-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, SiXc5Zx97VwwQA1faXkeKllKxtto6SAK8Q0jvgb+DIYNaT17/vo8ZAqiEPsBF4fm 7w4+6TgY4cdBHrCA8YAxQA== 0000050104-96-000028.txt : 19961118 0000050104-96-000028.hdr.sgml : 19961118 ACCESSION NUMBER: 0000050104-96-000028 CONFORMED SUBMISSION TYPE: 10-Q PUBLIC DOCUMENT COUNT: 2 CONFORMED PERIOD OF REPORT: 19960930 FILED AS OF DATE: 19961114 SROS: NYSE SROS: PSE FILER: COMPANY DATA: COMPANY CONFORMED NAME: TESORO PETROLEUM CORP /NEW/ CENTRAL INDEX KEY: 0000050104 STANDARD INDUSTRIAL CLASSIFICATION: PETROLEUM REFINING [2911] IRS NUMBER: 950862768 STATE OF INCORPORATION: DE FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-Q SEC ACT: 1934 Act SEC FILE NUMBER: 001-03473 FILM NUMBER: 96664060 BUSINESS ADDRESS: STREET 1: 8700 TESORO DR CITY: SAN ANTONIO STATE: TX ZIP: 78217 BUSINESS PHONE: 2108288484 10-Q 1 10Q FOR QUARTER ENDED 9/30/96 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, 1996 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 26,409,961 shares of the Registrant's Common Stock outstanding at October 31, 1996. TESORO PETROLEUM CORPORATION AND SUBSIDIARIES INDEX TO FORM 10-Q FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 1996 PART I. FINANCIAL INFORMATION Page Item 1. Financial Statements (Unaudited) Condensed Consolidated Balance Sheets - September 30, 1996 and December 31, 1995 . . . . . . . . . . . . . . 3 Condensed Statements of Consolidated Operations - Three Months and Nine Months Ended September 30, 1996 and 1995 . . . 4 Condensed Statements of Consolidated Cash Flows - Nine Months Ended September 30, 1996 and 1995 . . . . . . . . . . . . 5 Notes to Condensed Consolidated Financial Statements . . . . . . . . . 6 Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations . . . . . . . . . . . . . 10 PART II. OTHER INFORMATION Item 1. Legal Proceedings . . . . . . . . . . . . . . . . . . . . . . . 21 Item 2. Changes in Securities . . . . . . . . . . . . . . . . . . . . . 21 Item 6. Exhibits and Reports on Form 8-K. . . . . . . . . . . . . . . . 22 SIGNATURES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 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, 1996 1995* ---- ---- ASSETS CURRENT ASSETS: Cash and cash equivalents . . . . . . . . . . . . $ 103,572 13,941 Receivables, less allowance for doubtful accounts of $1,990 ($1,842 at December 31, 1995) . . . . . . . . . . . . . . . 91,700 77,534 Inventories: Crude oil and wholesale refined products, at LIFO . . . . . . . . . . . . . . . . . . . . 51,988 70,406 Merchandise and refined products . . . . . . . . 8,400 5,153 Materials and supplies . . . . . . . . . . . . . 4,409 4,894 Prepayments and other . . . . . . . . . . . . . . 8,597 10,536 ------- ------- Total Current Assets . . . . . . . . . . . . . . 268,666 182,464 ------- ------- PROPERTY, PLANT AND EQUIPMENT: Refining and marketing. . . . . . . . . . . . . . 328,421 322,023 Exploration and production: Oil and gas (full cost method of accounting) . . 157,971 124,954 Gas transportation . . . . . . . . . . . . . . . 6,703 6,703 Marine services . . . . . . . . . . . . . . . . . 33,199 12,757 Corporate . . . . . . . . . . . . . . . . . . . . 12,315 12,443 ------- ------- 538,609 478,880 Less accumulated depreciation, depletion and amortization. . . . . . . . . . . . . . . . 248,238 217,191 ------- ------- Net Property, Plant and Equipment . . . . . . 290,371 261,689 ------- ------- RECEIVABLE FROM TENNESSEE GAS PIPELINE COMPANY (Note 4) . . . . . . . . . . . . . . . . . . . . . - 50,680 OTHER ASSETS. . . . . . . . . . . . . . . . . . . . 28,069 24,320 ------- ------- TOTAL ASSETS. . . . . . . . . . . . . . . . . $ 587,106 519,153 ======= ======= LIABILITIES AND STOCKHOLDERS' EQUITY CURRENT LIABILITIES: Accounts payable. . . . . . . . . . . . . . . . . $ 69,946 61,389 Accrued liabilities . . . . . . . . . . . . . . . 37,550 34,073 Current portion of long-term debt and other obligations. . . . . . . . . . . . . . . . . . . 83,513 9,473 ------- ------- Total Current Liabilities. . . . . . . . . . . . 191,009 104,935 ------- ------- DEFERRED INCOME TAXES . . . . . . . . . . . . . . . 16,554 5,389 ------- ------- OTHER LIABILITIES . . . . . . . . . . . . . . . . . 38,302 37,308 ------- ------- LONG-TERM DEBT AND OTHER OBLIGATIONS, LESS CURRENT PORTION . . . . . . . . . . . . . . . . . 80,020 155,007 ------- ------- COMMITMENTS AND CONTINGENCIES (Note 5) STOCKHOLDERS' EQUITY: Common Stock, par value $.16-2/3; authorized 50,000,000 shares; 26,399,371 shares issued and outstanding (24,780,134 in 1995) . . . . . . 4,398 4,130 Additional paid-in capital. . . . . . . . . . . . 189,185 176,599 Retained earnings . . . . . . . . . . . . . . . . 67,638 35,785 ------- ------- Total Stockholders' Equity . . . . . . . . . . . 261,221 216,514 ------- ------- TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY. . $ 587,106 519,153 ======= ======= The accompanying notes are an integral part of these condensed consolidated financial statements. * The balance sheet at December 31, 1995 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, ------------------ ----------------- 1996 1995 1996 1995 ---- ---- ---- ---- REVENUES: Refining and marketing. . . . . . . . $ 203,661 196,086 563,767 588,735 Exploration and production. . . . . . 26,476 29,626 83,933 96,747 Marine services . . . . . . . . . . . 32,660 18,467 87,467 56,848 Gain (loss) on sale of assets and other income. . . . . . . . . . (725) 33,144 4,378 33,166 ------- ------- ------- ------- Total Revenues . . . . . . . . . 262,072 277,323 739,545 775,496 ------- ------- ------- ------- OPERATING COSTS AND EXPENSES: Refining and marketing. . . . . . . . 194,156 190,463 545,303 584,418 Exploration and production. . . . . . 2,416 5,256 8,767 15,053 Marine services . . . . . . . . . . . 30,273 18,654 82,153 58,685 Depreciation, depletion and amortization . . . . . . . . . . . . 10,026 9,175 29,797 32,016 ------- ------- ------- ------- Total Operating Costs and Expenses. 236,871 223,548 666,020 690,172 ------- ------- ------- ------- OPERATING PROFIT . . . . . . . . . . . 25,201 53,775 73,525 85,324 General and Administrative . . . . . . (3,056) (4,372) (8,960) (12,371) Interest Expense . . . . . . . . . . . (4,142) (5,471) (12,142) (16,132) Interest Income. . . . . . . . . . . . 7,100 192 7,681 616 Other Expense, Net . . . . . . . . . . (1,254) (5,678) (8,802) (7,642) ------- ------- ------- ------- EARNINGS BEFORE INCOME TAXES AND EXTRAORDINARY LOSS. . . . . . . . . . 23,849 38,446 51,302 49,795 Income Tax Provision . . . . . . . . . 7,686 1,664 17,159 3,797 ------- ------- ------- ------- EARNINGS BEFORE EXTRAORDINARY LOSS . . 16,163 36,782 34,143 45,998 Extraordinary Loss on Extinguishment of Debt, Net of Income Tax Benefit of $886. . . . . . . . . . . . . . . (2,290) - (2,290) - ------- ------- ------- ------- NET EARNINGS . . . . . . . . . . . . . $ 13,873 36,782 31,853 45,998 ======= ======= ======= ======= EARNINGS PER SHARE: Earnings Before Extraordinary Loss. . $ .61 1.47 1.30 1.83 Extraordinary Loss, Net of Income Tax Benefit. . . . . . . . . . . . . (.09) - (.09) - ------- ------- ------- ------- Net Earnings . . . . . . . . . . . . $ .52 1.47 1.21 1.83 ======= ======= ======= ======= WEIGHTED AVERAGE COMMON AND COMMON EQUIVALENT SHARES. . . . . . . 26,816 25,093 26,370 25,140 ======= ======= ======= ======= 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, ----------------- 1996 1995 ---- ---- CASH FLOWS FROM (USED IN) OPERATING ACTIVITIES: Net earnings . . . . . . . . . . . . . . . . . . . . . . $ 31,853 45,998 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 . . . . . . . 30,386 32,763 Loss (gain) on sale of assets. . . . . . . . . . . . . 678 (33,055) Amortization of deferred charges and other . . . . . . 1,316 1,311 Changes in operating assets and liabilities: Receivable from Tennessee Gas Pipeline Company . . . 50,680 (29,465) Receivables, other trade . . . . . . . . . . . . . . (6,228) 9,916 Inventories. . . . . . . . . . . . . . . . . . . . . 16,901 6,006 Other assets . . . . . . . . . . . . . . . . . . . . 793 (4,434) Accounts payable and other current liabilities . . . 8,066 (349) Obligation payments to State of Alaska . . . . . . . (3,145) (2,129) Deferred income taxes. . . . . . . . . . . . . . . . 12,051 611 Other liabilities and obligations. . . . . . . . . . 2,760 3,108 ------- ------- Net cash from operating activities . . . . . . . . 148,401 30,281 ------- ------- CASH FLOWS FROM (USED IN) INVESTING ACTIVITIES: Capital expenditures . . . . . . . . . . . . . . . . . . (46,050) (48,881) Acquisition of Coastwide Energy Services, Inc. . . . . . (7,720) - Proceeds from sale of assets . . . . . . . . . . . . . . 