchase of up to 3 million shares (approximately 11% of the current outstanding shares) of Tesoro Common Stock in a buyback program that will extend through the end of 1998. Under the program, subject to certain conditions, the Company may repurchase from time to time Tesoro Common Stock in the open market and through privately negotiated transactions. Purchases will depend on price, market conditions and other factors and will be made primarily from cash flows. The repurchased Common Stock is accounted for as treasury stock and may be used for employee benefit plan requirements and other corporate purposes. For further information on the repurchase program and related restrictions, see "Capital Resources and Liquidity" in Management's Discussion and Analysis of Financial Condition and Results of Operations in Item 2 herein. INCENTIVE COMPENSATION STRATEGY In June 1996, the Company's Board of Directors unanimously approved a special incentive compensation strategy in order to encourage a longer-term focus for all employees to perform at an outstanding level. The strategy provides eligible employees with incentives to achieve a significant increase in the market price of the Company's Common Stock. Under the strategy, awards would be earned only if the market price of the Company's Common 7 Stock reaches an average price per share of $20 or higher over any 20 consecutive trading days after June 30, 1997 and before December 31, 1998 (the "Performance Target"). In connection with this strategy, non-executive employees will be able to earn cash bonuses equal to 25% of their individual payroll amounts for the previous twelve complete months and certain executives have been granted, from the Company's Amended and Restated Executive Long-Term Incentive Plan ("Plan"), a total of 340,000 stock options at an exercise price of $11.375 per share, the fair market value (as defined in the Plan) of a share of the Company's Common Stock on the date of grant, and 350,000 shares of restricted Common Stock, all of which vest only upon achieving the Performance Target. NOTE 6 - ACCOUNTING PRONOUNCEMENTS In February 1997, the Financial Accounting Standards Board ("FASB") issued Statement of Financial Accounting Standards ("SFAS") No. 128, "Earnings Per Share." SFAS No. 128 becomes effective for the Company in the fourth quarter of 1997. At that time, the Company will be required to present "basic" and "diluted" earnings per share and to restate earnings per share data presented in prior periods. Early adoption is not permitted. The Company believes that the adoption of SFAS No. 128 will not materially impact its earnings per share disclosures. In June 1997, the FASB issued SFAS No.130, "Reporting Comprehensive Income," and SFAS No.131, "Disclosures about Segments of an Enterprise and Related Information." Both Statements become effective for periods beginning after December 15, 1997 with early adoption permitted. The Company is evaluating the effects these Statements will have on its financial reporting and disclosures. The Statements will have no effect on the Company's results of operations, financial position, capital resources or liquidity. 8 ITEM 2. TESORO PETROLEUM CORPORATION AND SUBSIDIARIES MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS RESULTS OF OPERATIONS - THREE AND NINE MONTHS ENDED SEPTEMBER 30, 1997 COMPARED TO THREE AND NINE MONTHS ENDED SEPTEMBER 30, 1996 SUMMARY Net earnings of $8.0 million, or $.30 per share, for the three months ended September 30, 1997 ("1997 Quarter") compare with net earnings of $13.9 million, or $.52 per share, for the three months ended September 30, 1996 ("1996 Quarter"). For the year-to-date period, net earnings of $23.8 million, or $.88 per share, for the nine months ended September 30, 1997 ("1997 Period") compare with net earnings of $31.9 million, or $1.21 per share, for the nine months ended September 30, 1996 ("1996 Period"). Results for the 1996 Quarter and Period included revenues from sales of natural gas at above-market prices under a contract with Tennessee Gas Pipeline Company ("Tennessee Gas") which was terminated effective October 1, 1996. Results of operations in 1997 and future years will no longer include above-market revenues from this contract. Significant items, including the impact of the Tennessee Gas contract, which affect the comparability between results for 1997 and 1996 are highlighted in the table below (in millions except per share amounts): Three Months Ended Nine Months Ended September 30, September 30, ------------------ ----------------- 1997 1996 1997 1996 ---- ---- ---- ---- Net Earnings As Reported . . . . . . . . . . . . . . . . . . . $ 8.0 13.9 23.8 31.9 Extraordinary Loss on Debt Extinguishment, Net of Income Tax Benefit. . . . . . . . . . . . . . . . . . - 2.3 - 2.3 ------ ------ ------ ------ Earnings Before Extraordinary Item . . . . . . . . . . . . . . 8.0 16.2 23.8 34.2 ------ ------ ------ ------ Significant Items Affecting Comparability, Pretax: Operating profit from excess of Tennessee Gas contract prices over spot market prices . . . . . . . . . . . . . . - 8.5 - 24.6 Interest and reimbursement of fees and costs from resolution of litigation. . . . . . . . . . . . . . . . . . - 7.9 - 7.9 Income from collection of Bolivian receivable. . . . . . . . - - 2.2 - Income from retroactive severance tax refunds. . . . . . . . - - 1.8 5.0 Costs of shareholder consent solicitation resolved in April 1996 . . . . . . . . . . . . . . . . . . . . . . . - - - (2.3) Employee terminations, restructuring costs and other . . . . - (.7) - (4.5) ------ ------ ------ ------ Total Significant Items, Pretax . . . . . . . . . . . . . . - 15.7 4.0 30.7 Income Tax Effect . . . . . . . . . . . . . . . . . . . . . - 4.4 1.2 8.3 ------ ------ ------ ------ Total Significant Items, Aftertax . . . . . . . . . . . . . - 11.3 2.8 22.4 ------ ------ ------ ------ Net Earnings Excluding Significant Items and Extraordinary Loss. . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 8.0 4.9 21.0 11.8 ====== ====== ====== ====== Earnings Per Share: As Reported. . . . . . . . . . . . . . . . . . . . . . . . . $ .30 .52 .88 1.21 Extraordinary Loss . . . . . . . . . . . . . . . . . . . . . - (.09) - (.09) Significant Items: Impact of Tennessee Gas contract prices over spot market prices . . . . . . . . . . . . . . . . . . . - .23 - .68 Other significant items. . . . . . . . . . . . . . . . . . - .20 .10 .17 ------ ------ ------ ------ Excluding Significant Items and Extraordinary Loss . . . . . $ .30 .18 .78 .45 ====== ====== ====== ====== As shown above, net earnings of $8.0 million ($.30 per share) in the 1997 Quarter would compare to $4.9 million ($.18 per share) when excluding the significant items in the 1996 Quarter. The resulting increase in net earnings in the 1997 Quarter was mainly attributable to improved profitability from each of the Company's business segments together with lower corporate interest expense. For the year-to-date periods, excluding significant items, net earnings would have been $21.0 million ($.78 per share) for the 1997 Period compared to $11.8 million ($.45 per share) for the 1996 Period. The increase in the 1997 Period was primarily due to higher spot market natural gas prices, better refined product margins and lower corporate interest expense. A discussion and analysis of the factors contributing to the Company's results of operations are presented below. The Company conducts its operations in the following business segments: Refining and Marketing, Exploration and Production, and Marine Services. 