0000050104-95-000008.txt : 19950815 0000050104-95-000008.hdr.sgml : 19950815 ACCESSION NUMBER: 0000050104-95-000008 CONFORMED SUBMISSION TYPE: 10-Q PUBLIC DOCUMENT COUNT: 5 CONFORMED PERIOD OF REPORT: 19950630 FILED AS OF DATE: 19950814 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: 95563261 BUSINESS ADDRESS: STREET 1: 8700 TESORO DR CITY: SAN ANTONIO STATE: TX ZIP: 78217 BUSINESS PHONE: 2108288484 10-Q 1 10Q FOR QUARTER ENDED 6/30/95 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 June 30, 1995 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 (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 24,535,458 shares of the Registrant's Common Stock outstanding at July 31,1995. TESORO PETROLEUM CORPORATION AND SUBSIDIARIES INDEX TO FORM 10-Q FOR THE QUARTERLY PERIOD ENDED JUNE 30, 1995 PART I. FINANCIAL INFORMATION Page Item 1. Financial Statements (Unaudited) Condensed Consolidated Balance Sheets - June 30, 1995 and December 31, 1994 . . . . . . . . . . . . . . . . . . . . . . 3 Condensed Statements of Consolidated Operations - Three Months and Six Months Ended June 30, 1995 and 1994 . . . . . . . . 4 Condensed Statements of Consolidated Cash Flows - Six Months Ended June 30, 1995 and 1994 . . . . . . . . . . . . . . . . . . . 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 . . . . . . . . . . . . . . . . . . . . . 22 Item 4. Submission of Matters to a Vote of Security Holders . . . . 24 Item 6. Exhibits and Reports on Form 8-K . . . . . . . . . . . . . 24 SIGNATURES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25 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) June 30, December 31, 1995 1994* ASSETS CURRENT ASSETS: Cash and cash equivalents. . . . . . . . . . . . $ 7,356 14,018 Receivables, less allowance for doubtful accounts of $1,962 ($1,816 at December 31, 1994) . . . . 64,489 73,406 Receivable from Tennessee Gas Pipeline Company (Note 4) . . . . . . . . . . . . . . . . . . . 35,381 17,734 Inventories: Crude oil and wholesale refined products, at LIFO . . . . . . . . . . . . . . . . . . . 53,926 58,798 Merchandise and retail refined products . . . . 4,564 5,934 Materials and supplies. . . . . . . . . . . . . 3,867 3,570 Prepaid expenses and other . . . . . . . . . . . 13,661 8,648 --------- --------- Total Current Assets. . . . . . . . . . . . . . 183,244 182,108 PROPERTY, PLANT AND EQUIPMENT, Net of Accumulated Depreciation, Depletion and Amortization of $228,708 ($205,782 at December 31, 1994) . . . . 285,623 273,334 INVESTMENT IN TESORO BOLIVIA PETROLEUM COMPANY . . 13,248 10,295 OTHER ASSETS . . . . . . . . . . . . . . . . . . . 20,487 18,623 --------- --------- TOTAL ASSETS . . . . . . . . . . . . . . . $ 502,602 484,360 ========= ========= LIABILITIES AND STOCKHOLDERS' EQUITY CURRENT LIABILITIES: Accounts payable . . . . . . . . . . . . . . . . $ 58,307 53,573 Accrued liabilities. . . . . . . . . . . . . . . 33,292 35,266 Current portion of long-term debt and other obligations . . . . . . . . . . . . . . . . . . 8,694 7,404 --------- --------- Total Current Liabilities . . . . . . . . . . . 100,293 96,243 --------- --------- DEFERRED INCOME TAXES. . . . . . . . . . . . . . . 4,744 4,582 --------- --------- OTHER LIABILITIES. . . . . . . . . . . . . . . . . 37,352 30,593 --------- --------- LONG-TERM DEBT AND OTHER OBLIGATIONS, LESS CURRENT PORTION. . . . . . . . . . . . . . . . . 189,096 192,210 --------- --------- COMMITMENTS AND CONTINGENCIES (Notes 3 and 4) STOCKHOLDERS' EQUITY: Common Stock, par value $.16-2/3; authorized 50,000,000 shares; 24,539,497 shares issued and outstanding (24,389,801 in 1994) . . . . . 4,090 4,065 Additional paid-in capital . . . . . . . . . . . 176,658 175,514 Accumulated deficit. . . . . . . . . . . . . . . ( 9,631) ( 18,847) --------- --------- Total Stockholders' Equity. . . . . . . . . . . 171,117 160,732 --------- --------- TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $ 502,602 484,360 ========= ========= The accompanying notes are an integral part of these condensed consolidated financial statements. * The balance sheet at December 31, 1994 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 Six Months Ended June 30, June 30, ------------------ ------------------ 1995 1994 1995 1994 ---- ---- ---- ---- REVENUES: Gross operating revenues . . . . . . . . . . . . . $ 265,129 210,660 499,830 399,747 Interest income. . . . . . . . . . . . . . . . . . 188 452 424 975 Gain (loss) on sales of assets . . . . . . . . . . ( 9) ( 339) ( 2) 2,341 Other. . . . . . . . . . . . . . . . . . . . . . . 130 272 211 722 --------- --------- --------- --------- Total Revenues. . . . . . . . . . . . . . . . . . 265,438 211,045 500,463 403,785 --------- --------- --------- --------- COSTS AND EXPENSES: Costs of sales and operating expenses . . . . . . 234,501 191,228 445,112 358,833 General and administrative . . . . . . . . . . . . 4,185 3,377 7,999 7,004 Depreciation, depletion and amortization . . . . . 11,412 7,718 23,327 14,395 Interest expense, net of $240 capitalized in 1994. 5,368 4,629 10,661 9,506 Other. . . . . . . . . . . . . . . . . . . . . . . 1,093 2,252 2,015 3,443 --------- --------- --------- --------- Total Costs and Expenses. . . . . . . . . . . . . 256,559 209,204 489,114 393,181 --------- --------- --------- --------- EARNINGS BEFORE INCOME TAXES AND EXTRAORDINARY LOSS ON EXTINGUISHMENT OF DEBT . . . . . . . . . . . . . . 8,879 1,841 11,349 10,604 Income Tax Provision . . . . . . . . . . . . . . . . 1,423 611 2,133 2,172 --------- --------- --------- --------- EARNINGS BEFORE EXTRAORDINARY LOSS ON EXTINGUISHMENT OF DEBT. . . . . . . . . . . . . 7,456 1,230 9,216 8,432 Extraordinary Loss on Extinguishment of Debt . . . . - - - ( 4,752) --------- --------- --------- --------- NET EARNINGS . . . . . . . . . . . . . . . . . . . . 7,456 1,230 9,216 3,680 Dividend Requirements on Preferred Stocks . . . . . - 791 - 2,680 --------- --------- --------- --------- NET EARNINGS APPLICABLE TO COMMON STOCK . . . . . . . . . . . . . . . . . . . $ 7,456 439 9,216 1,000 ========= ========= ========= ========= EARNINGS (LOSS) PER PRIMARY AND FULLY DILUTED SHARE: Earnings Before Extraordinary Loss on Extinguishment of Debt. . . . . . . . . . . . . . $ .30 .02 .37 .27 Extraordinary Loss on Extinguishment of Debt . . . - - - ( .22) --------- --------- --------- --------- Net Earnings . . . . . . . . . . . . . . . . . . . $ .30 .02 .37 .05 ========= ========= ========= ========= AVERAGE OUTSTANDING COMMON AND COMMON EQUIVALENT SHARES . . . . . . . . . . . . . 25,206 23,222 25,163 21,350 ========= ========= ========= ========= Anti-dilutive.