1,079 69,711 Other. . . . . . . . . . . . . . . . . . . . . . . . . . (4,338) (3,201) ------- ------- Net cash from (used in) investing activities . . . . (57,029) 17,629 ------- ------- CASH FLOWS FROM (USED IN) FINANCING ACTIVITIES: Borrowings, net of repayments of $112,000 in 1996 and $262,500 in 1995, under revolving credit facilities. . . . . . . . . . . . . . . . . . . . . . . - - Payments of long-term debt . . . . . . . . . . . . . . . (2,885) (2,262) Other. . . . . . . . . . . . . . . . . . . . . . . . . . 1,144 (296) ------- ------- Net cash used in financing activities. . . . . . . . (1,741) (2,558) ------- ------- INCREASE IN CASH AND CASH EQUIVALENTS. . . . . . . . . . . 89,631 45,352 CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD . . . . . 13,941 14,018 ------- ------- CASH AND CASH EQUIVALENTS AT END OF PERIOD . . . . . . . . $ 103,572 59,370 ======= ======= SUPPLEMENTAL CASH FLOW DISCLOSURES: Interest paid. . . . . . . . . . . . . . . . . . . . . . $ 8,879 13,600 ======= ======= Income taxes paid. . . . . . . . . . . . . . . . . . . . $ 3,925 3,262 ======= ======= 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 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 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, 1995. 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 for the interim periods of 1995 to conform to the current presentation of financial information. NOTE 2 - ACQUISITION In February 1996, the Company purchased 100% of the capital stock of Coastwide Energy Services, Inc. ("Coastwide"). The consideration for the stock of Coastwide included approximately 1.4 million shares of Tesoro's Common Stock and $7.7 million in cash. The market price of Tesoro's Common Stock was $9.00 per share at closing of this transaction. In addition, upon closing, Tesoro repaid approximately $4.5 million of Coastwide's outstanding debt. Coastwide is primarily a provider of services and a wholesale distributor of diesel fuel and lubricants to the offshore petroleum industry in the Gulf of Mexico. The Company has combined its existing marine petroleum products distribution operations with Coastwide, forming a Marine Services segment. The acquisition of Coastwide was accounted for as a purchase whereby the purchase price was allocated to the assets acquired and liabilities assumed based upon their estimated fair values at the date of acquisition. NOTE 3 - LONG-TERM DEBT 12-3/4% Subordinated Debentures and 13% Exchange Notes In September 1996, the Company gave notice to fully redeem its two public debt issues, totaling approximately $74 million, at a price equal to 100% of the principal amount, plus accrued interest to the redemption date. The redemption of the debt, which was comprised of $44.1 million of outstanding 13% Exchange Notes ("Exchange Notes"), due December 1, 2000, and $30 million of outstanding 12-3/4% Subordinated Debentures ("Subordinated Debentures"), due March 15, 2001, was completed in November 1996. The redemption was accounted for as an early extinguishment of debt in the 1996 third quarter, resulting in a pretax charge of $3.2 million ($2.3 million aftertax) which represented a write-off of unamortized bond discount and issue costs. At September 30, 1996, the Exchange Notes and Subordinated Debentures were classified as current liabilities in the Consolidated Balance Sheet. Credit Facility In June 1996, the Company negotiated an amended and restated corporate revolving credit agreement ("Credit Facility") which provides total commitments of $150 million from a consortium of nine banks. The Credit Facility, which is subject to a borrowing base, provides for the issuance of letters of credit and cash borrowings. 6 The Company, at its option, has currently activated $100 million of commitments. Upon the resolution of the Tennessee Gas litigation and the collection of the related bonded receivable in the 1996 third quarter (see Note 4), certain provisions of the Credit Facility were enhanced, including an extension of the Credit Facility's expiration date to April 30, 2000 and an increase in cash borrowing availability from $50 million to $100 million. The Company had outstanding letters of credit of $39 million and no cash borrowings outstanding at September 30, 1996. 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. Cash borrowings under the Credit Facility bear interest at the prime rate plus .50% per annum or the London Interbank Offered Rate ("LIBOR") plus 1.5% per annum. Fees on outstanding letters of credit under the Credit Facility are 1.5% per annum. 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 restrict the incurrence of additional indebtedness and limit restricted payments. Under the Credit Facility, dividends up to $5 million per year are allowed, subject to the restricted payment covenant. See "Changes in Securities" in Part II, Item 2, contained herein. During the nine months ended September 30, 1996, the Company's gross borrowings and repayments under its revolving credit line totaled $112 million which were used on a short-term basis to finance working capital requirements and capital expenditures. NOTE 4 - GAS PURCHASE AND SALES CONTRACT The Company is selling a portion of the gas produced from its Bob West Field to Tennessee Gas Pipeline Company ("Tennessee Gas") under a Gas Purchase and Sales Agreement ("Contract") which expires in January 1999 and provides that the price of gas shall be the maximum price as calculated in accordance with Section 102(b)(2) ("Contract Price") of the Natural Gas Policy Act of 1978 ("NGPA"). In August 1990, Tennessee Gas filed suit against the Company and the other sellers under the Contract in the District Court of Bexar County, Texas, alleging that the Contract is not applicable to the Company's properties and that the gas sales price should be the price calculated under the provisions of Section 101 of the NGPA rather than the Contract Price. Tennessee Gas also claimed that the Contract should be considered an "output contract" under Section 2.306 of the Texas Uniform Commercial Code ("UCC") and that the increases in volumes tendered under the Contract exceeded those allowable for an output contract. The District Court judge returned a verdict in favor of the Company on all issues. Tennessee Gas appealed the District Court decision which was reviewed by the Supreme Court of Texas. On April 18, 1996, the Supreme Court of Texas issued its decision and affirmed the judgment of the District Court in full. Tennessee Gas filed a motion for rehearing and on August 16, 1996, the Supreme Court of Texas issued its mandate denying Tennessee Gas' motion for rehearing and upholding all aspects of the Contract. Tennessee Gas continues to take its minimum monthly required amount of gas and resumed paying the Contract Price to the Company for gas taken beginning with May 1996 volumes. On September 30, 1996, the Company received $67.5 million from Tennessee Gas, which included collection of a $59.6 million bonded receivable for underpayment for natural gas sold in prior periods. The remaining $7.9 million of cash received was for interest and reimbursement of legal fees and court costs, which had not previously been recorded by the Company resulting in income during the 1996 third quarter. For further information regarding the resolution of the Tennessee Gas litigation, see "Legal Proceedings" in Part II, Item 1, contained herein. 7 NOTE 5 - COMMITMENTS AND CONTINGENCIES 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 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 each 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 ("EPA") and other potentially responsible parties at the Abbeville, Louisiana site. The Company expects, based on these discussions, that its liability at the site 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, 1996, the Company's accruals for environmental matters amounted to $9.3 million, which included a noncurrent liability of approximately $4 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 anticipates that it will make capital improvements in 1996 and 1997 totaling approximately $2.3 million, primarily for upgrading of underground storage tanks. Environmental regulations would also have required the Company to make capital improvements starting in 1996 of approximately $9.5 million for the installation of dike liners. However, on April 18, 1996 the Alaska Department of Environmental Conservation ("ADEC") issued a memorandum stating that alternative compliance schedules allowing for delayed implementation of the requirements for dike liners in secondary containment systems for existing petroleum storage tanks would be approved. The April 18, 1996 ADEC Memorandum recognizes that secondary containment options other than synthetic dike liners are appropriate, but essential ADEC guidelines addressing other options will not be available before the end of 1996. The ADEC believes it will be three to five years before all affected facilities fully implement the provisions of the regulations. The Company is currently negotiating for an alternative compliance schedule with ADEC to maintain the Company's existing storage tank facilities in compliance with the state regulations. The Company cannot presently determine when an alternative schedule will be granted. 