9 REFINING AND MARKETING Three Months Ended Nine Months Ended September 30, September 30, ------------------ ----------------- (Dollars in millions except per unit amounts) 1997 1996 1997 1996 ---- ---- ---- ---- Gross Operating Revenues: Refined products. . . . . . . . . . . . . . . . . . . . . $ 177.5 169.9 486.9 465.7 Other, primarily crude oil resales and merchandise. . . . 21.3 33.8 48.1 98.1 ------ ------ ------ ------ Gross Operating Revenues . . . . . . . . . . . . . . . . $ 198.8 203.7 535.0 563.8 ====== ====== ====== ====== Total Operating Profit: Gross margin. . . . . . . . . . . . . . . . . . . . . . . $ 34.2 31.7 94.8 85.5 Operating expenses. . . . . . . . . . . . . . . . . . . . 23.3 22.3 68.7 67.1 Depreciation and amortization . . . . . . . . . . . . . . 3.4 3.0 9.7 9.0 Loss on sale of assets and other. . . . . . . . . . . . . .1 .7 .1 .7 ------ ------ ------ ------ Operating Profit . . . . . . . . . . . . . . . . . . . . $ 7.4 5.7 16.3 8.7 ====== ====== ====== ====== Capital Expenditures . . . . . . . . . . . . . . . . . . . $ 11.8 3.1 30.6 6.9 ====== ====== ====== ====== Refinery Throughput: Barrels per day . . . . . . . . . . . . . . . . . . . . . 43,192 41,165 48,225 45,760 % Alaska North Slope crude oil. . . . . . . . . . . . . . 68% 69% 77% 71% Refined Products Manufactured (average daily barrels)<FN1>: Gasoline . . . . . . . . . . . . . . . . . . . . . . . . 11,351 10,953 12,499 12,717 Middle distillates. . . . . . . . . . . . . . . . . . . . 17,999 17,690 20,400 19,143 Heavy oils and residual product . . . . . . . . . . . . . 12,587 11,638 14,140 12,829 Other . . . . . . . . . . . . . . . . . . . . . . . . . . 1,910 2,214 2,500 2,709 ------ ------ ------ ------ Total Refined Products Manufactured. . . . . . . . . . . 43,847 42,495 49,539 47,398 ====== ====== ====== ====== Refinery Operations - Product Spread ($/barrel)<FN1>: Average yield value of products manufactured. . . . . . . $ 23.81 25.07 23.83 23.87 Cost of raw materials . . . . . . . . . . . . . . . . . . 17.92 19.33 18.69 19.03 ------ ------ ------ ------ Refinery Product Spread. . . . . . . . . . . . . . . . . $ 5.89 5.74 5.14 4.84 ====== ====== ====== ====== Non-Refinery Margin, included in operating profit above ($ millions)<FN1><FN2> . . . . . . . . . . . . . . $ 10.8 10.0 27.1 24.9 ====== ====== ====== ====== Total Segment Product Sales (average daily barrels)<FN3>: Gasoline. . . . . . . . . . . . . . . . . . . . . . . . . 18,592 18,073 18,156 18,751 Middle distillates. . . . . . . . . . . . . . . . . . . . 37,844 32,123 30,138 30,159 Heavy oils and residual product . . . . . . . . . . . . . 13,748 16,489 17,700 14,594 ------ ------ ------ ------ Total Product Sales. . . . . . . . . . . . . . . . . . . 70,184 66,685 65,994 63,504 ====== ====== ====== ====== Total Segment Product Sales Prices ($/barrel): Gasoline. . . . . . . . . . . . . . . . . . . . . . . . . $ 35.23 34.52 33.90 32.35 Middle distillates. . . . . . . . . . . . . . . . . . . . $ 27.00 29.33 28.46 28.08 Heavy oils and residual product . . . . . . . . . . . . . $ 18.40 17.03 17.53 16.86 Total Segment Gross Margins on Product Sales ($/barrel)<FN4>: Average sales price . . . . . . . . . . . . . . . . . . . $ 27.49 27.70 27.03 26.76 Average costs of sales. . . . . . . . . . . . . . . . . . 22.80 23.16 22.52 22.43 ------ ------ ------ ------ Gross Margin . . . . . . . . . . . . . . . . . . . . . . $ 4.69 4.54 4.51 4.33 ====== ====== ====== ====== <FN> <FN1> Amounts reported in prior periods have been reclassified to conform with current presentation. <FN2> Non-refinery margin includes margins on products purchased and resold, margins on products sold in markets outside of Alaska, intrasegment pipeline revenues, retail margins, and adjustments due to selling a volume and mix of products that is different than actual volumes manufactured. <FN3> Sources of total products sales include products manufactured at the refinery, products drawn from inventory balances and products purchased from third parties. The Company's purchases of refined products for resale averaged approximately 24,700 and 13,600 barrels per day for the three months ended September 30, 1997 and 1996, respectively, and approximately 15,500 and 12,100 barrels per day for the nine months ended September 30, 1997 and 1996, respectively. <FN4> Gross margins on total product sales include margins on sales of purchased products, together with the effect of changes in inventories. 10 REFINING AND MARKETING THREE MONTHS ENDED SEPTEMBER 30, 1997 COMPARED WITH THREE MONTHS ENDED SEPTEMBER 30, 1996. Operating profit of $7.4 million from the Company's Refining and Marketing segment during the 1997 Quarter represented a 30% improvement from the 1996 Quarter. The continued success of the Company's program to sell a larger portion of its refinery production within the core Alaska market, together with generally favorable industry conditions, contributed to this improvement. The Company's sales of gasoline and asphalt in Alaska increased in the 1997 Quarter as compared to the 1996 Quarter. Jet fuel sales also increased due to growing trans-Pacific air cargo traffic through the international airport in Anchorage. The Company's refinery product spread averaged $5.89 per barrel in the 1997 Quarter, a $.15 per barrel improvement from the 1996 Quarter. The Company's refined product yield values decreased by 5% to $23.81 per barrel in the 1997 Quarter from $25.07 per barrel in the 1996 Quarter, while the Company's feedstock costs decreased by 7% to $17.92 per barrel in the 1997 Quarter from $19.33 per barrel in the 1996 Quarter. The 1997 Quarter and 1996 Quarter both included scheduled turnarounds, during which the refinery was not fully operational. Margins from non-refinery activities increased to $10.8 million during the 1997 Quarter from $10.0 million in the 1996 Quarter due primarily to higher retail sales and improved margins on refined products sold outside Alaska. The increase of $7.6 million in revenues from refined products sales during the 1997 Quarter was primarily due to higher sales volumes, which rose 5% to 70,184 barrels per day in the 1997 Quarter from 66,685 barrels per day in the 1996 Quarter. Other revenues declined by $12.5 million due primarily to lower sales volumes of previously purchased crude oil together with lower prices. During the 1997 Quarter, the Company had less crude oil available for resale as refinery throughput averaged 2,027 barrels per day more than in the 1996 Quarter. Costs of sales decreased in the 1997 Quarter due to lower prices for crude oil and refined products. The $1.0 million increase in operating expenses included higher employee costs associated in part with expanded marketing efforts and higher professional fees. The 1996 Quarter included a $.7 million write-down of a West Coast terminal that was subsequently sold. NINE MONTHS ENDED SEPTEMBER 30, 1997 COMPARED WITH NINE MONTHS ENDED SEPTEMBER 30, 1996. Operating profit of $16.3 million in the 1997 Period compares to operating profit of $8.7 million in the 1996 Period. The Company's refinery spread of $5.14 per barrel in the 1997 Period improved 6% from the prior year period. The Company's production of jet fuel, a