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) Six Months Ended June 30, -------------------- 1995 1994 ---- ---- CASH FLOWS FROM (USED IN) OPERATING ACTIVITIES: Net earnings . . . . . . . . . . . . . . . . . . . . . $ 9,216 3,680 Adjustments to reconcile net earnings to net cash from operating activities: Depreciation, depletion and amortization . . . . . . 23,327 14,395 Loss on extinguishment of debt. . . . . . . . . . . . - 4,752 Loss (gain) on sales of assets . . . . . . . . . . . 2 ( 2,341) Amortization of deferred charges and other, net . . . 786 792 Changes in assets and liabilities: Receivables . . . . . . . . . . . . . . . . . . . . 8,917 2,767 Receivable from Tennessee Gas Pipeline Company . . . (17,647) ( 9,751) Inventories . . . . . . . . . . . . . . . . . . . . 6,146 12,483 Investment in Tesoro Bolivia Petroleum Company . . . ( 2,953) ( 2,127) Other assets . . . . . . . . . . . . . . . . . . . . ( 4,351) ( 1,824) Accounts payable and other current liabilities . . . 5,855 22,103 Obligation payments to State of Alaska . . . . . . . ( 1,316) ( 1,320) Other liabilities and obligations . . . . . . . . . 1,461 1,442 --------- --------- Net cash from operating activities . . . . . . . . 29,443 45,051 --------- --------- CASH FLOWS FROM (USED IN) INVESTING ACTIVITIES: Capital expenditures . . . . . . . . . . . . . . . . . (32,758) (44,911) Acquisition of Kenai Pipe Line Company . . . . . . . . ( 3,000) - Proceeds from sales of assets. . . . . . . . . . . . . 1,015 2,247 Sales of short-term investments . . . . . . . . . . . - 5,952 Purchases of short-term investments. . . . . . . . . . - ( 1,974) Other. . . . . . . . . . . . . . . . . . . . . . . . . ( 172) 3,850 --------- --------- Net cash used in investing activities . . . . . . (34,915) (34,836) --------- --------- CASH FLOWS FROM (USED IN) FINANCING ACTIVITIES: Repayments, net of borrowings of $159,500 in 1995 and $5,000 in 1994, under revolving credit facilities - ( 5,000) Payments of long-term debt . . . . . . . . . . . . . . ( 1,200) ( 855) Proceeds from issuance of common stock, net. . . . . . - 56,967 Repurchase of common and preferred stock . . . . . . . - (52,948) Dividends on preferred stocks. . . . . . . . . . . . . - ( 1,684) Costs of recapitalization and other. . . . . . . . . . 10 ( 1,985) --------- --------- Net cash used in financing activities. . . . . . . ( 1,190) ( 5,505) --------- --------- INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS . . . . ( 6,662) 4,710 CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD . . . . 14,018 36,596 --------- --------- CASH AND CASH EQUIVALENTS AT END OF PERIOD . . . . . . . $ 7,356 41,306 ========= ========= SUPPLEMENTAL CASH FLOW DISCLOSURES: Interest paid, net of $240 capitalized in 1994 . . . . $ 9,013 9,229 ========= ========= Income taxes paid . . . . . . . . . . . . . . . . . . $ 2,389 2,756 ========= ========= 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) (1) Basis of Presentation The interim condensed consolidated financial statements are unaudited but, in the opinion of management, incorporate all adjustments necessary for a fair presentation of results for such periods. Such adjustments are of a normal recurring nature. The preparation of these condensed consolidated financial statements required the use of management's best estimates and judgment. The results of operations for any interim period are not necessarily indicative of results for the full year. 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, 1994. (2) Acquisition In March 1995, the Company acquired all of the outstanding stock of Kenai Pipe Line Company ("KPL") for $3 million. The Company transports its crude oil and a substantial portion of its refined products utilizing KPL's pipeline and marine terminal facilities in Kenai, Alaska. (3) Revolving Credit Facility Under the terms of its Revolving Credit Facility, as amended, the Company is required to maintain specified levels of working capital, tangible net worth, consolidated cash flow and refinery cash flow, as defined. Among other matters, the Revolving Credit Facility contains certain restrictions with respect to (i) capital expenditures, (ii) incurrence of additional indebtedness, and (iii) dividends on capital stock. The Revolving Credit Facility contains other covenants customary in credit arrangements of this kind. At June 30, 1995, the Company did not satisfy the refinery cash flow requirement, which required the Company to obtain a waiver to the Revolving Credit Facility. Compliance with certain financial covenants under the Revolving Credit Facility is primarily dependent on the Company's maintenance of specified levels of cash flows from operations, capital expenditures, levels of borrowings and the value of the Company's domestic oil and gas reserves. Based on current depressed refinery margins, the Company will be required to seek a waiver or an amendment to the Revolving Credit Facility from its banks with respect to its refinery cash flow requirement for the remainder of 1995. The Company believes it will be able to negotiate terms and conditions with its banks under the Revolving Credit Facility which will allow the Company to adequately finance its operations. (4) Commitments and Contingencies Gas Purchase and Sales Contract The Company is selling a portion of the gas from its Bob West Field to Tennessee Gas Pipeline Company ("Tennessee Gas") under a Gas Purchase and Sales Agreement ("Tennessee Gas Contract") which 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 in the District Court of Bexar County, Texas, alleging that the Tennessee Gas 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. During June 1995, the Contract Price was in excess of $8.00 per Mcf, the Section 101 price was $4.94 per Mcf and the average spot market price was $1.56 per Mcf. 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. On appeal by Tennessee Gas, the Court of Appeals for the Fourth Supreme Judicial District of Texas affirmed the validity of the Tennessee Gas Contract as to the Company's properties and held that the price payable by Tennessee Gas for the gas was the Contract Price. The Court of Appeals remanded the case to the trial court based on its determination (i) that the Tennessee Gas Contract was an output contract and (ii) that a fact issue existed as to whether the increases in the volumes of gas tendered to Tennessee Gas under the contract were made in bad faith or were unreasonably disproportionate to prior tenders. The Company sought review of the appellate court ruling on the output contract issue in the Supreme Court of Texas. Tennessee Gas also sought review of the appellate court ruling denying the 6 remaining Tennessee Gas claims in the Supreme Court of Texas. The appellate court decision was the first decision reported in Texas holding that a take-or-pay contract was an output contract. The Supreme Court of Texas heard arguments in December 1994, regarding the output contract issue and certain of the issues raised by Tennessee Gas. On August 1, 1995, the Supreme Court of Texas, in a divided opinion, affirmed the decision of the appellate court on all issues, determined that the Tennessee Gas Contract was an output contract and remanded the case to the trial court for determination of whether gas volumes tendered by the Company to Tennessee Gas were tendered in good faith and were not unreasonably disproportionate to any normal or otherwise comparable prior output or stated estimates in accordance with Section 2.306 of the UCC. In addition, the Supreme Court affirmed that the price under the Tennessee Gas Contract is the Contract Price. The Company intends to file a motion for rehearing before the Texas Supreme Court on the issue of whether the Tennessee Gas Contract is an output contract. Through June 30, 1995, under the Tennessee Gas Contract, the Company recognized cumulative revenues in excess of spot market prices through September 17, 1994, and in excess of a nonrefundable $3.00 per Mcf bond price subsequent to September 17, 1994, totaling $86.6 million of which $33.9 million is included in receivables. The Company and its outside counsel are evaluating the impact of various aspects of the Supreme Court decision. The Company believes that, if this issue is tried, the gas volumes tendered to Tennessee Gas will be found to have been in good faith and otherwise in accordance with the requirements of the UCC. However, there can be no assurance as to the ultimate outcome at trial. An adverse outcome of this litigation could require the Company to reverse some or all of the incremental revenue and repay Tennessee Gas all or a portion of $52.5 million for amounts received above spot market prices, plus interest if awarded by the court. In September 1994, the court ordered that, effective until August 1, 1995, Tennessee Gas (i) take at least its entire monthly take-or-pay obligation under the Tennessee Gas Contract, (ii) pay for gas at $3.00 per Mmbtu, which approximates $3.00 per Mcf ("Bond Price"), and (iii) post a $120 million bond with the court representing an amount which, together with anticipated sales of natural gas to Tennessee Gas at the Bond Price, will equal the anticipated value of the Tennessee Gas Contract during this interim period. The Bond Price is nonrefundable by the Company, and the Company retains the right to receive the full Contract Price for all gas sold to Tennessee Gas. On August 10, 1995, a hearing was held before the trial court regarding the extension of the Tennessee Gas bond. The parties agreed and the court ordered that Tennessee Gas, for the period August 14, 1995, until the earlier of October 16, 1995, or the date the Supreme Court issues its rulings on motions for rehearing, (i) continue to take at least its entire take-or-pay volume obligation, (ii) pay for gas at a price of $3.00 per Mmbtu subject to potential refund of amounts in excess of market prices if Tennessee Gas should ultimately prevail in the litigation, and (iii) post a $25 million bond in addition to the $120 million bond presently in place. Tennessee Gas had previously agreed to pay the Company the nonrefundable Bond Price until August 14, 1995. 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 in 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 this site is expected to be limited based upon the number of companies and the volumes of waste involved. The Company believes that its liability at this site is expected to be limited based upon the payment by the Company of a de minimis settlement amount of $2,500 at a similar site in Louisiana. 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. In addition, the Company is holding discussions with the Department of Justice ("DOJ") concerning the assessment of penalties with respect to certain alleged violations of regulations promulgated under the Clean Air Act as discussed below. In March 1992, the Company received a Compliance Order and Notice of Violation from the Environmental Protection Agency ("EPA") alleging violations by the Company of the New Source Performance Standards under the Clean Air Act at its Alaska refinery. These allegations include failure to install, maintain and operate 7 monitoring equipment over a period of approximately six years, failure to perform accuracy testing on monitoring equipment, and failure to install certain pollution control equipment. From March 1992 to July 1993, the EPA and the Company exchanged information relevant to these allegations. In addition, the EPA conducted an environmental audit of the Company's refinery in May 1992. As a result of this audit, the EPA is also alleging violation of certain regulations related to asbestos materials. In October 1993, the EPA referred these matters to the DOJ. The DOJ contacted the Company to begin negotiating a resolution of these matters. The DOJ has indicated that it is willing to enter into a judicial consent decree with the Company and that this decree would include a penalty assessment. Negotiations on the penalty are in progress. The DOJ has currently proposed a penalty assessment of approximately $2.3 million. The Company is continuing to negotiate with the DOJ but cannot predict the ultimate outcome of the negotiations. At June 30, 1995, the Company's accruals for environmental matters, including the alleged violations of the Clean Air Act, amounted to $11.3 million. Also included in this amount is an approximate $4 million noncurrent liability for remediation of the KPL properties, which liability 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 be required to make capital improvements in 1995 of approximately $2 million, primarily for the removal and upgrading of underground storage tanks, and approximately $8 million during 1996 for the installation of dike liners required under Alaska environmental regulations. 