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. Incentive Compensation Strategy In June 1996, the Company's Board of Directors unanimously approved an 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 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 12 complete months and certain executives have been granted, from the Company's Executive Long-Term 8 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 - SEVERANCE TAX EXEMPTION In February 1996, the Texas Railroad Commission certified substantially all of the Company's proved producing reserves in the Bob West Field as high-cost gas from a designated tight formation. As a result of the Railroad Commission's certification, the Texas Comptroller's office has issued certificates for the majority of these wells, indicating that the wells have been classified as high-cost gas wells that are exempt from state severance taxes from the date of first production through August 2001. During the first quarter of 1996, based on approved severance tax exemption certificates received to date by the Company from the Texas Comptroller's office, the Company recorded $5 million of income for retroactive refunds. These exemptions also had the effect of increasing the pretax present value of the Company's 1995 year-end U.S. proved reserves by $7.7 million to $176.4 million. Severance tax expense will not be recorded for current production from exempt wells during 1996. 9 Item 2. TESORO PETROLEUM CORPORATION AND SUBSIDIARIES MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONNDITION AND RESULTS OF OPERATIONS RESULTS OF OPERATIONS Summary Net earnings of $13.9 million, or $.52 per share, for the three months ended September 30, 1996 ("1996 quarter") compare with net earnings of $36.8 million, or $1.47 per share, for the three months ended September 30, 1995 ("1995 quarter"). For the year-to-date period, net earnings of $31.9 million ($1.21 per share) for the nine months ended September 30, 1996 ("1996 period") compare with net earnings of $46.0 million ($1.83 per share) for the nine months ended September 30, 1995 ("1995 period"). A non-cash extraordinary loss of $3.2 million pretax, or $2.3 million after tax ($.09 per share), for early redemption of the Company's 13% Exchange Notes ("Exchange Notes") and 12-3/4% Subordinated Debentures ("Subordinated Debentures") was included in the 1996 quarter and period. Earnings before the extraordinary loss amounted to $16.2 million ($.61 per share) for the 1996 quarter and $34.2 million ($1.30 per share) for the 1996 period. Comparability between the results for 1996 and 1995 was further impacted by significant transactions which are highlighted in the table below (in millions): Three Months Ended Nine Months Ended September 30, September 30, ------------------ ----------------- 1996 1995 1996 1995 ---- ---- ---- ---- Net Earnings Excluding Significant Items . . $ 11.0 6.7 30.5 13.0 ---- ---- ---- ---- Significant Items Affecting Comparability: Interest and reimbursement of fees and costs from Tennessee Gas . . . . . . 7.9 - 7.9 - Gain (loss) on sale of assets. . . . . . . (.7) 33.5 (.7) 33.5 Operating profit from Bob West Field interests sold in 1995 . . . . . . . . . - 1.3 - 4.2 Employee terminations and restructuring costs. . . . . . . . . . . . . . . . . . - (4.7) (2.6) (4.7) Retroactive severance tax refund . . . . . - - 5.0 - Costs of shareholder consent solicitation resolved in April 1996 . . . - - (2.3) - Other. . . . . . . . . . . . . . . . . . . - - (2.1) - ---- ---- ---- ---- Total Significant Items, Pretax. . . . . 7.2 30.1 5.2 33.0 Income Tax Effect. . . . . . . . . . . . 2.0 - 1.5 - ---- ---- ---- ---- Total Significant Items, Aftertax. . . . 5.2 30.1 3.7 33.0 ---- ---- ---- ---- Earnings Before Extraordinary Item . . . . . 16.2 36.8 34.2 46.0 Extraordinary Loss on Debt Extinguishment, Net . . . . . . . . . . . . . . . . . . . (2.3) - (2.3) - ---- ---- ---- ---- Net Earnings as Reported . . . . . . . . . $ 13.9 36.8 31.9 46.0 ==== ==== ==== ==== As shown above, excluding significant items, the Company's net earnings would have been $11.0 million ($.41 per share) in the 1996 quarter, compared to $6.7 million ($.27 per share) in the 1995 quarter, and $30.5 million ($1.16 per share) for the 1996 period, compared to $13.0 million ($.52 per share) for the 1995 period. The resulting increase in net earnings in the 1996 quarter and period was primarily attributable to improvements within the Company's Refining and Marketing and Marine Services segments, each of which reported significant profit improvements from the comparable prior year periods. Additionally, at the corporate level, initiatives during the past twelve months helped reduce general and administrative expenses and interest expense. These improvements were partially offset by an increase in the Company's total effective rate in 1996 as earnings subject to U.S. taxes exceeded available net operating loss and tax credit carryforwards. 10 Refining and Marketing Three Months Ended Nine Months Ended - ---------------------- September 30, September 30, ------------------ ----------------- (Dollars in millions except per unit 1996 1995 1996 1995 amounts) ---- ---- ---- ---- Gross Operating Revenues: Refined products . . . . . . . . . . . $ 169.9 176.3 465.7 499.6 Other, primarily crude oil resales and merchandise. . . . . . . . . . . . . 33.8 19.8 98.1 89.1 ------ ------ ------ ------ Gross Operating Revenues. . . . . . . $ 203.7 196.1 563.8 588.7 ====== ====== ====== ====== Operating Profit (Loss): Gross margin - refined products. . . . $ 27.8 23.2 75.4 57.2 Gross margin - other . . . . . . . . . 3.9 3.7 10.1 9.3 ------ ------ ------ ------ Gross margin. . . . . . . . . . . . . 31.7 26.9 85.5 66.5 Operating expenses . . . . . . . . . . 22.3 21.3 67.1 62.0 Depreciation and amortization. . . . . 3.0 2.8 9.0 8.8 Loss on sale of assets and other . . . (.7) - (.7) (.2) ------ ------ ------ ------ Operating Profit (Loss) . . . . . . . $ 5.7 2.8 8.7 (4.5) ====== ====== ====== ====== Capital Expenditures . . . . . . . . . . $ 3.1 1.9 6.9 7.2 ====== ====== ====== ====== Refinery Operations - Throughput (average daily barrels) . . . . . . . . . . . . 41,165 56,504 45,760 50,056 ====== ====== ====== ====== Refinery Operations - Production (average daily barrels): Gasoline . . . . . . . . . . . . . . . 11,007 16,221 12,742 14,269 Middle distillates and other . . . . . 18,782 25,626 21,438 22,927 Heavy oils and residual product. . . . 12,706 16,025 13,218 14,278 ------ ------ ------ ------ Total Refinery Production . . . . . . 42,495 57,872 47,398 51,474 ====== ====== ====== ====== Refinery Operations - Product Spread ($/barrel)*: Average yield value of products manufactured. . . . . . . . . . . . . $ 24.81 20.07 23.95 20.16 Cost of raw materials. . . . . . . . . 19.43 16.81 18.91 17.13 ------ ------ ------ ------ Refinery Product Spread . . . . . . . $ 5.38 3.26 5.04 3.03 ====== ====== ====== ====== Refining and Marketing - Total Product Sales (average daily barrels): Gasoline . . . . . . . . . . . . . . . 18,073 26,330 18,751 25,562 Middle distillates . . . . . . . . . . 32,123 38,925 30,159 38,292 Heavy oils and residual product. . . . 16,489 16,009 14,594 14,468 ------ ------ ------ ------ Total Product Sales . . . . . . . . . 66,685 81,264 63,504 78,322 ====== ====== ====== ====== Refining and Marketing - Total Product Sales Prices ($/barrel): Gasoline . . . . . . . . . . . . . . . $ 34.52 28.53 32.35 28.10 Middle distillates . . . . . . . . . . $ 29.33 24.07 28.08 24.08 Heavy oils and residual product. . . . $ 17.03 14.09 16.86 13.09 Refining and Marketing - Gross Margins on Total Product Sales ($/barrel)*: Average sales price. . . . . . . . . . $ 27.70 23.55 26.76 23.37 Average costs of sales . . . . . . . . 