product in short supply in Alaska, was higher in the 1997 Period principally due to the use of an improved catalyst in the hydrocracker unit, a change made during the refinery turnaround in the 1996 Period. Margins from non-refinery activities increased to $27.1 million during the 1997 Period as compared to $24.9 million in the 1996 Period due primarily to higher retail sales and improved margins on refined products sold outside of Alaska. Revenues from sales of refined products in the Company's Refining and Marketing segment increased by 5% during the 1997 Period due to higher sales volumes and prices. Other revenues declined by $50.0 million during the 1997 Period due primarily to lower sales volumes of crude oil together with lower prices. During the 1997 Period, the Company had less crude oil available for resale as refinery throughput averaged 2,465 barrels per day more than in the 1996 Period and fewer spot purchases of crude oil were made. Costs of sales decreased in the 1997 Period due to lower volumes of crude oil. The $1.6 million increase in operating expenses included higher employee costs and professional fees. FUTURE IMPACT. The improvement in Refining and Marketing results have been due in part to the Company's marketing program to sell a larger portion of its refinery production within the core Alaska market. In addition, favorable summer and fall weather conditions in Alaska increased the demand for the Company's in-state sales during the 1997 Period. In early October 1997, the Company completed an expansion of its refinery hydrocracker unit, which increases the unit's capacity by approximately 25% to 12,500 barrels per day and enables the Company to produce more jet fuel. The expansion, together with the addition of a new, high-yield jet fuel catalyst, has an estimated cost of $19 million with a projected payback period of two years and is expected to favorably impact this segment's results beginning in the fourth quarter of 1997. The Company is also expanding its Alaskan retail operations with the construction of new outlets and remodeling of existing outlets. With respect to crude oil supply, beginning in October 1997, a subsidiary of the Company has contracts to purchase all of the approximately 34,000 barrels per day of Cook Inlet production for various periods of more than one year. In the 1997 Period, the Company processed approximately 9,300 barrels per day of Cook Inlet crude, or 19% of the refinery's throughput. The increase in Cook Inlet crude oil as a refinery feedstock will enable the Company to 11 produce higher-valued products. Although the aforementioned initiatives are expected to improve the fundamental earnings potential of this segment, future profitability of this segment will continue to be influenced by market conditions, particularly as these conditions influence costs of crude oil relative to prices received for sales of refined products, and other additional factors that are beyond the control of the Company. EXPLORATION AND PRODUCTION Three Months Ended Nine Months Ended September 30, September 30, ------------------ ----------------- (Dollars in millions except per unit amounts) 1997 1996 1997 1996 ---- ---- ---- ---- U.S.<FN1><FN2>: Gross Operating Revenues. . . . . . . . . . . . . . . . . $ 15.9 23.0 53.3 73.4 Other Income (primarily retroactive severance tax refunds). . . . . . . . . . . . . . . . . . . . . . . . - - 1.9 5.0 Production Costs . . . . . . . . . . . . . . . . . . . . 1.5 1.3 5.0 3.8 Administrative Support and Other Operating Expenses . . . .6 .2 1.7 2.2 Depreciation, Depletion and Amortization. . . . . . . . . 7.0 6.2 22.2 18.9 ----- ----- ----- ----- Operating Profit - U.S.. . . . . . . . . . . . . . . . . 6.8 15.3 26.3 53.5 ----- ----- ----- ----- BOLIVIA: Gross Operating Revenues. . . . . . . . . . . . . . . . . 3.8 3.4 8.4 10.5 Other Income (related to collection of a receivable). . . - - 2.2 - Production Costs. . . . . . . . . . . . . . . . . . . . . .3 .2 .7 .6 Administrative Support and Other Operating Expenses . . . .5 .6 1.3 2.1 Depreciation, Depletion and Amortization. . . . . . . . . .5 .4 1.0 1.0 ----- ----- ----- ----- Operating Profit - Bolivia . . . . . . . . . . . . . . . 2.5 2.2 7.6 6.8 ----- ----- ----- ----- TOTAL OPERATING PROFIT - EXPLORATION AND PRODUCTION. . . . $ 9.3 17.5 33.9 60.3 ===== ===== ===== ===== U.S.: Average Daily Net Production: Natural gas (Mcf). . . . . . . . . . . . . . . . . . . . 79,683 80,612 86,317 88,723 Oil (barrels). . . . . . . . . . . . . . . . . . . . . . 93 39 119 15 Average Prices: Natural gas ($/Mcf) - Spot market<FN3>. . . . . . . . . . . . . . . . . . . . $ 2.01 1.71 2.08 1.77 Average<FN2>. . . . . . . . . . . . . . . . . . . . . . $ 2.01 2.92 2.08 2.85 Oil ($/barrel) . . . . . . . . . . . . . . . . . . . . . $ 18.23 20.93 19.44 20.59 Average Operating Expenses ($/Mcfe) - Lease operating expenses . . . . . . . . . . . . . . . . $ .21 .14 .18 .12 Severance taxes. . . . . . . . . . . . . . . . . . . . . - .04 .03 .04 ----- ----- ----- ----- Total Production Costs. . . . . . . . . . . . . . . . . .21 .18 .21 .16 Administrative support . . . . . . . . . . . . . . . . . .09 .01 .07 .08 ----- ----- ----- ----- Total Operating Expenses. . . . . . . . . . . . . . . . $ .30 .19 .28 .24 ===== ===== ===== ===== Depletion ($/Mcfe). . . . . . . . . . . . . . . . . . . . $ .93 .82 .92 .77 ===== ===== ===== ===== Capital Expenditures. . . . . . . . . . . . . . . . . . . $ 16.3 11.7 32.5 27.1 ===== ===== ===== ===== BOLIVIA: Average Daily Net Production: Natural gas (Mcf). . . . . . . . . . . . . . . . . . . . 26,856 20,945 18,452 21,355 Condensate (barrels) . . . . . . . . . . . . . . . . . . 760 605 529 611 Average Prices: Natural gas ($/Mcf). . . . . . . . . . . . . . . . . . . $ 1.13 1.31 1.20 1.33 Condensate ($/barrel). . . . . . . . . . . . . . . . . . $ 15.00 16.92 16.23 16.50 Average Operating Expenses ($/Mcfe) - Production costs . . . . . . . . . . . . . . . . . . . . $ .10 .11 .11 .10 Value-added taxes. . . . . . . . . . . . . . . . . . . . - .08 - .07 Administrative support . . . . . . . . . . . . . . . . . .20 .24 .25 .24 ----- ----- ----- ----- Total Operating Expenses. . . . . . . . . . . . . . . . $ .30 .43 .36 .41 ===== ===== ===== ===== Depletion ($/Mcfe). . . . . . . . . . . . . . . . . . . . $ .19 .17 .18 .15 ===== ===== ===== ===== Capital Expenditures. . . . . . . . . . . . . . . . . . . $ 20.0 .8 26.0 5.7 ===== ===== ===== ===== <FN> <FN1> Represents the Company's U.S. oil and gas operations combined with gas transportation activities. <FN2> Results for 1996 included revenues from above-market pricing provisions of a contract with Tennessee Gas which was terminated effective October 1, 1996. Operating profit for the three and nine months ended September 30, 1996 included $8.5 million and $24.6 million, respectively, for the excess of these contract prices over spot market prices. Net natural 12 gas production sold under the contract averaged approximately 14 Mmcf per day for both the three months and nine months ended September 30, 1996. <FN3> Includes effects of the Company's natural gas commodity price agreements which amounted to a loss of $.19 per Mcf for the three months ended September 30, 1996, and losses of $.06 per Mcf and $.15 per Mcf for the nine months ended September 30, 1997 and 1996, respectively. <FN4> Mcf is defined as one thousand cubic feet; Mcfe