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. Crude Oil Purchase Contract The Company's contract with the State of Alaska ("State") for the purchase of royalty crude oil expires on December 31, 1995. In May 1995, the Company renegotiated a new three-year contract with the State for the period January 1, 1996 through December 31, 1998. The new contract provides for the purchase of approximately 40,000 barrels per day of Alaska North Slope ("ANS") royalty crude oil, the primary feedstock for the Company's refinery, and is priced at the weighted average price reported to the State by a major North Slope producer for ANS crude oil as valued at Pump Station No. 1 on the Trans Alaska Pipeline System. Under this agreement, the Company is required to utilize in its refinery operations volumes equal to at least 80% of the ANS crude oil to be purchased from the State. This contract contains provisions that allow the Company to temporarily or permanently reduce its purchase obligations. Other In February 1995, a lawsuit was filed in the U.S. District Court for the Southern District of Texas, McAllen Division, by the Heirs of H.P. Guerra, Deceased ("Plaintiffs") against the United States and Tesoro and other working and overriding royalty interest owners to recover the oil and gas mineral estate under 2,706.34 acres situated in Starr County, Texas. The oil and gas mineral estate sought to be recovered underlies lands taken by the United States in connection with the construction of the Falcon Dam and Reservoir. In their lawsuit, the Plaintiffs allege that the original taking by the United States in 1948 was unlawful and void and the refusal of the United States to revest the mineral estate to H.P. Guerra or his heirs was arbitrary and capricious and unconstitutional. Plaintiffs seek (i) restoration of their oil and gas estate; (ii) restitution of all proceeds realized from the sale of oil and gas from their mineral estate, plus interest on the value thereof; and (iii) cancellation of all oil and gas leases issued by the United States to Tesoro and the other working interest owners covering their mineral estate. The lawsuit covers a significant portion of the mineral estate in the Bob West Field; however, none of the acreage covered is dedicated to the Tennessee Gas Contract. The Company cannot predict the ultimate resolution of this matter but, based upon advice from outside legal counsel, believes the lawsuit is without merit. In July 1994, a former customer of the Company ("Customer"), filed suit against the Company in the United States District Court for the District of New Mexico for a refund in the amount of approximately $1.2 million, plus 8 interest of approximately $4.4 million and attorney's fees, related to a gasoline purchase from the Company in 1979. The Customer also alleges entitlement to treble damages and punitive damages in the aggregate amount of $16.8 million. The refund claim is based on allegations that the Company renegotiated the acquisition price of gasoline sold to the Customer and failed to pass on the benefit of the renegotiated price to the Customer in violation of Department of Energy price and allocation controls then in effect. In May 1995, the court issued an order granting the Company's motion for summary judgment and dismissed with prejudice all the claims in the Customer's complaint. In June 1995, the Customer filed a notice of appeal with the U.S. Court of Appeals for the Federal Circuit. The Company cannot predict the ultimate resolution of this matter but believes the claim is without merit. (5) Oil and Gas Producing Activities The Company has entered into a price swap with another company for approximately 8.25 Bcf of its anticipated U.S. natural gas production for the period April 1, 1995 through December 31, 1995 at a fixed price of approximately $1.56 per Mcf. For the three months and six months ended June 30, 1995, the Company's average spot market sales prices, which included the effect of this price swap, were $1.52 and $1.48 per Mcf, respectively. The Company's mid-year reserve report, prepared by the Company's independent petroleum consultants, estimates that, during the first half of 1995, Tesoro's proved domestic natural gas reserves increased 53%, from 129 Bcf of natural gas at December 31, 1994, to 198 Bcf at June 30, 1995, after net production during this period of approximately 23 Bcf. As a result, this change in estimate reduced depreciation, depletion and amortization expense and increased net earnings for the three months ended June 30, 1995 by approximately $4 million ($.16 per share). 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, reduce the asset concentration associated with the Bob West Field and lower future capital commitments. In these regards, the Company is evaluating offers to sell or exchange approximately 40% of its total proved domestic natural gas reserves in the Bob West Field. The proved reserves for which offers are being evaluated are located in the C, D, E and F units of the Bob West Field and do not include acreage covered by the Tennessee Gas Contract (see Note 4). No offer for a sale or exchange has been accepted and there is no assurance that a sale or exchange will be consummated. The Company is uncertain as to the impact of these initiatives upon its capital resources and liquidity, if any. 9 Item 2. TESORO PETROLEUM CORPORATION AND SUBSIDIARIES MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS RESULTS OF OPERATIONS - THREE AND SIX MONTHS ENDED JUNE 30, 1995 COMPARED WITH THREE AND SIX MONTHS ENDED JUNE 30, 1994 A consolidated summary of the Company's operations for the three and six months ended June 30, 1995 and 1994 is presented below (in millions except per share amounts):
Three Months Ended Six Months Ended June 30, June 30, ------------------ ---------------- 1995 1994 1995 1994 ---- ---- ---- ---- Summary of Operations Segment Operating Profit (Loss): Refining and Marketing . . . . . . . . . . . . . . . $ ( 2.7) ( 5.0) ( 7.3) 1.4 Exploration and Production - United States . . . . . 20.0 14.6 36.6 25.8 Exploration and Production - Bolivia . . . . . . . . 2.3 2.5 4.0 4.4 Oil Field Supply and Distribution. . . . . . . . . . ( .5) ( .4) ( 1.8) ( 1.6) -------- ------- ------- -------- Total Segment Operating Profit. . . . . . . . . . . 19.1 11.7 31.5 30.0 Corporate and Unallocated Costs: Interest expense . . . . . . . . . . . . . . . . . . 5.4 4.6 10.7 9.5 Interest income. . . . . . . . . . . . . . . . . . . ( .2) ( .5) ( .4) ( 1.0) General and administrative expenses. . . . . . . . . 4.2 3.4 8.0 7.0 Other. . . . . . . . . . . . . . . . . . . . . . . . .9 2.3 1.9 3.8 -------- ------- ------- -------- Earnings Before Income Taxes and Extraordinary Loss . 8.8 1.9 11.3 10.7 Income Tax Provision . . . . . . . . . . . . . . . . . 1.4 .6 2.1 2.2 -------- ------- ------- -------- Earnings Before Extraordinary Loss . . . . . . . . . . 7.4 1.3 9.2 8.5 Extraordinary Loss on Extinguishment of Debt . . . . . - - - ( 4.8) -------- ------- ------- -------- Net Earnings . . . . . . . . . . . . . . . . . . . . . 7.4 1.3 9.2 3.7 Dividend Requirements on Preferred Stocks. . . . . . . - .8 - 2.7 -------- ------- ------- -------- Net Earnings Applicable to Common Stock. . . . . . . . $ 7.4 .5 9.2 1.0 ======== ======= ======= ======== Earnings (Loss) per Primary and Fully Diluted Share: Earnings Before Extraordinary Loss . . . . . . . . . $ .30 .02 .37 .27 Extraordinary Loss on Extinguishment of Debt . . . . - - - ( .22) -------- ------- ------- -------- Net Earnings . . . . . . . . . . . . . . . . . . . . $ .30 .02 .37 .05 ======== ======= ======= ======== Operating profit (loss) represents pretax earnings (loss) before certain corporate expenses, interest income and interest expense. Anti-dilutive.
Net earnings applicable to common stock of $7.4 million, or $.30 per share, for the three months ended June 30, 1995 ("1995 quarter") compare with net earnings applicable to common stock of $.5 million, or $.02 per share, for the three months ended June 30, 1994 ("1994 quarter"). Net earnings for the 1995 quarter included an aggregate benefit of approximately $4 million, or $.16 per share, due to additions to the Company's proved domestic natural gas reserves which reduced the domestic depletion rate to $.62 per Mcf, as compared to $.90 per Mcf for the 1995 first quarter. Net earnings for the 1994 quarter were reduced by $.8 million of dividend requirements on preferred stock. When comparing the 1995 quarter to the 1994 quarter, the increase in net earnings was primarily due to the successful drilling program and increased natural gas production from the Company's exploration and production operations in South Texas partially offset by lower spot market prices for sales of natural gas. In addition, during the 1995 quarter, the Company narrowed its operating loss from the refining and marketing segment to $2.7 million. Net earnings applicable to common stock of $9.2 million, or $.37 per share, for the six months ended June 30, 1995 ("1995 period") compare to net earnings applicable to common stock of $1.0 million, or $.05 per share, for the six months ended June 30, 1994 ("1994 period"). The comparability between these two periods was impacted by certain significant transactions. As discussed above, the 1995 period included an aggregate benefit of approximately $4 million resulting from a reduced depletion rate. Net earnings for the 1994 period were reduced by $2.7 million of dividend requirements on preferred stock. Also included in the 1994 period was a noncash extraordinary loss of $4.8 million, or $.22 per share, attributable to the early extinguishment of debt in connection with a recapitalization in 1994. Earnings before the extraordinary loss were $8.5 million, or $.27 per share, for the 1994 period. The 1994 period was favorably impacted by a gain of $2.4 million, or $.11 per share, from the sale of assets. Excluding these significant transactions for both periods, the decrease in net earnings was 10 largely due to lower operating results from the Company's refining and marketing segment and lower spot market prices for sales of natural gas, partially offset by increased natural gas production from the Company's exploration and production operations in South Texas. 11
Refining and Marketing Three Months Ended Six Months Ended June 30, June 30, ------------------ ---------------- 1995 1994 1995 1994 ---- ---- ---- ---- (Dollars in millions except per barrel amounts) Gross Operating Revenues: Refined products . . . . . . . . . . . . . . . . . $ 169.7 134.8 323.3 254.1 Other, primarily crude oil resales and merchandise 37.8 31.4 69.3 62.4 --------- --------- --------- --------- Gross Operating Revenues. . . . . . . . . . . . . $ 207.5 166.2 392.6 316.5 ========= ========= ========= ========= Operating Profit (Loss): Gross margin - refined products. . . . . . . . . . $ 18.9 15.2 34.0 38.7 Gross margin - other . . . . . . . . . . . . . . . 3.1 3.4 5.6 6.0 --------- --------- --------- --------- Gross margin. . . . . . . . . . . . . . . . . . . 22.0 18.6 39.6 44.7 Operating expenses . . . . . . . . . . . . . . . . 21.5 20.7 40.7 40.6 Depreciation and amortization. . . . . . . . . . . 3.0 2.6 6.0 5.2 Other, including gain on asset sales . . . . . . . .2 .3 .2 ( 2.5) --------- --------- --------- --------- Operating Profit (Loss) . . . . . . . . . . . . . $ ( 2.7) ( 5.0) ( 7.3) 1.4 ========= ========= ========= ========= Capital Expenditures . . . . . . . . . . . . . . . . $ 3.0 8.2 5.3 14.3 ========= ========= ========= ========= Refining and Marketing - Total Product Sales (average daily barrels): Gasoline . . . . . . . . . . . . . . . . . . . . . 26,996 21,596 25,172 22,080 Middle distillates . . . . . . . . . . . . . . . . 35,174 32,043 36,688 29,437 Heavy oils and residual product. . . . . . . . . . 16,103 13,070 14,966 14,748 --------- --------- --------- --------- Total Product Sales . . . . . . . . . . . . . . . 78,273 66,709 76,826 66,265 ========= ========= ========= ========= Refining and Marketing - Product Sales Prices ($/barrel): Gasoline . . . . . . . . . . . . . . . . . . . . . $ 28.76 27.01 27.87 25.44 Middle distillates . . . . . . . . . . . . . . . . $ 24.72 23.48 24.18 23.85 Heavy oils and residual product. . . . . . . . . . $ 13.80 11.14 13.27 9.52 Refining and Marketing - Gross Margins on Total Product Sales ($/barrel): Average sales price. . . . . . . . . . . . . . . . $ 23.87 22.20 23.27 21.19 Average cost of sales. . . . . . . . . . . . . . . 21.20 19.71 20.82 17.96 --------- --------- --------- --------- Gross margin . . . . . . . . . . . . . . . . . . . $ 2.67 2.49 2.45 3.23 ========= ========= ========= ========= Refinery Operations - Throughput (average daily barrels) . . . . . . . . . . . . . 47,971 42,651 46,778 43,978 ========= ========= ========= ========= Refinery Operations - Production (average daily barrels): Gasoline . . . . . . . . . . . . . . . . . . . . . 13,779 10,896 13,277 11,391 Middle distillates . . . . . . . . . . . . . . . . 19,426 18,014 19,556 17,975 Heavy oils and residual product. . . . . . . . . . 14,347 13,295 13,391 14,345 Refinery fuel. . . . . . . . . . . . . . . . . . . 1,969 1,929 1,998 1,834 --------- --------- --------- --------- Total Refinery Production . . . . . . . . . . . . 49,521 44,134 48,222 45,545 ========= ========= ========= ========= Refinery Operations - Product Spread ($/barrel): Yield value of products produced - Gasoline . . . . . . . . . . . . . . . . . . . . $ 26.49 25.42 25.30 23.99 Middle distillates . . . . . . . . . . . . . . . $ 24.16 23.19 23.67 23.28 Heavy oils and residual product. . . . . . . . . $ 9.77 8.77 9.48 6.87 Average yield value of products produced . . . . . $ 20.70 19.48 20.22 18.39 Cost of raw materials. . . . . . . . . . . . . . . 17.87 16.34 17.33 14.28 --------- --------- --------- --------- Product Spread. . . . . . . . . . . . . . . . . . $ 2.83 3.14 2.89 4.11 ========= ========= ========= ========= 12 Total products sold 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 28,700 and 22,000 average daily barrels for the 1995 and 1994 quarters, respectively, and 26,900 and 20,800 average daily barrels for the 1995 and 1994 periods, respectively. The product spread presented above represents the excess of yield value of the products produced at the refinery over the cost of the raw materials used to manufacture such products.