23.16 20.46 22.43 20.69 ------ ------ ------ ------ Gross margin . . . . . . . . . . . . $ 4.54 3.09 4.33 2.68 ====== ====== ====== ====== * The refinery product spread presented above represents the excess of yield value of the products manufactured at the refinery over the cost of raw materials used to manufacture such products. Sources of total product sales include products manufactured at the refinery, existing inventory balances and products purchased from third parties. Margins on sales of purchased products, together with the effect of changes in inventories, are included in the gross margin on total product sales presented above. The Company's purchases of refined products for resale approximated 13,600 and 26,800 average daily barrels for the three months ended September 30, 1996 and 1995, respectively, and 12,100 and 26,900 average daily barrels for the nine months ended September 30, 1996 and 1995, respectively. 11 Three Months Ended September 30, 1996 Compared With Three Months Ended September 30, 1995. Results from the Company's Refining and Marketing segment improved during the 1996 quarter with operating profit of $5.7 million, as compared to operating profit of $2.8 million in the 1995 quarter. This improvement was achieved during a quarter when the industry was facing a rapidly rising crude oil market and margins were weakening, particularly towards the end of the 1996 quarter. At the same time, the Company had reduced production levels to complete a scheduled turnaround at its refinery during September 1996, but was able to maintain a refinery product spread of $5.38 per barrel for the 1996 quarter, which compares to $3.26 per barrel in the 1995 quarter. The Company's results were helped by its initiatives to reduce costs and improve marketing of its refined products. The Company's refined product yield values increased by 24% to $24.81 per barrel in the 1996 quarter from $20.07 per barrel in the 1995 quarter, while the Company's feedstock costs increased by 16% to $19.43 per barrel in the 1996 quarter from $16.81 per barrel in the 1995 quarter. Revenues from sales of refined products in the Company's Refining and Marketing segment were lower in the 1996 quarter due primarily to an 18% decrease in sales volumes, partially offset by an 18% increase in average sales prices. Total refined product sales volumes averaged 66,685 barrels per day in the 1996 quarter as compared to 81,264 barrels per day in the 1995 quarter. This decrease reflected the Company's withdrawal from certain West Coast markets, which also reduced the Company's purchases from other refiners and suppliers to 13,600 barrels per day in the 1996 quarter as compared to 26,800 barrels per day in the 1995 quarter. The Company has curtailed certain operations in California and plans to sell three Company-owned facilities, one of which was written down by $.7 million during the 1996 third quarter. Resales of crude oil increased in the 1996 third quarter to $24.8 million, compared to $11.0 million in the 1995 quarter, due primarily to sales of excess crude supply resulting from the scheduled turnaround at the Company's refinery during the current quarter and to increased crude oil prices. Costs of sales were higher in the 1996 quarter due to the rising prices for crude oil and refined products, partially offset by lower refined product volumes discussed above. Operating expenses were higher in the 1996 quarter, as compared to the 1995 quarter, by $1.0 million primarily due to a reduction of an environmental accrual in the 1995 quarter. Nine Months Ended September 30, 1996 Compared With Nine Months Ended September 30, 1995. Operating profit of $8.7 million in the 1996 period compared to an operating loss of $4.5 million in the 1995 period. This improvement was due primarily to higher product margins, as experienced generally by the industry and in part to initiatives by the Company to reduce costs and improve marketing of its refined products. The Company's average yield value of refined products increased by 19% to $23.95 per barrel in the 1996 period from $20.16 per barrel in the 1995 period, while average feedstock costs increased by only 10% to $18.91 per barrel in the 1996 period from $17.13 per barrel in the 1995 period. Revenues from sales of refined products in the Company's Refining and Marketing segment decreased in the 1996 period due primarily to a 19% decline in sales volumes, partially offset by a 15% increase in average sales prices. Total refined product sales averaged 63,504 barrels per day in the 1996 period as compared to 78,322 barrels per day in the 1995 period. This decline, as discussed above, reflected the Company's withdrawal from certain West Coast markets, which also reduced refined product purchases from other refiners and suppliers to 12,100 barrels per day in the 1996 period from 26,900 barrels per day in the 1995 period. Resales of crude oil increased to $74.6 million in the 1996 period from $65.8 million in the 1995 period due primarily to sales of excess crude supply resulting from the scheduled turnaround at the Company's refinery during the 1996 period and to increased crude oil prices. Costs of sales decreased in the 1996 period due to lower volumes of refined products, partially offset by higher prices for crude oil and refined products. Operating expenses were higher in the 1996 period, as compared to the 1995 period, by $5.1 million due primarily to the reduction of an environmental accrual in the 1995 period and, to a lesser extent, higher maintenance and employee termination costs in the 1996 period. Although results from the Company's Refining and Marketing segment for the 1996 quarter and period have improved over 1995 levels, margins continue to be volatile. Future profitability of this segment will continue to be significantly 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. 12 Exploration and Production Three Months Ended Nine Months Ended - -------------------------- September 30, September 30, ------------------ ----------------- (Dollars in millions except per unit 1996 1995 1996 1995 amounts) ---- ---- ---- ---- U.S. Oil and Gas: Gross operating revenues. . . . . . . . . $ 21.7 24.9 69.4 83.5 Other income - severance tax refunds. . . - - 5.0 - Gain on sale of assets. . . . . . . . . . - 33.5 - 33.5 Production costs. . . . . . . . . . . . . 1.3 3.2 3.8 9.9 Administrative support and other operating expenses . . . . . . . . . . . .1 .8 2.0 2.0 Depreciation, depletion and amortization. 6.1 6.2 18.7 22.8 ------ ------- ------ ------- Operating Profit - U.S. Oil and Gas. . . 14.2 48.2 49.9 82.3 ------ ------- ------ ------- U.S. Gas Transportation: Gross operating revenues. . . . . . . . . 1.3 1.5 4.0 4.2 Operating expenses. . . . . . . . . . . . .1 .1 .2 .2 Depreciation and amortization . . . . . . .1 .1 .2 .2 ------ ------- ------ ------- Operating Profit - U.S. Gas Transportation. . . . . . . . . . . . . 1.1 1.3 3.6 3.8 ------ ------- ------ ------- Bolivia: Gross operating revenues. . . . . . . . . 3.4 3.2 10.5 9.0 Production costs. . . . . . . . . . . . . .2 .2 .6 .5 Administrative support and other operating expenses. . . . . . . . . . . .6 .8 2.1 2.3 Depreciation, depletion and amortization . . . . . . . . . . . . . . .4 - 1.0 - ------ ------- ------ ------- Operating Profit - Bolivia . . . . . . . 2.2 2.2 6.8 6.2 ------ ------- ------ ------- Total Operating Profit - Exploration and Production. . . . . . . . $ 17.5 51.7 60.3 92.3 ====== ======= ====== ======= U.S.: Capital expenditures. . . . . . . . . . . $ 11.7 13.8 27.1 40.8 ====== ======= ====== ======= Net natural gas production (average daily Mcf) - Spot market and other. . . . . . . . . . 66,447 93,641 74,300 98,625 Tennessee Gas Contract(1). . . . . . . . 14,165 18,048 14,423 21,323 ------ ------- ------ ------- Total production . . . . . . . . . . 80,612 111,689 88,723 119,948 ====== ======= ====== ======= Average natural gas sales ($/Mcf) - Spot market(2) . . . . . . . . . . . . . $ 1.71 1.26 1.77 1.30 Tennessee Gas Contract(1). . . . . . . . $ 8.61 8.50 8.41 8.35 Average. . . . . . . . . . . . . . . . . $ 2.92 2.43 2.85 2.55 Average operating expenses ($/Mcf) - Lease operating expenses . . . . . . . . $ .14 .13 .12 .13 Severance taxes. . . . . . . . . . . . . .04 .17 .04 .17 ------ ------- ------ ------- Total production costs. . . . . . . . . .18 .30 .16 .30 Administrative support . . . . . . . . . .01 .10 .08 .06 ------ ------- ------ ------- Total operating expenses. . . . . . . . $ .19 .40 .24 .36 ====== ======= ====== ======= Depletion ($/Mcf) . . . . . . . . . . . . $ .82 .60 .77 .70 ====== ======= ====== ======= Bolivia: Capital expenditures. . . . . . . . . . . $ .8 - 5.7 - Net natural gas production (average daily Mcf) . . . . . . . . . . . . . . . 20,945 20,559 21,355 19,075 Average natural gas sales price ($/Mcf) . $ 1.31 1.32 1.33 1.29 Net condensate production (average daily barrels) . . . . . . . . . . . . . 