is defined as net equivalent one thousand cubic feet. EXPLORATION AND PRODUCTION - U. S. THREE MONTHS ENDED SEPTEMBER 30, 1997 COMPARED WITH THREE MONTHS ENDED SEPTEMBER 30, 1996. Operating profit of $6.8 million from the Company's U.S. operations in the 1997 Quarter compares to operating profit of $15.3 million in the 1996 Quarter. The 1996 Quarter included revenues from the sale of natural gas at above-market prices under a contract with Tennessee Gas. The excess of these contract prices over spot market prices contributed approximately $8.5 million to operating profit in the 1996 Quarter. When excluding the incremental value of the Tennessee Gas contract from the 1996 Quarter, operating profit from the Company's U.S. operations for the 1997 Quarter would be relatively unchanged as total production volumes remained flat during both quarters and increases in spot market natural gas prices were offset by increased depreciation and depletion and operating expenses. Prices realized by the Company on spot market natural gas production increased to $2.01 per Mcf in the 1997 Quarter from $1.71 per Mcf in the 1996 Quarter. On a weighted-average basis, the Company's natural gas sales price was $2.92 per Mcf in the 1996 Quarter due to sales under the Tennessee Gas contract. The Company's production averaged 80.2 million cubic feet equivalents ("Mmcfe") per day in the 1997 Quarter compared to 80.8 Mmcfe per day in the 1996 Quarter. This decrease in the Company's production consisted of a 14.0 million cubic feet ("Mmcf") per day decline from the Bob West Field partially offset by a 13.4 Mmcfe per day production increase from other U.S. fields. The Company's production outside of the Bob West Field rose to 23% of total production during the 1997 Quarter, as compared to 6% in the 1996 Quarter. In September 1997, production began from the Company's interest in the Vinegarone East Field in Val Verde Basin of Southwest Texas at an initial flow rate of approximately 12 Mmcf per day gross (8.6 Mmcf per day net). Drilling is underway on two development wells in this field. In addition, the Cuellar 1 well, which was discovered during the 1997 Quarter in the Wilcox Trend of South Texas, began production in October 1997 at 8.0 Mmcf per day gross (6.0 Mmcf per day net). The Company's net U.S. production reached 90 Mmcf per day in late October 1997. Gross operating revenues from the Company's U.S. operations, after excluding amounts related to Tennessee Gas, increased due to the higher spot market prices. Production costs increased by $.2 million in the 1997 Quarter due primarily to higher per-unit lease operating expenses from the Company's newer fields. Depreciation and depletion increased by $.8 million, or 13%, due to a higher depletion rate. From time to time, the Company enters into commodity price agreements to reduce the risk caused by fluctuation in the prices of natural gas in the spot market. During the 1996 Quarter, the Company used such agreements to set the price of 38% of the natural gas production that it sold in the spot market and recognized a loss of $1.2 million ($.19 per Mcf) related to these price agreements. The Company did not have any such transactions during the 1997 Quarter. NINE MONTHS ENDED SEPTEMBER 30, 1997 COMPARED WITH NINE MONTHS ENDED SEPTEMBER 30, 1996. Operating profit of $26.3 million from the Company's U.S. operations in the 1997 Period compares to $53.5 million in the 1996 Period. Comparability between these periods was impacted by certain significant items. The 1996 Period included operating profit of $24.6 million from the excess of Tennessee Gas contract prices over spot market prices. Results of operations in 1997 and future years will no longer include above-market revenues from this contract which was terminated effective October 1, 1996. Operating profit also included retroactive severance tax refunds of $1.8 million and $5.0 million in the 1997 and 1996 Periods, respectively. Excluding the incremental value of the Tennessee Gas contract and retroactive severance tax refunds, operating profit from the Company's U.S. operations would have been $24.5 million in the 1997 Period compared to $23.9 million in the 1996 Period. The resulting increase of $.6 million was primarily attributable to higher spot market prices for sales of natural gas partially offset by higher depreciation and depletion. Prices realized by the Company on its spot natural gas production increased 18% to $2.08 per Mcf in the 1997 Period from $1.77 per Mcf in the 1996 Period. The increase in average spot market prices was attributable in part to unusually high prices received during January and February when there was unusually cold weather combined with below-normal natural gas storage levels. On a weighted-average basis, the Company's natural 13 gas sales price was $2.85 per Mcf in the 1996 Period due to sales under the Tennessee Gas contract. The Company's production averaged 87.0 Mmcfe per day in the 1997 Period, a decrease of 1.8 Mmcfe per day from the 1996 Period. This decrease in the Company's production consisted of a 13.9 Mmcf per day decline from the Bob West Field partially offset by a 12.1 Mmcfe per day increase from other U.S. fields. Production from the Bob West Field, which accounted for 95% of the Company's total U.S. production in the 1996 Period, was reduced to 81% in the 1997 Period. Gross operating revenues from the Company's U.S. operations, after excluding amounts related to Tennessee Gas, increased due to the higher spot market prices. Production costs increased by $1.2 million during the 1997 Period due to higher per-unit lease operating expenses from the Company's newer fields. Administrative support and other operating expenses decreased by $.5 million. Depreciation and depletion increased by $3.3 million, or 17%, due to a higher depletion rate. From time to time, the Company enters into commodity price agreements to reduce the risk caused by fluctuations in the prices of natural gas in the spot market. In addition, from time to time the Company has entered into price agreements with collars, under which no payments will be made by either party unless the price falls below a designated floor price or above a designated ceiling price, at which time the Company receives or pays the difference, respectively. During the 1997 and 1996 Periods, the Company used such agreements to set the price of 11% and 37%, respectively, of the natural gas production that it sold in the spot market. During the 1997 and 1996 Periods, the Company realized losses of $1.6 million ($.06 per Mcf) and $2.9 million ($.15 per Mcf), respectively, from these price agreements. At September 30, 1997, the Company has no remaining price agreements outstanding for the year. EXPLORATION AND PRODUCTION - BOLIVIA HYDROCARBONS LAW. In 1996, a new Hydrocarbons Law was passed by the Bolivian government that significantly impacts the Company's operations in Bolivia. The new law, among other matters, granted the Company the option to convert its Contracts of Operation to new Shared Risk Contracts. On November 6, 1997, the Company completed the conversion of its Contracts of Operation for Block 18 and Block 20 into four Shared Risk Contracts. The new contracts have an effective date of July 29, 1996 and extend the Company's term of operation, provide more favorable acreage relinquishment terms and provide for a more