Three Months Ended June 30, 1995 Compared With Three Months Ended June 30, 1994. While the refining industry market conditions strengthened as the 1995 quarter advanced, margins on the Company's sales of refined products remained weak. The Company's average feedstock costs increased to $17.87 per barrel for the 1995 quarter compared with $16.34 per barrel for the 1994 quarter, while the average yield value of the Company's refinery production increased to $20.70 per barrel for the 1995 quarter from $19.48 for the prior year quarter. As a result, the Company's refinery spread remained depressed in the 1995 quarter and will continue to be depressed as long as the cost of Alaska North Slope ("ANS") crude oil remains high relative to the price received for the Company's sales of refined products. The start-up in December 1994 of a vacuum unit at the Company's refinery increased the yield of higher-valued products during the 1995 quarter and period and lessened the impact of these industry conditions on the Company's refinery spread. In addition, margins on sales of inventories and purchased volumes combined to improve the segment's gross margins as compared with the prior year quarter. Revenues from sales of refined products in the 1995 quarter were higher than the 1994 quarter due to higher sales prices and a 17% increase in sales volumes. In addition, to optimize the refinery's feedstock mix and in response to market conditions, the Company's resales of crude oil increased by $7.0 million. Costs of sales, likewise, were higher in the 1995 quarter due to increased prices and volumes. Depreciation and amortization increased $.4 million in the 1995 quarter due to capital additions, primarily the vacuum unit, completed in late 1994. Six Months Ended June 30, 1995 Compared With Six Months Ended June 30, 1994. The Company's average feedstock costs increased to $17.33 per barrel for the 1995 period compared with $14.28 per barrel for the 1994 period, while the average yield value of the Company's refinery production increased to $20.22 per barrel for the 1995 period from $18.39 for the prior year period. Increased demand for ANS crude oil for use as a feedstock in West Coast refineries combined with an oversupply of products in Alaska and on the West Coast resulted in higher feedstock costs for the Company relative to increases in refined product sales prices. As a result, the Company's refined product margins were severely depressed in the 1995 period and will continue to be depressed as long as the cost of ANS crude oil remains high relative to the price received for the Company's sales of refined products. Revenues from sales of refined products in the 1995 period were higher than the 1994 period due to higher sales prices and a 16% increase in sales volumes. Resales of crude oil increased by $7.5 million. Costs of sales, likewise, were higher in the 1995 period due to increased prices and volumes. Depreciation and amortization increased $.8 million in the 1995 period due to capital additions, primarily the vacuum unit, completed in late 1994. Included in the 1994 period was a $2.4 million gain from the sale of assets. 13
Exploration and Production Three Months Ended Six Months Ended June 30, June 30, ------------------ ---------------- 1995 1994 1995 1994 ---- ---- ---- ---- (Dollars in millions except per unit amounts) United States: Gross operating revenues . . . . . . . . . . $ 33.2 22.8 63.0 40.2 Lifting costs. . . . . . . . 5.4 3.2 10.2 5.5 Depreciation, depletion and amortization . . . . 8.1 4.7 16.7 8.5 Other . . . . . . . . . . . ( .3) .3 ( .5) .4 ---------- --------- ---------- --------- Operating Profit - United States . . . . . . . 20.0 14.6 36.6 25.8 ---------- --------- ---------- --------- Bolivia: Gross operating revenues . . . . . . . . . . . . 3.2 3.3 5.8 6.1 Lifting costs. . . . . . . . . . . . . . . . . . .1 .1 .3 .3 Other . . . . . . . . . . . . . . . . . . . . . .8 .7 1.5 1.4 ---------- --------- ---------- --------- Operating Profit - Bolivia. . . . . . . . . . . 2.3 2.5 4.0 4.4 ---------- --------- ---------- --------- Total Operating Profit - Exploration and Production . . . . . . . . . . . . . . . . . $ 22.3 17.1 40.6 30.2 ========== ========= ========== ========= United States: Capital expenditures . . . . . . . . . . . . . . $ 13.0 17.7 27.0 29.4 ========== ========= ========== ========= Net natural gas production (average daily Mcf) - Spot market and other . . . . . . . . . . . . . 121,811 51,003 101,157 41,960 Tennessee Gas Contract. . . . . . . . . . . 20,401 19,902 22,988 18,052 ---------- --------- ---------- --------- Total production . . . . . . . . . . . . . . . 142,212 70,905 124,145 60,012 ========== ========= ========== ========= Average natural gas sales price per Mcf -. . . . Spot market . . . . . . . . . . . . . . . . . . $ 1.52 1.74 1.48 1.84 Tennessee Gas Contract. . . . . . . . . . . $ 8.43 7.96 8.37 7.89 Average . . . . . . . . . . . . . . . . . . . . $ 2.51 3.49 2.75 3.66 Average lifting costs per Mcf. . . . . . . . $ .42 .49 .46 .51 Depletion per Mcf. . . . . . . . . . . . . . . . $ .62 .73 .74 .78 Bolivia: Net natural gas production (average daily Mcf) . 19,715 22,050 18,321 20,601 Average natural gas sales price per Mcf. . . . . $ 1.30 1.20 1.28 1.21 Net crude oil (condensate) production (average daily barrels) . . . . . . . . . . . . 610 735 581 699 Average crude oil price per barrel . . . . . . . $ 15.69 13.65 15.22 12.63 Average lifting costs per net equivalent Mcf . . $ .09 .03 .09 .07 The Company is involved in litigation with Tennessee Gas relating to a natural gas sales contract. See "Capital Resources and Liquidity--Tennessee Gas Contract," "Legal Proceedings--Tennessee Gas Contract" and Note 4 of Notes to Condensed Consolidated Financial Statements. Average lifting costs for the Company's U.S. operations include such items as severance taxes, property taxes, insurance, materials and supplies and transportation of natural gas production through Company-owned pipelines. Since severance taxes are based upon sales prices of natural gas, the average lifting costs presented above include the impact of above-market prices for sales under the Tennessee Gas Contract. Lifting costs per Mcf of natural gas sold in the spot market were approximately $.36 and $.40 for the 1995 and 1994 quarters, respectively, and approximately $.38 and $.42 for the 1995 and 1994 periods, respectively.