605 604 611 589 Average condensate price ($/barrel) . . . $ 16.92 12.95 16.50 14.44 Average operating expenses ($/Mcfe) - Production costs . . . . . . . . . . . . $ .11 .05 .10 .08 Value-added taxes. . . . . . . . . . . . .08 .09 .07 .06 Administrative support . . . . . . . . . .24 .30 .24 .31 ------ ------- ------ ------- Total operating expenses . . . . . . . $ .43 .44 .41 .45 ====== ======= ====== ======= Depletion ($/Mcfe). . . . . . . . . . . . $ .17 - .15 - ====== ======= ====== ======= 13 (1) The Company is selling a portion of the gas produced from its Bob West Field to Tennessee Gas Pipeline Company ("Tennessee Gas") under a contract ("Tennessee Gas Contract") which expires in January 1999 (see Note 4 of Notes to Condensed Consolidated Financial Statements). (2) Includes effects of the Company's natural gas price swap agreements which amounted to a loss of $.19 per Mcf and a gain of $.05 per Mcf for the three months ended September 30, 1996 and 1995, respectively, and a loss of $.15 per Mcf and a gain of $.04 per Mcf for the nine months ended September 30, 1996 and 1995, respectively. (3) Mcf is defined as one thousand cubic feet; Mcfe is defined as net equivalent one thousand cubic feet. United States Three Months Ended September 30, 1996 Compared With Three Months Ended September 30, 1995. Operating profit of $14.2 million from the Company's U.S. oil and gas operations in the 1996 quarter compares to $48.2 million in the 1995 quarter. Included in the 1995 quarter was a gain of $33.5 million from the sale of certain interests in the Bob West Field and operating profit of $1.3 million related to these sold interests. Excluding these amounts from the 1995 quarter, operating profit improved 6% in the 1996 quarter, due primarily to a reduction in current severance taxes and other operating expenses together with higher sales price for natural gas. Prices realized by the Company on its spot natural gas production increased 36% to $1.71 per Mcf in the 1996 quarter from $1.26 per Mcf in the 1995 quarter. Excluding 26.6 Mmcf per day related to the sold interests from the 1995 quarter, the Company's spot production was essentially unchanged, with a 4.5 Mmcf per day decline in the Company's Bob West Field spot production offset by a 4.0 Mmcf per day increase in production from the Company's exploration and acquisition programs outside of the Bob West Field. The Company's weighted average sales price, including the above-market pricing of the Tennessee Gas Contract, increased 20% to $2.92 per Mcf in the 1996 quarter as compared to $2.43 per Mcf in the 1995 quarter. Volumes sold under the Tennessee Gas Contract declined 22% during the 1996 quarter due to an expected decline in contract deliverability. Gross operating revenues from the Company's U. S. oil and gas operations, after excluding revenues related to the sold interests from the 1995 quarter, remained essentially unchanged due to higher prices for the Company's spot production offsetting the decline in volumes sold under the Tennessee Gas Contract. Production costs, after excluding costs related to the sold interests from the 1995 quarter, were lower during the 1996 quarter due to a $1.3 million reduction in current severance taxes on exempt wells. On a per Mcf basis, production costs were reduced to $.18 per Mcf in the 1996 quarter, compared to $.30 per Mcf in the 1995 quarter, also due to the severance tax exemptions. Total operating expenses on a per Mcf basis decreased due to the lower production costs together with lower administrative expenses, primarily professional fees. Total depreciation, depletion and amortization was lower in the 1996 quarter due to lower production volumes, partially offset by a higher depletion rate. The Company enters into commodity price swap agreements to reduce the risk caused by fluctuations in the prices of natural gas in the spot market. During both the 1996 and 1995 quarters, the Company used such arrangements to set the price of approximately 38% of the natural gas production that it sold in the spot market. The Company realized a loss of $1.2 million (or $.19 per Mcf) during the 1996 quarter and a gain of $.5 million (or $.05 per Mcf) during the 1995 quarter from these price swap arrangements. Nine Months Ended September 30, 1996 Compared With Nine Months Ended September 30, 1995. Operating profit of $49.9 million from the Company's U.S. oil and gas operations in the 1996 period benefited from retroactive state severance tax exemptions totaling approximately $5 million from its Bob West Field production in prior years. Substantially all of the Company's proved producing reserves in the Bob West Field were certified by the Texas Railroad Commission as high-cost gas from a designated tight formation, eligible for state severance tax exemptions from the date of first production through August 2001. These exemptions also had the effect of increasing the pretax present value of the Company's 1995 year-end U.S. proved reserves by $7.7 million to $176.4 million. Severance tax expense will not be recorded for current production from exempt wells during 1996. Operating profit of $82.3 million in the 1995 period included a gain of $33.5 million from the sale of certain interests in the Bob West Field together with operating profit of $4.2 million related to these sold interests. Excluding the income related to the severance tax refund from the 1996 period and the operating profit related to sold interests from the 1995 period, operating profit from the U.S. oil and gas producing operations was relatively unchanged from the 1995 period. 14 Prices for sales of the Company's natural gas production sold into the spot market increased 36% to $1.77 per Mcf in the 1996 period from $1.30 per Mcf in the 1995 period. Excluding 32.7 average daily Mmcf related to the sold interests from the 1995 period, natural gas production sold into the spot market increased by 13% during the 1996 period, reflecting the effects of a voluntary curtailment by the Company during the early part of the 1995 period in response to poor market conditions during that time and reflecting initiatives by the Company during the 1996 period to add production through drilling and acquisition activities. The Company's weighted average sales price, including the effect of the above-market pricing of the Tennessee Gas Contract, increased to $2.85 per Mcf in the 1996 period from $2.55 per Mcf in the 1995 period. Production sold under the Tennessee Gas Contract decreased by 32% due to an expected decline in contract deliverability during the 1996 period. A compression facility will be installed in the Bob West Field by the end of 1996 that may impact the decline in future contract deliverability. Gross operating revenues from the Company's U.S. oil and gas operations, after excluding $11.7 million related to the sold interests from the 1995 period and excluding the price swap transactions discussed below, increased by $1.5 million due to increases in the Company's sales prices for its spot production and due to new production from the Company's development, exploration and acquisition programs offsetting the declines in volumes sold under the Tennessee Gas Contract. The decrease in total production costs, after excluding costs related to the sold interests in the 1995 period, reflected a reduction of $4.0 million in current year severance taxes. On a per Mcf basis, production costs were reduced to $.16 per Mcf compared to $.30 per Mcf due to the exemption of severance taxes. Total depreciation, depletion and amortization was lower in the 1996 period due to lower production volumes, partially offset by a higher depletion rate. The Company enters into commodity price swap agreements to reduce the risk caused by fluctuations in the prices of natural gas in the spot market. During the 1996 and 1995 periods, the Company used such arrangements to set the price of 37% and 28%, respectively, of the natural gas production that it sold in the spot market. During the 1996 and 1995 periods, the Company realized a loss of $2.9 million (or $.15 per Mcf) and a gain of $1.0 million (or $.04 per Mcf), respectively, from these price swap arrangements. As of September 30, 1996, the Company had no material price swap arrangements remaining for 1996. Bolivia Three Months Ended September 30, 1996 Compared With Three Months Ended September 30, 1995. Operating profit from the Company's Bolivian operations during the 1996 quarter remained relatively unchanged from the 1995 quarter, as increased revenues from higher condensate prices together with lower operating expenses were offset by increased depreciation, depletion and amortization. During the 1996 quarter, the Company's net production of natural gas in Bolivia averaged 20.9 Mmcf per day, relatively constant with the 1995 quarter. Nine Months Ended September 30, 1996 Compared With Nine Months Ended September 30, 1995. Operating profit from the Company's Bolivian operations increased by $.6 million