favorable fiscal regime of royalties and taxes. The new contract for Block 18 is extended to the year 2017. The new contracts for Block 20 are extended to the year 2029 for Block 20-West and Block 20-East, which are in the exploration phase, and to the year 2018 for Block 20-Los Suris that is in the development phase. FARMOUT. A farmout agreement executed June 19, 1997, between the Company and Total Exploration Production Bolivie, S.A. ("Total"), an affiliate of Total S.A., became effective on a portion of Block 20-West on November 6, 1997. Pursuant to the farmout agreement, Total established a financial guarantee to the Bolivian government to guarantee the performance of exploration work on Block 20-West. Under the farmout agreement, Total has the right to drill, at its sole cost, two exploratory wells to earn a 75 percent interest in the farmout area which consists of 315,000 acres of Block 20-West. The assignment of interest by the Company to Total, which is subject to reversion if Total does not earn the interest, has been approved by the Bolivian government and is expected to become effective in the fourth quarter of 1997. It is anticipated that Total will spud the first well by mid-1998. YPFB AND YPF CONTRACT. The Company's Bolivian natural gas production has been sold to Yacimientos Petroliferos Fiscales Bolivianos ("YPFB"), which in turn sells the natural gas to Yacimientos Petroliferos Fiscales, SA ("YPF"), a publicly-held company based in Argentina. Currently, the Company's sales of natural gas production is based on the volume and pricing terms in the contract between YPFB and YPF. The contract to sell gas to YPF expired March 31, 1997 and a contract extension was signed effective April 1, 1997 extending the contract term two years to March 31, 1999 with an option to extend the contract a maximum of one additional year if the pipeline being constructed from Bolivia to Brazil is not complete. In the contract extension, YPF negotiated an 11% reduction in the minimum contract volume it is required to import from Bolivia, which in turn resulted in a corresponding 11% reduction of Tesoro's minimum contract volume. ACCESS TO NEW MARKETS. A lack of market access has constrained natural gas production in Bolivia. Preliminary work on a new 1,900-mile pipeline that will link Bolivia's gas reserves with markets in Brazil has begun and the pipeline is expected to be operational in early 1999. THREE MONTHS ENDED SEPTEMBER 30, 1997 COMPARED WITH THREE MONTHS ENDED SEPTEMBER 30, 1996. Operating profit of $2.5 million from the Company's Bolivian operations in the 1997 Quarter compares to 14 operating profit of $2.2 million in the 1996 Quarter. With the Company's purchase of Zapata's interests in Block 18 and Block 20 in July 1997, the Company now holds a 100% interest in both blocks, subject to the farmout agreement with Total (see Note 2 of Notes to Condensed Consolidated Financial Statements). Beginning in the 1997 Quarter, the Company's net share of production from Block 18 increased by approximately 33% as a result of this purchase. Block 20 is currently shut-in waiting on the construction of the pipeline to Brazil, which is expected to be operational in early 1999. Natural gas prices for Bolivian production fell to $1.13 per Mcf in the 1997 Quarter, a 14% drop from the 1996 Quarter. NINE MONTHS ENDED SEPTEMBER 30, 1997 COMPARED WITH NINE MONTHS ENDED SEPTEMBER 30, 1996. Operating profit of $7.6 million from the Company's Bolivian operations in the 1997 Period compares to operating profit of $6.8 million in the 1996 Period. The 1997 Period included income of $2.2 million related to the collection of a receivable for prior years production. Excluding this income, operating profit would have decreased by $1.4 million as production of natural gas and condensate fell by 14%. As discussed above, the Company's production rose during the 1997 Quarter due to the purchase of the Zapata interests in July 1997 which will also benefit future periods. However, earlier in the year, the Company's Bolivian natural gas production was lower due to a reduction in minimum takes under the new contract between YPFB and YPF and also due to constraints arising from repairs to a non-Company-owned pipeline that transports gas from Bolivia to Argentina. A replacement pipeline is now operational, which has restored full capacity. During the 1996 Period, production was higher due to requests from YPFB for additional production from the Company to meet export specifications. Natural gas prices declined to $1.20 per Mcf in the 1997 Period compared to $1.33 per Mcf in the 1996 Period. Administrative support and other operating expenses decreased by $.8 million in the 1997 Period due primarily to the reduced production levels. MARINE SERVICES Three Months Ended Nine Months Ended September 30, September 30, ------------------ ----------------- (Dollars in millions) 1997 1996 1997 1996 ---- ---- ---- ---- Gross Operating Revenues: Fuels . . . . . . . . . . . . . . . $ 25.2 26.0 77.6 70.4 Lubricants and other. . . . . . . . 4.2 4.1 12.3 10.9 Services. . . . . . . . . . . . . . 3.1 2.6 8.4 6.2 ---- ---- ---- ---- Gross Operating Revenues . . . . . 32.5 32.7 98.3 87.5 Costs of Sales . . . . . . . . . . . 22.9 24.5 72.6 66.7 ---- ---- ---- ---- Gross Profit . . . . . . . . . . . 9.6 8.2 25.7 20.8 Operating Expenses and Other . . . . 6.5 5.8 20.4 15.4 Depreciation and Amortization. . . . .4 .4 1.2 .9 ---- ---- ---- ---- Operating Profit . . . . . . . . . $ 2.7 2.0 4.1 4.5 ==== ==== ==== ==== Sales Volumes (millions of gallons): Fuels, primarily diesel . . . . . . 39.1 37.8 116.2 107.4 Lubricants. . . . . . . . . . . . . .7 .7 2.0 1.9 Capital Expenditures . . . . . . . . $ 2.0 1.2 5.3 6.2 For the 1997 Quarter, gross operating revenues declined by $.2 million due primarily to lower fuel sales prices partly offset by increased fuel volumes. The $1.6 million decrease in cost of sales correlates to these lower fuel market prices. The 19% increase in service revenues was associated with the increased rig activity in the Gulf of Mexico and the Company's focus to serve these customers. The improvement of $1.4 million in gross profit was partly offset by higher operating expenses associated with the increased sales volumes and service revenues. For the 1997 Period, gross operating revenues increased by $10.8 million, with an 11% increase in fuels and lubricants revenues and a 35% increase in service revenues. These increases were mainly due to added locations and associated volumes stemming from an acquisition consummated in February 1996 together with internal growth initiatives. Costs of sales during the 1997 Period increased due to the higher volumes and also included a $.7 million charge associated with inventory valuations as market prices declined from year-end levels. The improvement of $4.9 million in gross profit during the 1997 Period was offset by higher operating and other expenses associated with the increased activity and upgrades to facilities and services. The Marine Services segment's business is largely dependent upon the volume of oil and gas drilling, workover, construction and seismic activity in the Gulf of Mexico. 