14 United States Three Months Ended June 30, 1995 Compared With Three Months Ended June 30, 1994. The improvement in the 1995 quarter was attributable to the continued development of the Bob West Field in South Texas. This success was indicated in the Company's mid-year reserve report, prepared by the Company's independent petroleum consultants, which reflected a 53% increase in the Company's domestic proved reserves of natural gas from 129 Bcf of natural gas at December 31, 1994, to 198 Bcf at June 30, 1995, after net production during this period of approximately 23 Bcf. The pre-tax net present value of the Company's proved reserves rose 10% to $198 million from $179 million at year-end 1994. Results for the 1995 quarter benefited by nearly $4 million in the aggregate due to the additions to proved reserves which reduced the domestic depletion rate to $.62 per Mcf, as compared with $.90 per Mcf for the 1995 first quarter. The number of producing wells in South Texas in which the Company has a working interest increased to 58 wells at the end of the 1995 quarter, compared with 38 wells at the end of the 1994 quarter. The Company's 1995 quarter results included a 101% increase in U.S. natural gas production with a $10.4 million increase in revenues. Revenues for natural gas sales during the 1995 quarter, however, were adversely affected by a 28% decline in the Company's weighted average sales price, which included a 13% drop in average spot market prices. Total lifting costs and depreciation, depletion and amortization were higher in the 1995 quarter, compared with the 1994 quarter, due to the increased production level, but declined on a per Mcf basis. Tennessee Gas may elect, and from time to time has elected, not to take gas under the Tennessee Gas Contract. The Company recognizes revenues under the Tennessee Gas Contract based on the quantity of natural gas actually taken by Tennessee Gas. While Tennessee Gas has the right to elect not to take gas during any contract year, this right is subject to an obligation to pay within 60 days after the end of such contract year for gas not taken. The contract year ends on January 31 of each year. Although the failure to take gas could adversely affect the Company's income and cash flows from operating activities within a contract year, the Company should recover reduced cash flows shortly after the end of the contract year under the take-or-pay provisions of the Tennessee Gas Contract, subject to the provisions of a bond posted by Tennessee Gas which is discussed in "Capital Resources and Liquidity--Tennessee Gas Contract," "Legal Proceedings--Tennessee Gas Contract" and Note 4 of Notes to Condensed Consolidated Financial Statements. The Company has entered into a price swap with another company for approximately 8.25 Bcf of its anticipated U.S. natural gas production for the period April 1, 1995 through December 31, 1995 at a fixed price of approximately $1.56 per Mcf. For the three months and six months ended June 30, 1995, the Company's average spot market sales prices, which included the effect of this price swap, were $1.52 and $1.48 per Mcf, respectively. Six Months Ended June 30, 1995 Compared With Six Months Ended June 30, 1994. Results for the 1995 period included a 107% increase in U.S. natural gas production with a $22.8 million increase in revenues. Revenues for natural gas sales during the 1995 period, however, were adversely affected by a 25% decline in the Company's weighted average sales price, which included a 20% drop in average spot market prices. In response to the depressed spot market prices, during the first quarter of the 1995 period the Company and one of its partners initiated a voluntary reduction of natural gas production sold in the spot market. The Company's share of this reduction was estimated to be approximately 30 Mmcf per day. In April 1995, the Company's U.S. natural gas production levels resumed at higher rates. The Company may elect to curtail natural gas production in the future, depending upon market conditions. Total lifting costs and depreciation, depletion and amortization were higher in the 1995 period compared with the 1994 period due to the increased production level, but declined on a per Mcf basis. See discussion above for information relating to additions to proved reserves and a price swap contract. Bolivia Three Months Ended June 30, 1995 Compared With Three Months Ended June 30, 1994. Operating results from the Company's Bolivian operations decreased by $.2 million during the 1995 quarter primarily due to an 11% decline in average daily natural gas production, partially offset by an 8% increase in the average natural gas sales price. During the 1994 quarter, the Company benefited from higher levels of production due to the inability of another producer to satisfy gas supply requirements. Also offsetting the decrease in production was a $2.04 per barrel increase in the average price of condensate production. The Company's Bolivian natural gas production is sold to Yacimientos Petroliferos Fiscales Bolivianos ("YPFB"), which in turn sells the natural gas to 15 Yacimientos Petroliferos Fiscales, S.A. ("YPF"), a publicly-held company based in Argentina. During 1994, the contract between YPFB and YPF was extended through March 31, 1997, maintaining approximately the same volumes as the previous contract. Currently, the Company is selling its natural gas production to YPFB based on the volume and pricing terms in the contract between YPFB and YPF. Six Months Ended June 30, 1995 Compared With Six Months Ended June 30, 1994. Operating results from the Company's Bolivian operations decreased by $.4 million during the 1995 period, primarily due to an 11% decrease in production of natural gas, partially offset by a 6% increase in natural gas prices. As discussed above, the 1994 period benefited from higher production levels due to the inability of another producer to satisfy gas supply requirements. Also offsetting the decrease in production was a $2.59 per barrel increase in the average price of condensate production. See discussion above for information relating to the Company's contract with YPFB regarding sales of natural gas production.
Oil Field Supply and Distribution Three Months Ended Six Months Ended June 30, June 30, ------------------ ---------------- 1995 1994 1995 1994 ---- ---- ---- ---- (Dollars in millions) Gross Operating Revenues . . . . . . . . . . . $ 21.2 18.3 38.4 36.9 Costs of Sales . . . . . . . . . . . . . . . . 18.3 15.8 33.4 31.7 -------- -------- -------- -------- Gross Margin . . . . . . . . . . . . . . . . 2.9 2.5 5.0 5.2 Operating Expenses and Other . . . . . . . . . 3.3 2.8 6.6 6.6 Depreciation and Amortization. . . . . . . . . .1 .1 .2 .2 -------- -------- -------- -------- Operating Loss . . . . . . . . . . . . . . . $ ( .5) ( .4) ( 1.8) ( 1.6) ======== ======== ======== ======== Refined Product Sales (average daily barrels) 8,419 7,486 7,679 7,455 ======== ======== ======== ========
Three Months Ended June 30, 1995 Compared With Three Months Ended June 30, 1994. Although sales volumes of refined products increased over 12%, gross margins remained tight and were substantially offset by increased operating costs resulting in a moderate increase in operating loss. Six Months Ended June 30, 1995 Compared With Six Months Ended June 30, 1994. Although refined product sales volumes increased during the 1995 period, gross margin decreased primarily as a result of lower merchandise margins due to continued strong competition in an oversupplied market. Included in operating expenses in the 1994 period were charges of $1.2 million for discontinuing the Company's environmental products marketing operations. Interest Expense The increases of $.8 million and $1.2 million in interest expense during the 1995 quarter and period, respectively, were primarily due to interest on the vacuum unit financing and cash borrowings under the Revolving Credit Facility during 1995 and to capitalized interest in 1994. General and Administrative Expense The increases of $.8 million and $1.0 million in general and administrative expense during the 1995 quarter and period, respectively, were primarily due to higher employee costs. Other Expense The decreases of $1.4 million and $1.9 million in other expense during the 1995 quarter and period, respectively, were largely attributable to lower environmental expenses related to former operations. 16 Income Taxes Income taxes of $1.4 million in the 1995 quarter compare with $.6 million in the 1994 quarter. The increase was primarily due to higher state income taxes on the Company's increased taxable 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 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, major 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. The carrying value of oil and 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 The Company operates in an environment where markets for crude oil, natural gas and refined products historically have been volatile and are likely to continue to be volatile in the future. The Company's liquidity and capital resources are significantly 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 economic conditions. The Company cannot predict the future markets and prices for its natural gas or refined products and the resulting future impact on earnings and cash flows. The Company's operations have been adversely affected by depressed market conditions and will continue to be adversely affected for so long as these market conditions exist. The Company's future capital expenditures, borrowings under its credit arrangements and other sources of capital will be affected by these conditions. 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, reduce the asset concentration associated with the Bob West Field and lower future capital commitments. In these regards, the Company is evaluating offers to sell or exchange approximately 40% of its total proved domestic natural gas reserves in the Bob West Field. The proved reserves for which offers are being evaluated are located in the C, D, E and F units of the Bob West Field and do not include acreage covered by the Tennessee Gas Contract (see Note 4 of Notes to Condensed Consolidated Financial Statements). No offer for a sale or exchange has been accepted and there is no assurance that a sale or exchange will be consummated. The Company is uncertain as to the impact of these initiatives upon its capital resources and liquidity, if any. In July 1995, the Company completed the Longoria #1 exploratory well in Webb County of South Texas, marking the discovery of a new natural gas field. This well tested at an initial gross rate of 3.5 Mmcf per day of natural gas. Tesoro serves as operator of this well with a 45% working interest and a 33.33% net revenue interest. The discovery was made on Tesoro's 2,200-acre S. Guerra prospect. Initial estimates are that this new field is analogous to the Guerra field (four miles to the northeast), which remains under development but has already produced a cumulative 125 Bcf of natural gas. Additional tests currently are being conducted on the Longoria #1 to determine the producing zone's permeability and the need to fracture the pay sands to stimulate higher production rates. The well will remain shut-in until such tests are completed and the well can be tied in to one of several pipelines in the area. The Company is uncertain as to the future impact of this discovery upon its capital resources and liquidity. 