during the 1996 period, primarily due to a 12% increase in production of natural gas together with higher prices received for both natural gas and condensate. During the second and third quarters of 1996, the Company benefited from increased demand from the Bolivian state-owned oil and gas company for higher quality natural gas, in order to meet contract specifications for exports to Argentina, together with the inability of another producer to meet supply requirements. Production costs and other operating expenses remained relatively unchanged in total but declined by 9% on a per unit basis reflecting the increase in volumes with minimal increases in expenses. Partially offsetting these improvements was depreciation, depletion and amortization of $1.0 million recorded in the 1996 period. Bolivian Hydrocarbons Laws. On April 30, 1996, a new Hydrocarbons Law that significantly impacts the Company's operations in Bolivia was enacted by the Bolivian government. Among other matters, the new law granted the Company the option to convert its Contracts of Operation to Shared Risk Contracts. On July 29, 1996, the Company signed agreements converting its Contracts of Operation to Shared Risk Contracts subject to recision at the option of the Company if the Company is not satisfied with modifications to Bolivian fiscal law to be enacted not later than January 31, 1997. The Shared Risk Contracts extend the term of operation, provide more favorable acreage relinquishment terms and a revised fiscal regime of taxes and tariffs. The new contracts will extend the Company's operations on Block 18 and Block 20 to 2017 and 2029 from their current expiration dates of 2007 and 2008, respectively, except for an Exploitation Area in Block 20 which will have an expiration date of 2018. The new contract provisions may result in an immediate increase, which the Company believes could be as high 15 as 35%, in the Company's proved Bolivian reserves that have been previously limited by the contract termination dates. In connection with the conversion to Shared Risk Contracts, the Company retained its productive fields on Block 18 with no relinquishment of acreage. On Block 20, the Company selected certain acreage to be relinquished, retaining its discoveries and approximately two-thirds of the remaining unexplored Block 20 acreage. Block 20 is subject to a seven-year exploration period, certain future acreage relinquishments and exploration drilling obligations required by law. Marine Services Three Months Ended Nine Months Ended - --------------- September 30, September 30, ------------------ ----------------- (Dollars in millions) 1996 1995 1996 1995 ---- ---- ---- ---- Gross Operating Revenues . . . . . . . $ 32.7 18.5 87.5 56.9 Costs of Sales . . . . . . . . . . . . 24.5 15.8 66.7 49.2 ------ ------ ------- ------ Gross Margin . . . . . . . . . . . . 8.2 2.7 20.8 7.7 Operating and Other Expenses . . . . . 5.8 3.3 15.4 9.9 Depreciation and Amortization. . . . . .4 .1 .9 .3 ------ ------ ------- ------ Operating Profit (Loss). . . . . . . $ 2.0 (.7) 4.5 (2.5) ====== ====== ======= ====== Capital Expenditures . . . . . . . . . $ 1.2 .1 6.2 .2 ====== ====== ======= ====== Refined Product Sales, Primarily Diesel Fuel (thousands of gallons). . 37,829 27,837 107,376 86,210 ====== ====== ======= ====== On February 20, 1996, the Company acquired Coastwide Energy Services, Inc. ("Coastwide") and combined Coastwide's operations with the Company's marine petroleum products distribution business, forming a Marine Services segment. As a combined operation, the Marine Services segment is a wholesale distributor of diesel fuel and lubricants and a provider of services to the offshore petroleum industry in the Gulf of Mexico. Operating results from Coastwide have been included in the Company's Marine Services segment since the date of acquisition. The Marine Services segment currently consists of 22 terminals, primarily marine-based, as compared to 15 terminals in the prior year. The added locations and volumes, mainly related to the acquisition discussed above, combined with higher refined product prices, have contributed to revenue increases for the segment of $14.2 million and $30.6 million during the 1996 quarter and period, respectively, when compared to the same periods of the prior year. Sales of refined products, primarily diesel fuel, have increased by 36% during the 1996 quarter and 25% during the 1996 period. These increases in volumes together with improved margins during the 1996 quarter and period were partially offset by higher operating and other expenses associated with the increased activity. Depreciation and amortization increased during the 1996 quarter and period due to capital additions during the year. In total, results for the Marine Services segment reflected a turnaround from the losses incurred in the prior year with operating profit of $2.0 million for the 1996 quarter and $4.5 million for the 1996 period. General and Administrative Expenses General and administrative expenses decreased by $1.3 million, or 30%, during the 1996 quarter and by $3.4 million, or 27%, during the 1996 period. These decreases were primarily due to lower employee and labor costs resulting from cost reduction measures implemented by the Company in late 1995. Interest Expense Interest expense decreased by $1.3 million, or 24%, during the 1996 quarter and by $4.0 million, or 25%, during the 1996 period. In December 1995, the Company redeemed $34.6 million of its Subordinated Debentures which, together with lower borrowings under the Company's revolving credit facility, resulted in the interest expense savings during the 1996 quarter and period. In November 1996, the Company fully redeemed its two public debt issues, totaling approximately $74 million, which will further reduce the Company's interest expense by approximately $10 million annually. 16 Interest Income On September 30, 1996, the Company received interest of approximately $7 million from Tennessee Gas in conjunction with the collection of a receivable which resulted from underpayment for natural gas sold in prior periods (see Note 4 of Notes to Condensed Consolidated Financial Statements). Interest income for the 1996 quarter and period benefited from this receipt, which had not previously been recorded by the Company. Other Expense, Net The decrease of $4.4 million in other expense during the 1996 quarter resulted primarily from severance costs and related benefits of $3.8 million incurred for an administrative workforce reduction and other employee terminations during the 1995 quarter. For the 1996 period, other expense increased by $1.2 million, primarily due to costs of $2.3 million related to a shareholder consent solicitation which was resolved in April 1996 together with a write-off of deferred financing costs , partially offset by lower employee termination costs. Income Taxes Income taxes increased by $5.9 million and $13.3 million during the 1996 quarter and period, respectively. These increases were primarily due to a higher effective tax rate for the Company during the 1996 quarter and period as earnings subject to U.S. taxes exceeded available net operating loss and tax credit carryforwards. 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 gross 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. Likewise, changes in natural gas prices impact revenues and the present value of estimated future net revenues and cash flows from the Company's exploration and production operations. From time to time, the Company may increase or decrease its natural gas production in response to market conditions. The carrying value of natural gas assets may also be subject to noncash write-downs based on changes in natural gas prices and other determining factors. CAPITAL RESOURCES AND LIQUIDITY Overview 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 factors that are beyond the control of the Company. These factors 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, borrowings under its credit facility and other sources of capital will be affected by these conditions. During the 1996 period, the Company achieved improvement in profitability, primarily from its Refining and Marketing and Marine Services segments. Furthermore, the resolution of the Tennessee Gas litigation in August 1996 removed a major financial uncertainty from the Company's capital structure that will improve the predictability of the Company's cash flow, provide for additional financial flexibility, and allow the Company to focus on growth initiatives. In these regards, the receipt of $67.5 million from Tennessee Gas on September 30, 1996 has enabled the Company to fully redeem its two public debt issues, reducing the