15 GENERAL AND ADMINISTRATIVE General and administrative expense increased by $.3 million and $.6 million during the 1997 Quarter and Period, respectively. These increases were primarily due to higher employee costs partially offset by reduced professional fees and insurance costs. INTEREST EXPENSE AND INTEREST INCOME Interest expense decreased by $2.6 million and $7.5 million during the 1997 Quarter and Period, respectively. These decreases were primarily due to the Company's redemption of $74.1 million of public debt in November 1996 which has resulted in interest expense savings of approximately 60% in the 1997 Quarter and Period. Interest income decreased by $6.9 million and $6.2 million during the 1997 Quarter and Period, respectively. The 1996 Quarter and Period included interest of approximately $7 million received from Tennessee Gas in conjunction with the collection of a receivable which resulted from underpayment for natural gas sold in prior periods. The 1997 Period included interest income of approximately $.4 million related to the collection of a Bolivia receivable. OTHER EXPENSE, NET For the 1997 Period, other expense decreased by $5.3 million primarily due to charges incurred in the prior year period for shareholder consent solicitation costs of $2.3 million, which was resolved in April 1996, together with a write-off of deferred financing costs and employee termination costs with no material comparable costs recorded in the current period. INCOME TAX PROVISION Income taxes decreased by $2.2 million and $2.8 million during the 1997 Quarter and Period, respectively. These decreases were primarily due to lower earnings. IMPACT OF CHANGING PRICES The Company's operating results and cash flows are sensitive to the volatile changes in energy prices. Major shifts in the cost of crude oil used for refinery feedstocks and the price of refined products can result in a change in margin from the Refining and Marketing operations, as prices received for refined products may or may not keep pace with changes in crude oil costs. These energy prices, together with volume levels, also determine the carrying value of crude oil and refined product inventory. The Company uses the last-in, first-out ("LIFO") method of accounting for inventories of crude oil and U.S. wholesale refined products. This method results in inventory carrying amounts that are less likely to represent current values and in costs of sales which more closely represent current costs. Likewise, changes in natural gas, condensate and oil prices impact revenues and the present value of estimated future net revenues and cash flows from the Company's Exploration and Production operations. The Company may increase or decrease its production in response to market conditions. The carrying value of oil and natural gas assets may be subject to noncash writedowns based on changes in natural gas prices and other determining factors. Changes in natural gas prices also influence the level of drilling activity in the Gulf of Mexico. The Company's Marine Services operation, whose customers include offshore drilling contractors and related industries, could be impacted by significant fluctuations in natural gas prices. The Company's Marine Services segment uses the first-in, first-out ("FIFO") method of accounting for its inventories of fuel. Changes in fuel prices can significantly impact inventory valuations and costs of sales in this segment. 16 CAPITAL RESOURCES AND LIQUIDITY OVERVIEW The Company's primary sources of liquidity are its cash and cash equivalents, internal cash generation and external financing. During the first nine months of 1997, the Company made capital expenditures exceeding $95 million, which were funded through a combination of cash flows from operations of $71 million, external financing of $16 million and available cash balances. Subsequently, in October 1997, the Company obtained a $16.2 million term loan to finance the expansion of the refinery hydrocracker unit (see Note 3 of Notes to Condensed Consolidated Financial Statements). At September 30, 1997, the Company's debt-to-capitalization ratio was 22% which enhances the Company's ability to access capital markets. The Company is focused on its strategic plans to make operational improvements and continues to assess its asset base in order to maximize returns and develop full value through strategic diversification and acquisitions in all of its operating segments. This ongoing assessment includes, in the Exploration and Production segment, evaluating ways in which the Company could diversify its oil and gas reserve base and offset the impact of declining production through domestic development, exploration and acquisition outside of the Bob West Field. In the Refining and Marketing segment, the Company has been engaged in studies to improve profitability and has also evaluated possible joint ventures, strategic alliances or business combinations; such evaluations have not resulted in any significant transaction but operating strategies have been implemented to optimize the product and feedstock slates, improve efficiencies and reliability, and expand marketing to increase placement of products in Alaska. In the Marine Services segment, the Company continues to pursue opportunities for expansion as well as optimizing existing operations. The Company operates in an environment where its liquidity and capital resources are impacted by changes in the supply of and demand for crude oil, natural gas and refined petroleum products, market uncertainty and a variety of additional risks that are beyond the control of the Company. These risks include, among others, the level of consumer product demand, weather conditions, the proximity of the Company's natural gas reserves to pipelines, the capacities of such pipelines, fluctuations in seasonal demand, governmental regulations, the price and availability of alternative fuels and overall market and economic conditions. The Company's future capital expenditures as well as borrowings under its credit arrangements and other sources of capital will be affected by these conditions. STOCK REPURCHASE PROGRAM On May 7, 1997, the Company's Board of Directors authorized the repurchase of up to 3 million shares (approximately 11% of the current outstanding shares) of Tesoro Common Stock in a buyback program that will extend through the end of 1998. Under the program, subject to certain conditions, the Company may repurchase from time to time Tesoro Common Stock in the open market and through privately negotiated transactions. Purchases will depend on price, market conditions and other factors and will be made primarily from cash flows. The repurchased Common Stock is accounted for as treasury stock and may be used for employee benefit plan requirements and other corporate purposes. Repurchases of Common Stock are subject to the restricted payments provision of the Credit Facility as described below. CREDIT ARRANGEMENTS The Company has financing and credit arrangements with a consortium of nine banks under a corporate revolving credit agreement ("Credit Facility") which provides total commitments of $150 million. The Credit Facility, which extends through April 2000, provides for cash borrowings up to $100 million and issuance of letters of credit, subject to a borrowing base (which was approximately $147 million at September 30, 1997). The Company, at its option, has currently activated total commitments of $100 million. Outstanding obligations under the Credit Facility are secured by liens on substantially all of the