17 Credit Arrangements The Company has financing and credit arrangements under a three-year, $125 million corporate Revolving Credit Facility dated April 20, 1994 with a consortium of ten banks. The Revolving Credit Facility, which is subject to a borrowing base, provides for (i) the issuance of letters of credit up to the full amount of the borrowing base and (ii) cash borrowings up to the amount of the borrowing base attributable to domestic oil and gas reserves. Outstanding obligations under the Revolving 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. At June 30, 1995, the borrowing base of approximately $111 million included a domestic oil and gas reserve component of $45 million. At June 30, 1995, the Company had outstanding letters of credit under the Revolving Credit Facility of approximately $51 million with no cash borrowings outstanding. The Company has borrowed from time to time under this facility during 1995 on a short-term basis to finance working capital requirements and capital expenditures. Under the terms of the Revolving Credit Facility, as amended, the Company is required to maintain specified levels of working capital, tangible net worth, consolidated cash flow and refinery cash flow, as defined. Among other matters, the Revolving Credit Facility contains certain restrictions with respect to (i) capital expenditures, (ii) incurrence of additional indebtedness, and (iii) dividends on capital stock. The Revolving Credit Facility contains other covenants customary in credit arrangements of this kind. At June 30, 1995, the Company did not satisfy the refinery cash flow requirement which required the Company to obtain a waiver to the Revolving Credit Facility. Compliance with certain financial covenants under the Revolving Credit Facility is primarily dependent on the Company's maintenance of specified levels of cash flows from operations, capital expenditures, levels of borrowings and the value of the Company's domestic oil and gas reserves. Based on current depressed refinery margins, the Company will be required to seek a waiver or an amendment to the Revolving Credit Facility from its banks with respect to its refinery cash flow requirement for the remainder of 1995. The Company believes it will be able to negotiate terms and conditions with its banks under the Revolving Credit Facility which will allow the Company to adequately finance its operations. See Note 3 of Notes to Condensed Consolidated Financial Statements. Debt Obligations The Company's funded debt obligations as of June 30, 1995 included approximately $64.6 million principal amount of 12-3/4% Subordinated Debentures ("Subordinated Debentures"), which bear interest at 12-3/4% per annum and require sinking fund payments sufficient to annually retire $11.25 million principal amount of Subordinated Debentures. As part of a recapitalization in 1994, $44.1 million principal amount of Subordinated Debentures was tendered in exchange for a like principal amount of new 13% Exchange Notes ("Exchange Notes"). This exchange satisfied the 1994 sinking fund requirement and, except for $.9 million, will satisfy sinking fund requirements for the Subordinated Debentures through 1997. The indenture governing the Subordinated Debentures contains certain covenants, including a restriction that prevents the current payment of cash dividends on Common Stock and currently limits the Company's ability to purchase or redeem any shares of its capital stock. The Exchange Notes bear interest at 13% per annum, mature December 1, 2000 and have no sinking fund requirements. The limitation on dividend payments included in the indenture governing the Exchange Notes is less restrictive than the limitation imposed by the Subordinated Debentures. The Subordinated Debentures and Exchange Notes are redeemable at the option of the Company at 100% of principal amount, plus accrued interest. The Company continuously reviews financing alternatives with respect to its Subordinated Debentures and Exchange Notes. However, there can be no assurance whether or when the Company would propose a refinancing, if any. Capital Expenditures The Company has under consideration total capital expenditures for 1995 of approximately $60 million, compared with $100 million for 1994. Capital expenditures for the continued development of the Bob West Field and exploratory drilling in other areas of South Texas in 1995 are projected to be $47 million. The amount of such expenditures for exploration and production activities is dependent upon, among other factors, the price the Company receives for its natural gas production. Capital expenditures for 1995 for the refining and marketing segment are projected to be $11 million, primarily for capital improvements at the refinery and expansion of the Company's retail locations in Alaska. For the six months ended June 30, 1995, total capital expenditures amounted to $33 million, including $27 million for exploration and production and $5 million for refining and 18 marketing, which were funded through cash flows from operations, existing cash and borrowings under the Revolving Credit Facility. The Company expects to finance capital expenditures for the remainder of 1995 through a combination of cash flows from operations and borrowings under the Revolving Credit Facility. Cash Flows At June 30, 1995, the Company's net working capital totaled $83.0 million, which included cash of $7.4 million and a receivable from Tennessee Gas of $35.4 million. For information on litigation related to a natural gas sales contract and the related impact on the Company's cash flows from operations, see "Tennessee Gas Contract" below and Note 4 of Notes to Condensed Consolidated Financial Statements. Components of the Company's cash flows are set forth below (in millions): Six Months Ended June 30, ----------------------- 1995 1994 ------ ------ Cash Flows From (Used In): Operating Activities . . . . . . . . . . . . . . . $ 29.4 45.0 Investing Activities . . . . . . . . . . . . . . . (34.9) (34.8) Financing Activities . . . . . . . . . . . . . . . ( 1.2) ( 5.5) ------ ------ Increase (Decrease) in Cash and Cash Equivalents . . $ ( 6.7) 4.7 ====== ====== Net cash from operating activities of $29.4 million during the 1995 period compares to $45.0 million for the 1994 period. Although natural gas production from the Bob West Field increased during the 1995 period, lower cash receipts for sales of natural gas and reduced cash flows from the refining and marketing operations adversely affected the Company's cash flows from operations. Net cash used in investing activities of $34.9 million included $32.8 million of capital expenditures and $3.0 million for acquisition of the Kenai Pipe Line Company. Capital expenditures for the 1995 period included $27.0 million for the Company's exploration and production activities in South Texas, primarily for completion of nine natural gas development wells. Net cash used in financing activities of $1.2 million during the 1995 period was primarily related to payments of long-term debt. The Company's gross borrowings and repayments under its Revolving Credit Facility totaled $159.5 million during the 1995 period. Tennessee Gas Contract The Company is selling a portion of the gas from its Bob West Field to Tennessee Gas Pipeline Company ("Tennessee Gas") under a Gas Purchase and Sales Agreement ("Tennessee Gas Contract") which 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 in the District Court of Bexar County, Texas, alleging that the Tennessee Gas 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. During June 1995, the Contract Price was in excess of $8.00 per Mcf, the Section 101 price was $4.94 per Mcf and the average spot market price was $1.56 per Mcf. 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. On appeal by Tennessee Gas, the Court of Appeals for the Fourth Supreme Judicial District of Texas affirmed the validity of the Tennessee Gas Contract as to the Company's properties and held that the price payable by Tennessee Gas for the gas was the Contract Price. The Court of Appeals remanded the case to the trial court based on its determination (i) that the Tennessee Gas Contract was an output contract and (ii) that a fact issue existed as to whether the increases in the volumes of gas tendered to Tennessee Gas under the contract were made in bad faith or were unreasonably disproportionate to prior tenders. The Company sought review of the appellate court ruling on the output contract issue in the Supreme Court of Texas. Tennessee Gas also sought review of the appellate court ruling denying the remaining Tennessee Gas claims in the Supreme Court of Texas. The appellate court decision was the first decision reported in Texas holding that a take-or-pay contract was an output contract. The Supreme Court of 19 Texas heard arguments in December 1994, regarding the output contract issue and certain of the issues raised by Tennessee Gas. On August 1, 1995, the Supreme Court of Texas, in a divided opinion, affirmed the decision of the appellate court on all issues, determined that the Tennessee Gas Contract was an output contract and remanded the case to the trial court for determination of whether gas volumes tendered by the Company to Tennessee Gas were tendered in good faith and were not unreasonably disproportionate to any normal or otherwise comparable prior output or stated estimates in accordance with Section 2.306 of the UCC. In addition, the Supreme Court affirmed that the price under the Tennessee Gas Contract is the Contract Price. The Company intends to file a motion for rehearing before the Texas Supreme Court on the issue of whether the Tennessee Gas Contract is an output contract. Through June 30, 1995, under the Tennessee Gas Contract, the Company recognized cumulative revenues in excess of spot market prices through September 17, 1994, and in excess of a nonrefundable $3.00 per Mcf bond price subsequent to September 17, 1994, totaling $86.6 million of which $33.9 million is included in receivables. The Company and its outside counsel are evaluating the impact of various aspects of the Supreme Court decision. The Company believes that, if this issue is tried, the gas volumes tendered to Tennessee Gas will be found to have been in good faith and otherwise in accordance with the requirements of the UCC. However, there can be no assurance as to the ultimate outcome at trial. An adverse outcome of this litigation could require the Company to reverse some or all of the incremental revenue and repay Tennessee Gas all or a portion of $52.5 million for amounts received above spot market prices, plus interest if awarded by the court. In September 1994, the court ordered that, effective until August 1, 1995, Tennessee Gas (i) take at least its entire monthly take-or-pay obligation under the Tennessee Gas Contract, (ii) pay for gas at $3.00 per Mmbtu, which approximates $3.00 per Mcf ("Bond Price"), and (iii) post a $120 million bond with the court representing an amount which, together with anticipated sales of natural gas to Tennessee Gas at the Bond Price, will equal the anticipated value of the Tennessee Gas Contract during this interim period. The Bond Price is nonrefundable by the Company, and the Company retains the right to receive the full Contract Price for all gas sold to Tennessee Gas. On August 10, 1995 a hearing was held before the trial court regarding the extension of the Tennessee Gas bond. The parties agreed and the court ordered that Tennessee Gas, for the period August 14, 1995, until the earlier of October 16, 1995, or the date the Supreme Court issues its rulings on motions for rehearing, (i) continue to take at least its entire take-or-pay volume obligation, (ii) pay for gas at a price of $3.00 per Mmbtu subject to potential refund of amounts in excess of market prices if Tennessee Gas should ultimately prevail in the litigation, and (iii) post a $25 million bond in addition to the $120 million bond presently in place. Tennessee Gas had previously agreed to pay the Company the nonrefundable Bond Price until August 14, 1995. Environmental and Other Matters 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. In addition, the Company is holding discussions with the Department of Justice concerning the assessment of penalties with respect to certain alleged violations of the Clean Air Act. At June 30, 1995 the Company's accruals for environmental matters, including the alleged violations of the Clean Air Act, amounted to $11.3 million. Also included in this amount is an approximate $4 million noncurrent liability for remediation of the KPL properties, which liability 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 be required to make capital improvements in 1995 of approximately $2 million, primarily for the removal and upgrading of underground storage tanks, and approximately $8 million during 1996 for the installation of dike liners required under Alaska environmental regulations. 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 20 further information on environmental contingencies, see Note 4 of Notes to Condensed Consolidated Financial Statements. The Company's contract with the State of Alaska ("State") for the purchase of royalty crude oil expires on December 31, 1995. In May 1995, the Company renegotiated a new three-year contract with the State for the period January 1, 1996 through December 31, 1998. The new contract provides for the purchase of approximately 40,000 barrels per day of ANS royalty crude oil, the primary feedstock for the Company's refinery, and is priced at the weighted average price reported to the State by a major North Slope producer for ANS crude oil as valued at Pump Station No. 1 on the Trans Alaska Pipeline System. Under this agreement, the Company is required to utilize in its refinery operations volumes equal to at least 80% of the ANS crude oil to be purchased from the State. This contract contains provisions that allow the Company to temporarily or permanently reduce its purchase obligations. As discussed in Note 4 of Notes to Condensed Consolidated Financial Statements, the Company is involved with other litigation and claims, none of which is expected to have a material adverse effect on the financial condition of the Company. 