Company's debt-to-capital ratio to 23%. The Company continues to assess its existing asset base in order to maximize returns and financial flexibility through diversification, acquisitions and divestitures in all of its operating segments. This ongoing assessment includes, in the Exploration and Production segment, evaluating ways in which the Company might diversify the mix of its oil and gas assets and offset the impact of declining production under the Tennessee Gas Contract 17 through domestic development, exploration and acquisition activity outside of the Bob West Field. In the Refining and Marketing segment, the Company has been engaged in an ongoing effort to evaluate these assets and operations and has considered possible joint ventures, strategic alliances or business combinations; however, such evaluations have not resulted in any transaction. The Company continues to assess its Marine Services segment, pursuing opportunities to consolidate operations and improve efficiencies. In these regards, during the 1996 period, the Company completed the acquisition of Coastwide for approximately 1.4 million shares of Tesoro's Common Stock and $7.7 million in cash (see Note 2 of Notes to Condensed Consolidated Financial Statements). Resolution of Tennessee Gas Litigation The Company is selling a portion of the gas produced from its Bob West Field to Tennessee Gas Pipeline Company ("Tennessee Gas") under a Gas Purchase and Sales Agreement ("Contract") which expires in January 1999 and provides that the price of gas shall be the maximum price as calculated in accordance with Section 102(b)(2) ("Contract Price") of the Natural Gas Policy Act of 1978 ("NGPA"). In August 1990, Tennessee Gas filed suit against the Company and the other sellers under the Contract in the District Court of Bexar County, Texas, alleging that the Contract is not applicable to the Company's properties and that the gas sales price should be the price calculated under the provisions of Section 101 of the NGPA rather than the Contract Price. Tennessee Gas also claimed that the Contract should be considered an "output contract" under Section 2.306 of the Texas Uniform Commercial Code ("UCC") and that the increases in volumes tendered under the Contract exceeded those allowable for an output contract. The District Court judge returned a verdict in favor of the Company on all issues. Tennessee Gas appealed the District Court decision which was reviewed by the Supreme Court of Texas. On April 18, 1996, the Supreme Court of Texas issued its decision and affirmed the judgment of the District Court in full. Tennessee Gas filed a motion for rehearing and on August 16, 1996, the Supreme Court of Texas issued its mandate denying Tennessee Gas' motion for rehearing and upholding all aspects of the Contract. Tennessee Gas continues to take its minimum monthly required amount of gas and resumed paying the Contract Price to the Company for gas taken beginning with May 1996 volumes. On September 30, 1996, the Company received $67.5 million from Tennessee Gas, which included collection of a $59.6 million bonded receivable for underpayment for natural gas sold in prior periods. The remaining $7.9 million of cash received was for interest and reimbursement of legal fees and court costs, which had not previously been recorded by the Company resulting in income during the 1996 third quarter. For further information regarding the resolution of the Tennessee Gas litigation, see "Legal Proceedings" in Part II, Item 1, contained herein. Redemption of Debt In September 1996, the Company gave notice to fully redeem its two public debt issues, totaling approximately $74 million, at a price equal to 100% of the principal amount, plus accrued interest to the redemption date. The redemption of the debt, which was comprised of $44.1 million of outstanding Exchange Notes, due December 1, 2000, and $30 million of outstanding Subordinated Debentures, due March 15, 2001, was completed in November 1996. See Note 3 of Notes to Condensed Consolidated Financial Statements for further information on the redemption of debt and "Changes in Securities" in Part II, Item 2, contained herein, regarding dividend restrictions. Credit Arrangements In June 1996, the Company negotiated an amended and restated corporate revolving credit agreement ("Credit Facility") which provides total commitments of $150 million from a consortium of nine banks. The Credit Facility, which is subject to a borrowing base, provides for the issuance of letters of credit and cash borrowings. The Credit Facility replaced a higher-cost $90 million facility and provides the Company with more financial flexibility, including lower interest rates, reduced fees on letters of credit, elimination of certain restrictive financial tests, an increased borrowing base, increased cash borrowing availability, and the right to restructure non-recourse or limited financings for certain subsidiaries. The Company, at its option, has currently activated $100 million of commitments. Upon the resolution of the Tennessee Gas litigation and the collection of the related bonded receivable in the 1996 third quarter (see Note 4 of Notes to Condensed Consolidated Financial Statements), certain provisions of the Credit Facility were enhanced, including an extension of the Credit Facility's expiration date to April 30, 2000 and an increase in cash borrowing availability from $50 million to $100 million. 18 At September 30, 1996, the Company had outstanding letters of credit of $39 million and no cash borrowings outstanding. 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 restrict the incurrence of additional indebtedness and limit restricted payments. Under the Credit Facility, dividends up to $5 million per year are allowed, subject to the restricted payment covenant. See "Changes in Securities" in Part II, Item 2, contained herein. Capital Expenditures For the year 1996, the Company's capital budget is approximately $85 million, of which approximately $46 million had been spent during the nine months ended September 30, 1996. The Company expects to continue funding of its capital expenditures for 1996 through a combination of cash flows from operations and borrowings under its Credit Facility. The Exploration and Production segment accounts for $64 million of the 1996 budgeted expenditures, including as much as $56 million for U.S. activities and $8 million for Bolivia. The Company's planned U.S. expenditures include $36 million for exploration, development and acquisition outside of the Bob West Field and $20 million for development drilling and facilities in the Bob West Field. Through the nine months ended September 30, 1996, total U.S. expenditures were $27 million, principally for participation in the drilling of ten development wells (nine completed) and four exploratory wells (two completed) and acquisitions of proved properties. The Company's U.S. budget for the remainder of 1996 of $29 million includes $19 million for drilling projects, some of which may not be commenced by year-end, and $10 million for unspecified acquisitions. Although the Company continues to pursue exploration, development and acquisition opportunities, actual capital expenditures may vary from budget due to a number of factors, including the timing of drilling projects and the extent to which proved properties are acquired. In Bolivia, capital spending totaled $6 million during the first nine months of 1996, primarily for the drilling and completion of two exploratory wells. Capital spending for the Refining and Marketing segment is projected to be $13 million for 1996, of which $7 million had been spent through the first nine months, primarily for installation of facilities to produce and market asphalt, improvements and upgrades at the refinery, expansion of its retail marketing facilities, and environmental projects. In the Marine Services segment, capital spending for 1996 is budgeted at $7 million, of which $6 million had been spent through the first nine months (excluding amounts for the Coastwide acquisition). Capital expenditures have contributed to this segment's improved operating efficiencies and marketing efforts. Cash Flows From Operating, Investing and Financing At September 30, 1996, the Company's working capital totaled $78 million, which included cash of $104 million and current liabilities for debt and other obligations of $84 million. In November 1996, the Company redeemed its two public debt issues, using approximately $74 million of cash and reducing current liabilities. Components of the Company's cash flows are set forth below (in millions): Nine Months Ended September 30, ----------------- 1996 1995 ---- ---- Cash Flows From (Used