Company's trade accounts receivable and product inventory and by mortgages on the Company's refinery and South Texas natural gas reserves. Under the terms of the Credit Facility, the Company is required to maintain specified levels of consolidated working capital, tangible net worth, cash flow and interest coverage. Among other matters, the Credit Facility contains covenants which limit the incurrence of additional indebtedness and restricted payments. An amendment to the Credit Facility, which was negotiated in September 1997, reduces interest rates and certain fees, increases the Company's borrowing base and makes certain covenants less restrictive. Additionally, the Company is now 17 permitted to utilize unsecured letters of credit outside of the Credit Facility up to $40 million (none outstanding at September 30, 1997). Under the Credit Facility, the Company had letters of credit of $33.9 million, primarily for royalty crude oil purchases from the State of Alaska, and cash borrowings of $11.9 million outstanding at September 30, 1997. The terms of the Credit Facility allow for open market stock repurchases and the payment of cash dividends subject to a cumulative amount available for restricted payments (defined as the difference of (i) the sum since December 31, 1995, of (a) $5 million and (b) 50% of consolidated net earnings of the Company in any calendar year and (ii) any restricted payments made since June 1996). At September 30, 1997, the cumulative amount available for restricted payments was approximately $54 million. Annually, however, the aggregate of open market stock repurchases and cash dividends cannot exceed a maximum of $5 million. In addition, the Credit Facility permits the Company to repurchase a limited amount of Common Stock up to $10 million annually, specifically for oddlot buyback programs and employee benefit or compensation plans. While the Board of Directors has no present plans to pay dividends, from time to time the Board of Directors reevaluates the feasibility of declaring future dividends. In addition to the Credit Facility, a subsidiary of the Company has a three-year line of credit with a bank which provides up to $10 million for the purchase of real estate and equipment for the Company's Marine Services segment at the bank's prime rate. The loan facility is not guaranteed by the Company and is secured only by such real estate and equipment that are financed. Beginning in March 1998, credit availability is reduced quarterly by 6.667%. At September 30, 1997, $ 4.8 million was outstanding under the loan facility. In early October 1997, the Company completed an expansion of the hydrocracker unit at its Alaska refinery. The expansion, together with the addition of a new, high-yield jet fuel catalyst, has an estimated cost of approximately $19 million and is expected to improve the Company's refinery feedstock and product slate beginning in the fourth quarter of 1997. In October 1997, the National Bank of Alaska ("NBA") and the Alaska Industrial Development and Export Authority ("AIDEA"), under a loan agreement ("Hydrocracker Loan") entered into between the Company and NBA, provided a $16.2 million loan to the Company towards the cost of the hydrocracker expansion. The Hydrocracker Loan matures on or before April 1, 2005 and is secured by a second lien on the refinery. Under the terms of the Hydrocracker Loan, the Company is required to maintain specified levels of working capital and tangible net worth. See Note 3 of Notes to Condensed Consolidated Financial Statements. CAPITAL SPENDING During the first nine months of 1997, the Company's capital expenditures totaled $95 million which were financed with available cash reserves, internally-generated cash flows from operations and external financing. In addition, the Company has obtained outside financing, as discussed above, for expansion of the refinery hydrocracker unit. Although capital expenditures for the remainder of the year had been projected to reach $65 million, actual capital spending will be less due to a number of factors, including the extent to which properties are acquired and the timing of capital projects. Capital expenditures for the remainder of the year are expected to be funded by cash flows from operations and external borrowings under the Company's credit arrangements. The Exploration and Production segment accounts for $101 million of the projected capital expenditures, with $71 million planned for U.S. activities and $30 million in Bolivia. Planned U.S. expenditures include $22 million for property acquisitions; $17 million for development drilling (participation in 16 wells), field facilities and workovers; $13 million for leasehold, geological and geophysical; and $19 million for exploratory drilling (participation in 14 wells). For the first nine months of 1997, actual U.S. expenditures were $32 million, principally for participation in the drilling of five development wells (all completed) and nine exploratory wells (seven completed). In Bolivia, projected capital expenditures of $30 million for the year included an increase for the purchase of additional contract interests in July 1997 (see Note 2 of Notes to Condensed Consolidated Financial Statements). The projection in Bolivia includes $3 million for one exploratory well and $2 million for workovers and field facilities, with the remainder planned for three-dimensional seismic. Capital spending for the first nine months of 1997 totaled $26 million in Bolivia, primarily for the purchase of additional contract interests, exploratory drilling, seismic activity and workovers. Although the Company continues to pursue exploratory, development and acquisition opportunities, as discussed above, actual capital expenditures for the remainder of the year may vary from projections. 18 Capital spending for the Refining and Marketing segment is projected to be $50 million for the year, including costs for the refinery hydrocracker expansion and a multi-year capital program to improve marketing operations. During the first nine months of 1997, the Refining and Marketing segment had spent approximately $31 million towards capital projects. In the Marine Services segment, capital spending for 1997 is currently projected at $8 million, a $21 million reduction from the original budget. This projection, of which $5 million was spent during the first nine months of 1997, is now primarily directed towards expansion and improvement of operations along the Gulf of Mexico rather than acquisitions. CASH FLOWS Components of the Company's cash flows are set forth below (in millions): Nine Months Ended September 30, ----------------- 1997 1996 ---- ---- Cash Flows From (Used In): Operating Activities . . . . . . . . . . . . . . $ 71.1 148.4 Investing Activities . . . . . . . . . . . . . . (98.2) (57.0) Financing Activities . . . . . . . . . . . . . . 