21 PART II - OTHER INFORMATION Item 1. Legal Proceedings Tennessee Gas Contract. The Company is selling a portion of the gas from its Bob West Field to Tennessee Gas Pipeline Company ("Tennessee Gas") under a Gas Purchase and Sales Agreement ("Tennessee Gas Contract") which 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 in the District Court of Bexar County, Texas, alleging that the Tennessee Gas 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. During June 1995, the Contract Price was in excess of $8.00 per Mcf, the Section 101 price was $4.94 per Mcf and the average spot market price was $1.56 per Mcf. 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. On appeal by Tennessee Gas, the Court of Appeals for the Fourth Supreme Judicial District of Texas affirmed the validity of the Tennessee Gas Contract as to the Company's properties and held that the price payable by Tennessee Gas for the gas was the Contract Price. The Court of Appeals remanded the case to the trial court based on its determination (i) that the Tennessee Gas Contract was an output contract and (ii) that a fact issue existed as to whether the increases in the volumes of gas tendered to Tennessee Gas under the contract were made in bad faith or were unreasonably disproportionate to prior tenders. The Company sought review of the appellate court ruling on the output contract issue in the Supreme Court of Texas. Tennessee Gas also sought review of the appellate court ruling denying the remaining Tennessee Gas claims in the Supreme Court of Texas. The appellate court decision was the first decision reported in Texas holding that a take-or-pay contract was an output contract. The Supreme Court of Texas heard arguments in December 1994, regarding the output contract issue and certain of the issues raised by Tennessee Gas. On August 1, 1995, the Supreme Court of Texas, in a divided opinion, affirmed the decision of the appellate court on all issues, determined that the Tennessee Gas Contract was an output contract and remanded the case to the trial court for determination of whether gas volumes tendered by the Company to Tennessee Gas were tendered in good faith and were not unreasonably disproportionate to any normal or otherwise comparable prior output or stated estimates in accordance with Section 2.306 of the UCC. In addition, the Supreme Court affirmed that the price under the Tennessee Gas Contract is the Contract Price. The Company intends to file a motion for rehearing before the Texas Supreme Court on the issue of whether the Tennessee Gas Contract is an output contract. Through June 30, 1995, under the Tennessee Gas Contract, the Company recognized cumulative revenues in excess of spot market prices through September 17, 1994, and in excess of a nonrefundable $3.00 per Mcf bond price subsequent to September 17, 1994, totaling $86.6 million of which $33.9 million is included in receivables. The Company and its outside counsel are evaluating the impact of various aspects of the Supreme Court decision. The Company believes that, if this issue is tried, the gas volumes tendered to Tennessee Gas will be found to have been in good faith and otherwise in accordance with the requirements of the UCC. However, there can be no assurance as to the ultimate outcome at trial. An adverse outcome of this litigation could require the Company to reverse some or all of the incremental revenue and repay Tennessee Gas all or a portion of $52.5 million for amounts received above spot market prices, plus interest if awarded by the court. In September 1994, the court ordered that, effective until August 1, 1995, Tennessee Gas (i) take at least its entire monthly take-or-pay obligation under the Tennessee Gas Contract, (ii) pay for gas at $3.00 per Mmbtu, which approximates $3.00 per Mcf ("Bond Price"), and (iii) post a $120 million bond with the court representing an amount which, together with anticipated sales of natural gas to Tennessee Gas at the Bond Price, will equal the anticipated value of the Tennessee Gas Contract during this interim period. The Bond Price is nonrefundable by the Company, and the Company retains the right to receive the full Contract Price for all gas sold to Tennessee Gas. On August 10, 1995, a hearing was held before the trial court regarding the extension of the Tennessee Gas bond. The parties agreed and the court ordered that Tennessee Gas, for the period August 14, 1995, until the earlier of October 16, 1995, or the date the Supreme Court issues its rulings on motions for rehearing, (i) continue to take at least its entire take-or-pay volume obligation, (ii) pay for gas at a price of $3.00 per Mmbtu subject to potential refund of amounts in excess of market prices if Tennessee Gas should ultimately prevail in litigation, and (iii) post a $25 million bond in addition to the $120 million bond presently in place. Tennessee Gas had previously agreed to pay the Company the nonrefundable Bond Price until August 14, 1995. 22 Environmental Matters. As previously reported, the Company has been identified by the Environmental Protection Agency ("EPA") as a potentially responsible party ("PRP") pursuant to the Comprehensive Environmental Response, Compensation, and Liability Act of 1980 ("CERCLA") for the Hansen Container Site, Grand Junction, Mesa County, Colorado ("Site"). The Site was a drum recycling site which accepted and recycled used containers from the mid-1960's through 1989. Over 220 parties have been identified as PRP's at the Site. The Company sold a minimum number of containers to the Site in the mid-1970's. CERCLA imposes joint and several liability on PRP's; each PRP is therefore responsible for 100% of the costs of the response actions necessary to remediate the Site in the event a settlement with the EPA cannot be reached. The EPA has spent approximately $2.35 million at the Site through September 1994 and is seeking reimbursement from over 220 PRP's. The Company has entered into an Administrative Order on Consent for De Minimis Settlement with the EPA applicable to those PRP's who each contributed less than 2% of the total contamination at the Site. The Company has agreed to contribute approximately $1,400 in full settlement of claims against the Company. As previously reported, in March 1992, the Company received a Compliance Order and Notice of Violation from the EPA alleging violations by the Company of the New Source Performance Standards under the Clean Air Act at its Alaska refinery. These allegations include failure to install, maintain and operate monitoring equipment over a period of approximately six years, failure to perform accuracy testing on monitoring equipment, and failure to install certain pollution control equipment. From March 1992 to July 1993, the EPA and the Company exchanged information relevant to these allegations. In addition, the EPA conducted an environmental audit of the Company's refinery in May 1992. As a result of this audit, the EPA is also alleging violation of certain regulations related to asbestos materials. In October 1993, the EPA referred these matters to the Department of Justice ("DOJ"). The DOJ contacted the Company to begin negotiating a resolution of these matters. The DOJ has indicated that it is willing to enter into a judicial consent decree with the Company and that this decree would include a penalty assessment. Negotiations on the penalty are in progress. The DOJ has currently proposed a penalty assessment of approximately $2.3 million. The Company is continuing to negotiate with the DOJ but cannot predict the ultimate outcome of the negotiations. Refund Claim. As previously reported, in July 1994, Simmons Oil Corporation, also known as David Christopher Corporation, a former customer of the Company ("Customer"), filed suit against the Company in the United States District Court for the District of New Mexico for a refund in the amount of approximately $1.2 million, plus interest of approximately $4.4 million and attorney's fees, related to a gasoline purchase from the Company in 1979. The Customer also alleges entitlement to treble damages and punitive damages in the aggregate amount of $16.8 million. The refund claim is based on allegations that the Company renegotiated the acquisition price of gasoline sold to the Customer and failed to pass on the benefit of the renegotiated price to the Customer in violation of Department of Energy price and allocation controls then in effect. In May 1995, the court issued an order granting the Company's motion for summary judgment and dismissed with prejudice all the claims in the Customer's complaint. In June 1995, the Customer filed a notice of appeal with the U.S. Court of Appeals for the Federal Circuit. The Company cannot predict the ultimate resolution of this matter but believes the claim is without merit. 23 Item 4. Submission of Matters to a Vote of Security Holders (a) The 1995 annual meeting of stockholders of the Company was held on May 4, 1995. (b) The names of the directors elected at the meeting and a tabulation of the number of votes cast for, against or withheld with respect to each such director are set forth below: Name Votes Votes Votes For Against Withheld Michael D. Burke 21,058,262 0 946,368 Robert J. Caverly 12,649,742 0 9,354,888 Peter M. Detwiler 11,118,264 0 10,886,366 Steven H. Grapstein 21,041,619 0 963,011 Raymond K. Mason, Sr. 11,112,707 0 10,891,923 John J. McKetta, Jr. 11,085,270 0 10,919,360 Joel V. Staff 13,377,871 0 8,626,759 Murray L. Weidenbaum 12,653,329 0 9,351,301 At the annual meeting of stockholders, a dissident slate of directors consisting of six individuals was nominated from the floor. The dissident slate subsequently challenged the results of the election. The challenge was rejected by the inspector of election and, thereafter, by the Delaware Chancery Court which upheld the votes set forth above. Joel V. Staff resigned as a director of the Company effective June 13, 1995. Bruce A. Smith was elected as a director of the Company effective July 26, 1995. (c) A brief description of each matter, other than the election of directors, voted upon at the meeting and the number of votes cast for, against or withheld, as well as the number of abstentions and broker non-votes as to each matter, is set forth below: With respect to a proposal to approve and adopt the 1995 Non-Employee Director Stock Option Plan, there were 10,957,145 votes for; 10,403,943 votes against; 284,496 votes withheld; 359,046 broker non-votes; and no abstentions. With respect to a proposal to limit the number of shares which can be granted to any single participant in one year under the Executive Long-Term Incentive Plan, there were 12,198,512 votes for; 9,287,131 votes against; 163,941 votes withheld; 355,046 broker non-votes; and no abstentions. With respect to a proposal to appoint Deloitte & Touche LLP as independent auditors for the Company for fiscal year 1995, there were 21,235,489 votes for; 256,468 votes against; 157,627 votes withheld; 355,046 broker non-votes; and no abstentions. 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. 24 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: August 14, 1995 /s/ Michael D. Burke Michael D. Burke President and Chief Executive Officer Date: August 14, 1995 /s/ Bruce A. Smith Bruce A. Smith Chief Operating Officer, Executive Vice President and Chief Financial Officer 25 EXHIBIT INDEX Exhibit Number 4 Copy of Consent and Waiver No. 2 dated as of July 31, 1995 to the Company's Credit Agreement dated as of April 20, 1994. 10 Agreement for the Sale and Purchase of State Royalty Oil dated as of April 21, 1995 by and between Tesoro Alaska Petroleum Company and the State of Alaska. 11 Information Supporting Earnings (Loss) Per Share Computations. 27 Financial Data Schedule. 