In): Operating Activities . . . . . . . . . . . . . . . $ 148.4 30.3 Investing Activities . . . . . . . . . . . . . . . (57.0) 17.6 Financing Activities . . . . . . . . . . . . . . . (1.8) (2.5) ----- ---- Increase in Cash and Cash Equivalents. . . . . . . . $ 89.6 45.4 ===== ==== Net cash from operating activities of $148 million during the 1996 period, which compares to $30 million for the 1995 period, included the receipt of $67.5 million from Tennessee Gas (see Note 4 of Notes to Condensed Consolidated Financial Statements) and reduced working capital balances. Net cash used in investing activities during the 1996 period of $57 million included capital expenditures of $46 million and cash consideration of $7.7 million for the acquisition of Coastwide. Capital expenditures for the 1996 period included $33 million for the 19 Company's exploration and production activities in South Texas and Bolivia. Net cash used in financing activities of $2 million during the 1996 period was primarily due to payments of long-term debt. During the 1996 period, the Company's gross borrowings and repayments under its revolving credit line amounted to $112 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, 1996, the Company's accruals for environmental matters amounted to $9.3 million, which included a noncurrent liability of approximately $4 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 anticipates that it will make capital improvements in 1996 and 1997 totaling approximately $2.3 million, primarily for upgrading of underground storage tanks. Environmental regulations would also have required the Company to make capital improvements starting in 1996 of approximately $9.5 million for the installation of dike liners. However, on April 18, 1996, the Alaska Department of Environmental Conservation ("ADEC") issued a memorandum stating that alternative compliance schedules allowing for delayed implementation of the requirements for dike liners in secondary containment systems for existing petroleum storage tanks would be approved. The April 18, 1996 ADEC Memorandum recognizes that secondary containment options other than synthetic dike liners are appropriate, but essential ADEC guidelines addressing other options will not be available before the end of 1996. The ADEC believes it will be three to five years before all affected facilities fully implement the provisions of the regulations. The Company is currently negotiating for an alternative compliance schedule with ADEC to maintain the Company's existing storage tank facilities in compliance with the state regulations. The Company cannot presently determine when an alternative schedule will be granted. 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 5 of Notes to Condensed Consolidated Financial Statements. FORWARD-LOOKING STATEMENTS Statements concerning the Company, including those contained in the foregoing discussion, 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 20 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. PART II - OTHER INFORMATION Item 1. Legal Proceedings The Company is selling a portion of the gas produced from its Bob West Field to Tennessee Gas Pipeline Company ("Tennessee Gas") under a Gas Purchase and Sales Agreement ("Contract") which expires in January 1999 and provides that the price of gas shall be the maximum price as calculated in accordance with Section 102(b)(2) ("Contract Price") of the Natural Gas Policy Act of 1978 ("NGPA"). In August 1990, Tennessee Gas filed suit against the Company and the other sellers under the Contract in the District Court of Bexar County, Texas, alleging that the Contract is not applicable to the Company's properties and that the gas sales price should be the price calculated under the provisions of Section 101 of the NGPA rather than the Contract Price. Tennessee Gas also claimed that the Contract should be considered an "output contract" under Section 2.306 of the Texas Uniform Commercial Code ("UCC") and that the increases in volumes tendered under the Contract exceeded those allowable for an output contract. The District Court judge returned a verdict in favor of the Company on all issues. Tennessee Gas appealed the District Court decision which was reviewed by the Supreme Court of Texas. On April 18, 1996, the Supreme Court of Texas issued its decision and affirmed the judgment of the District Court in full. Tennessee Gas filed a motion for rehearing and on April 16, 1996, the Supreme Court of Texas issued its mandate denying Tennessee Gas' motion for rehearing and upholding all aspects of the Contract. Subsequently, the parties entered into an Agreement Regarding Partial Satisfaction of Judgment ("Judgment") effective September 30, 1996, pursuant to which Tennessee Gas paid the Company $67,500,063.87 including interest and attorney fees, and the issue of how interest should ultimately be computed was referred to the District Court for final decision. On October 31, 1996, the District Court ruled that interest on the Judgment should be computed at a rate of 9% per annum compounded, rather than 9% simple, the rate that the Company was paid under the Judgment. As a result, Tennessee Gas paid the Company an additional $154,348.15 in November 1996. The District Court has entered Agreed Orders Releasing Supersedeas Bonds and discharging Tennessee Gas and its surety from all obligations with respect to the Supersedeas Bonds in the amount of $206 million posted by Tennessee Gas during the appeal process and releasing funds in the Registry of the Court whereby three Certificates of Deposit, in the total amount of $220,088.81, will be distributed among the Company and the other sellers under the Contract. Tennessee Gas continues to take its minimum monthly required amount of gas and resumed paying the Contract Price to the Company for gas taken beginning with May 1996 volumes. See Note 4 of Notes to Condensed Consolidated Financial Statements in Part I, Item 1, contained herein. Item 2. Changes in Securities In September 1996, the Company gave notice to redeem its 13% Exchange Notes ("Exchange Notes") and 12-3/4% Subordinated Debentures ("Subordinated Debentures"). See Note 3 of Notes to Condensed Consolidated Financial Statements in Part I, Item 1, contained herein. With the redemption of this debt in November 1996, the Company is no longer subject to the indenture governing the Subordinated Debentures which contained covenants that prevented the payment of cash dividends on Common Stock and limited the Company's ability to purchase or redeem any shares of its capital stock. As previously reported, the Company will continue to be subject to covenants under its Amended and Restated Credit Agreement ("Credit Facility") with respect to dividends on its capital stock. Although the terms of the Credit Facility allow for the payment of cash dividends subject to a cumulative amount available for dividend payments (which is defined as the difference of (i) the sum since December 31, 1995, of (a) $5,000,000 and (b) 50% of consolidated net earnings of the Company in any calendar year and (ii) any amount previously paid for dividends since June 1996), cash dividends cannot exceed a maximum of $5,000,000 annually. The Credit Facility also permits the Company to repurchase a limited amount of Common Stock for oddlot buyback programs, employee benefit plans and open market repurchases. The Board of Directors has no present plans to pay dividends. However, from time to time, the Board of Directors will reevaluate the feasibility of declaring future dividends. 21 Item 6. Exhibits and Reports on Form 8-K (a) Exhibits Exhibit Number Description 27 Financial Data Schedule. (b) Reports on Form 8-K No reports on Form 8-K have been filed during the quarter for which this report is filed. 22 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, 1996 /s/ BRUCE A. SMITH Bruce A. Smith Chairman of the Board of Directors, President and Chief Executive Officer Date: November 14, 1996 /s/ DON E. BEERE Don E. Beere Vice President, Controller (Chief Accounting Officer) 23 EX-27 2 FINANCIAL DATA SCHEDULE
5 THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM TESORO PETROLEUM CORPORATION'S FINANCIAL STATEMENTS AS OF AND FOR THE NINE MONTH PERIOD ENDED SEPTEMBER 30, 1996, AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL STATEMENTS. 1,000 9-MOS DEC-31-1996 SEP-30-1996 103,572 0 93,690 1,990 64,797 268,666 538,609 248,238 587,106 191,009 80,020 4,398 0 0 256,823 587,106 735,167 739,545 636,223 636,223 30,386 0 12,142 51,302 17,159 34,143 0 (2,290) 0 31,853 1.21 1.21 EARNINGS PER SHARE IS AFTER AN EXTRAORDINARY LOSS OF $2.3 MILLION ($.09 LOSS PER SHARE) ON EXTINGUISHMENT OF DEBT.
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