11.7 (1.8) ------ ------ Increase (Decrease) in Cash and Cash Equivalents . $ (15.4) 89.6 ====== ====== Operating cash flows of $71 million during the 1997 Period included a $46 million decrease in receivables due in part to collections related to high product and crude oil sales volumes at 1996 year-end and to a Bolivian receivable representing production sold in prior years, partially offset by income tax and other payments. The 1996 Period operating cash flows of $148 million included a $67.5 million receipt from Tennessee Gas and reduced working capital requirements. Net cash used in investing activities of $98 million during the 1997 Period included capital expenditures of $58 million for the Company's Exploration and Production activities, $31 million for Refining and Marketing operations and $5 million for Marine Services. Net cash from financing activities during the 1997 Period included borrowings of $16 million under revolving credit facilities partially offset by payments of other long-term debt and purchases of treasury stock. At September 30, 1997, the Company's net working capital totaled $76 million, which included cash and cash equivalents of $7 million. ENVIRONMENTAL The Company is subject to extensive federal, state and local environmental laws and regulations. These laws, which change frequently, regulate the discharge of materials into the environment and may require the Company to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites or install additional controls or other modifications or changes in use for certain emission sources. The Company is currently involved in remedial responses and has incurred cleanup expenditures associated with environmental matters at a number of sites, including certain of its own properties. At September 30, 1997, the Company's accruals for environmental expenses amounted to $8.7 million, which included a noncurrent liability of $3.1 million for remediation of KPL's properties that has been funded by the former owners of KPL through a restricted escrow deposit. Based on currently available information, including the participation of other parties or former owners in remediation actions, the Company believes these accruals are adequate. In addition, to comply with environmental laws and regulations, the Company anticipates that it will make capital improvements of approximately $3 million in 1997 and $8 million in 1998. The Company also expects to spend approximately $6 million by the year 2002 for secondary containment systems for existing storage tanks in Alaska. Conditions that require additional expenditures may exist for various Company sites, including, but not limited to, the Company's refinery, retail gasoline outlets (current and closed locations) and petroleum product terminals, and for compliance with the Clean Air Act. The amount of such future expenditures cannot currently be determined by the Company. For further information on environmental contingencies, see Note 4 of Notes to Condensed Consolidated Financial Statements. 19 FORWARD-LOOKING STATEMENTS Statements in this Quarterly Report on Form 10-Q, including those contained in the foregoing discussion and other items herein, concerning the Company which are (a) projections of revenues, earnings, earnings per share, capital expenditures or other financial items, (b) statements of plans and objectives for future operations, (c) statements of future economic performance, or (d) statements of assumptions or estimates underlying or supporting the foregoing are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. The ultimate accuracy of forward-looking statements is subject to a wide range of business risks and changes in circumstances, and actual results and outcomes often differ from expectations. Any number of important factors could cause actual results to differ materially from those in the forward-looking statements herein, including the following: the timing and extent of changes in commodity prices and underlying demand and availability of crude oil and other refinery feedstocks, refined products, and natural gas; actions of our customers and competitors; changes in the cost or availability of third-party vessels, pipelines and other means of transporting feedstocks and products; state and federal environmental, economic, safety and other policies and regulations, any changes therein, and any legal or regulatory delays or other factors beyond the Company's control; execution of planned capital projects; weather conditions affecting the Company's operations or the areas in which the Company's products are marketed; future well performance; the extent of Tesoro's success in acquiring oil and gas properties and in discovering, developing and producing reserves; political developments in foreign countries; the conditions of the capital markets and equity markets during the periods covered by the forward-looking statements; earthquakes or other natural disasters affecting operations; adverse rulings, judgments, or settlements in litigation or other legal matters, including unexpected environmental remediation costs in excess of any reserves; and adverse changes in the credit ratings assigned to the Company's trade credit. For more information with respect to the foregoing, see the Company's Annual Report on Form 10-K. The Company undertakes no obligation to publicly release the result of any revisions to any such forward-looking statements that may be made to reflect events or circumstances after the date hereof or to reflect the occurrence of unanticipated events. 20 PART II - OTHER INFORMATION ITEM 1. LEGAL PROCEEDINGS As previously reported, on June 21, 1997, the Company received a letter from the Office of the Attorney General of the State of Alaska ("State") alleging that Kenai Pipe Line Company ("KPL"), a wholly-owned subsidiary of the Company, failed to follow the terms of its Oil Discharge Prevention and Contingency Plan ("Contingency Plan"), which allegation arose out of the State's investigation of a December 5, 1995 spill into the Cook Inlet from KPL's facility. The Company has settled all claims with the State by agreeing to (i) pay $70,000 to the State as a civil penalty and to reimburse the State for its costs; (ii) contribute $10,000 to the Cook Inlet Regional Citizens Advisory Council to conduct additional operational oversight of KPL's Contingency Plan; and (iii) complete a pollution prevention project at KPL's facility with an estimated cost of $50,000 by December 31, 1998. ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K (a) Exhibits See the Exhibit Index immediately preceding the exhibits filed herewith. (b) Reports on Form 8-K No reports on Form 8-K have been filed during the quarter for which this report is filed. 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 thereunto duly authorized. TESORO PETROLEUM CORPORATION REGISTRANT Date: November 14, 1997 /s/ BRUCE A. SMITH Bruce A. Smith Chairman of the Board of Directors, President and Chief Executive Officer Date: November 14, 1997 /s/ DON E. BEERE Don E. Beere Vice President, Controller (Chief Accounting Officer) 22 EXHIBIT INDEX EXHIBIT NUMBER 4.1 First Amendment to Amended and Restated Credit Agreement ("Credit Facility") among the Company and Banque Paribas, individually, as an Issuing Bank and as Administrative Agent ("Banque Paribas"), The Bank of Nova Scotia, individually and as Documentation Agent ("Bank of Nova Scotia"), and other financial institution parties thereto, effective as of March 21, 1997. 4.2 Second Amendment to Credit Facility among the Company, Banque Paribas, Bank of Nova Scotia and other financial institution parties thereto, effective as of March 31, 1997. 4.3 Third Amendment to Credit Facility among the Company, Banque Paribas, Bank of Nova Scotia and other financial institution parties thereto, effective as of September 15, 1997. 27 Financial Data Schedule. 23