26 EX-4 2 CONSENT AND WAIVER NO. 2 CONSENT AND WAIVER NO. 2 CONSENT AND WAIVER NO. 2 (the "Consent and Waiver"), dated as of July 31, 1995, by and among Tesoro Petroleum Corporation (the "Company"), Texas Commerce Bank National Association ("TCB"), individually, as an Issuing Bank and as Agent (the "Agent"), Banque Paribas ("BP"), individually, as an Issuing Bank and as Co-Agent, and Bank of Scotland, Christiania Bank, The Bank of Nova Scotia, NBD Bank, Bank of America Illinois, First Union National Bank of North Carolina, National Bank of Canada and The Frost National Bank. WITNESSETH WHEREAS, the Company has entered into a Credit Agreement, dated as of April 20,1994, among the Company, TCB, individually, as an Issuing Bank and as Agent, BP, individually, as an Issuing Bank and as Co-Agent, and the other financial institutions parties thereto (the "Credit Agreement"; all capitalized terms used herein and not otherwise defined herein shall have the meanings ascribed thereto in the Credit Agreement); WHEREAS, the Company has requested that Majority Lenders consent to the waiver of the Company's obligation to cause the Tesoro Refining and Marketing Group to maintain the Tesoro Refining and Marketing Group EBITDA for the Rolling Period ending on June 30,1995; WHEREAS, the Agent, the Issuing Banks and the Lenders are willing to agree to the consent and waiver contained herein upon the terms and conditions set forth below; NOW, THEREFORE, the parties hereto agree as follows: SECTION 1. Consent and Waiver. The Majority Lenders hereby consent to the waiver of the Company's obligations under Section 5.03(d) to the Credit Agreement to cause the Tesoro Refining and Marketing Group to maintain the Tesoro Refining and Marketing Group EBITDA of at least $15,000,000 for the Rolling Period ending on June 30, 1995; provided, however, the Company agrees that it will be required to comply in full with such Section 5.03(d) of the Credit Agreement for the Rolling Period ending on September 30,1995. SECTION 2. Representations and Warranties. On and as of the date hereof, after giving effect to this Consent and Waiver, the Company represents and warrants the following: (a) all of the representations and warranties in Article IV of the Credit Agreement are true and correct in all material respects as if made on and as of the date of this Consent and Waiver, except to the extent any such representation or warranty relates specifically to an earlier date; (b) no Default or Event of Default has occurred and is continuing, or would result from the effectiveness of this Consent and Waiver; and (c) The execution and delivery by the Company of this Consent and Waiver are within the Company's powers and have been duly authorized by all necessary corporate or other action. SECTION 3. Effect on Credit Apreement. Except to the extent of the consents and waivers specifically set forth herein, all provisions of the Credit Agreement and the other Security Instruments are and shall remain in full force and effect and are hereby ratified and confirmed in all respects, and the execution, delivery and effectiveness of this Consent and Waiver shall not operate as a waiver of any provision of the Credit Agreement or any other Security Instrument not specifically referred to herein. SECTION 4. Execution in Counterparts. This Consent and Waiver may be executed in any number of counterparts, and by the parties hereto in separate counterparts, each of which when so executed shall be deemed to be an original and all of which taken together shall constitute one and the same agreement. SECTION 5. GOVERNING LAW. THIS CONSENT AND WAIVER SHALL BE GOVERNED BY AND CONSTRUED IN ACCORDANCE WITH THE APPLICABLE LAWS OF THE STATE OF TEXAS WITHOUT REFERENCE TO PRINCIPLES OF CONFLICT OF LAWS. SECTION 6. Previous Agreements. This Consent and Waiver supersedes any and all previous agreements, documents and understandings relating to the consents and waivers set forth herein, to the extent inconsistent herewith. IN WITNESS WHEREOF, the parties hereto have caused this Consent and Waiver to be duly executed and delivered by their respective officers or other duly authorized representatives as of the date first above written. COMPANY: TESORO PETROLEUM CORPORATION By: /s/ William T. Van Kleef Name: William T. Van Kleef Title: Vice President, Treasurer -2- AGENT, ISSUING BANKS AND LENDERS: TEXAS COMMERCE BANK NATIONAL ASSOCIATION, individually, as an Issuing Bank and as Agent By: /s/ D. G. Mills Name: D. G. Mills Title: Vice President -3 - BANQUE PARIBAS, individually, as an Issuing Bank and as Co-Agent By: /s/ Brian Malone Name: BRIAN MALONE Title: VICE PRESIDENT By: /s/ Barton D. Schouest Name: Barton D. Schouest Title: Group Vice President -4- BANK OF SCOTLAND By: /s/ Catherine M. Oniffrey Name: CATHERINE M. ONIFFREY Title: VICE PRESIDENT -5- CHRISTIANIA BANK By: /s/ Peter M. Dodge Name: PETER M. DODGE Title: VICE PRESIDENT By: /s/ Debra Ives Name: DEBRA IVES Title: VICE PRESIDENT -6- THE BANK OF NOVA SCOTIA By: /s/ F. C. H. Ashby Name: F.C.H. Ashby Title: Senior Manager Loan Operations -7- NBD BANK By: /s/ Russell H. Liebetrau, Jr. Name: RUSSELL H. LIEBETRAU, JR. Title: Vice President -8- BANK OF AMERICA ILLINOIS By: /s/ Ronald E. McKaig Name: Ronald E. McKaig Title: Vice President -9- FIRST UNION NATIONAL BANK OF NORTH CAROLINA By: /s/ Michael J. Kolosowsky Name: Michael J. Kolosowsky Title: Vice President -10- NATIONAL BANK OF CANADA By: /s/ Larry L. Sears Name: Larry L. Sears Title: Group Vice President By: /s/ Douglas G. Clark Name: Douglas G. Clark Title: Vice President -11- THE FROST NATIONAL BANK By: /s/ Phil Dudley Name: Phil Dudley Title: Vice President -12- EX-10 3 CRUDE OIL PURCHASE CONTRACT AGREEMENT FOR THE SALE AND PURCHASE OF STATE ROYALTY OIL to TESORO ALASKA PETROLEUM COMPANY THE STATE OF ALASKA Department of Natural Resources Dated as of April 21, 1995 TABLE OF CONTENTS ARTICLE I DEFINITIONS.................................................1 1.1 Commissioner ......................................1 1.2 Daily Royalty Oil..................................1 1.3 Day................................................1 1.4 Effective Date ....................................1 1.5 Field Cost Agreement. .............................1 1.6 Leases.............................................1 1.7 Lessee ............................................2 1.8 Month .............................................2 1.9 Oil................................................2 1.10 Point of Delivery .................................2 1.11 Royalty Oil........................................2 1.12 Royalty Settlement Agreements .....................2 1.13 Royalty Value .....................................2 1.14 TAPS ..............................................2 1.15 Unit Agreement.....................................2 ARTICLE II SALE OF ROYALTY OIL ........................................3 2.1 Quantity...........................................3 2.2 Quality............................................4 2.3 Price of the Royalty Oil...........................5 2.4 Reopeners..........................................5 2.5 Point and Time of Delivery.........................7 2.6 Passage of Title and Risk of Loss..................7 2.7 Tesoro's Responsibility............................7 2.8 Transportation Arrangements .......................7 2.9 Absolute Obligations...............................8 2.10 Date of First Delivery.............................8 2.11 Performance Guaranty and Reservation Fee...........8 2.12 In-State Processing................................8 ARTICLE III REPRESENTATION AND OBLIGATIONS OF TESORO....................9 3.1 Good Standing and Due Authorization................9 3.2 Financial Condition...............................10 3.3 Financial Statements .............................10 ii ARTICLE IV MEASUREMENTS AND TESTS ....................................11 ARTICLE V PAYMENTS AND ACCOUNTING....................................11 5.1 Initial Billing...................................11 5.2 Initial Adjustment ...............................12 5.3 Subsequent Adjustments ...........................13 5.4 Payment...........................................13 5.5 Interest..........................................14 5.6 Late Payment Penalty..............................15 5.7 Payment to Lessee.................................16 5.8 Payment to Third Parties..........................16 ARTICLE VI TERM ......................................................16 ARTICLE VII DEFAULT OR TERMINATION.....................................17 7.1 Default...........................................17 7.2 Failure to Pay Debts..............................18 7.3 State's Remedies..................................19 7.4 Tesoro's Exclusive Remedies.......................20 ARTICLE VIII DISPOSITION OF OIL.........................................20 8.1 Disposition of Oil Upon Default or Termination ...20 8.2 Inability to Receive Oil..........................20 8.3 No Right to Storage or Underlift .................21 ARTICLE IX WAIVER.....................................................21 ARTICLE X VALIDITY...................................................22 ARTICLE XI FORCE MAJEURE AND CHANGE IN CONDITION......................22 11.1 Effect of Force Majeure ..........................22 11.2 Responsibility....................................22 iii ARTICLE XII NOTICES....................................................23 12.1 Method............................................23 12.2 Change of Address ................................24 ARTICLE XIII RULES AND REGULATIONS......................................24 ARTICLE XIV SOVEREIGN POWER OF THE STATE...............................24 ARTICLE XV SECURITY...................................................24 15.1 Letter of Credit..................................24 15.2 Reduction of Term.................................26 ARTICLE XVI PREFERENTIAL HIRING AND NON-DISCRIMINATION ................26 ARTICLE XVII ...................................................27 APPLICABLE LAW.............................................27 17.1 Alaska Law........................................27 17.2 Submission to Jurisdiction........................27 ARTICLE XVIII WARRANTIES.................................................27 ARTICLE XIX AMENDMENT..................................................28 ARTICLE XX SUCCESSORS AND ASSIGNS.....................................28 ARTICLE XXI HEADINGS ..................................................28 ARTICLE XXII RECORDS....................................................28 22.1 Preservation of Records ..........................28 22.2 Inspection of Records of Parties..................29 ARTICLE XXIII INTERPRETATION OF TERMS AND CONDITIONS ....................30 iv ARTICLE XXIV COUNTERPARTS ..............................................30 SIGNATURES......................................................31 ACKNOWLEDGEMENT ................................................32 EXHIBIT A.......................................................35 v AGREEMENT FOR THE SALE AND PURCHASE OF ROYALTY OIL THIS AGREEMENT is effective as of April 21, 1995 by and between the State of Alaska (State) and Tesoro Alaska Petroleum Company, a Delaware corporation with its principal offices located at 3230 C Street, Anchorage, Alaska 99503 and Tesoro Petroleum Corporation, a Delaware corporation with its principal offices located at 8700 Tesoro Drive, San Antonio, Texas 78217 (collectively Tesoro). ARTICLE I DEFINITIONS As used in this Agreement, the following terms shall have the following respective meanings: 1.1 "Commissioner" means the Commissioner of the Alaska Department of Natural Resources or his designee. 1.2 "Daily Royalty Oil" means the quantity of Royalty Oil produced by the Lessees from the Prudhoe Bay Unit Area in a Day except as provided in Article 2.1 (b). 1.3 "Day" means a period of twenty-four (24) consecutive hours, beginning at 12:01 a.m., Alaska Standard Time. 1.4 "Effective Date" shall have the meaning set out in Article VI. 1.5 "Field Cost Agreement" means the Prudhoe Bay Royalty Settlement Agreement effective April 1, 1980. 1.6 "Leases" means the Oil and Gas leases which are subject to the terms of the Prudhoe Bay Unit Agreement. 1 1.7 "Lessee" means any person owning a working interest in any of the Leases. 1.8 "Month" means the period beginning at 12:01 a.m., Alaska Standard Time, on the first Day of the calendar Month and ending at the same time on the first Day of the next succeeding calendar Month. 1.9 "Oil" means the same as the word "oil" under the Leases and the Unit Agreement, except where inconsistent with Articles 2.1(b) and 2.2 of this Agreement, in which case Articles 2.1(b) and 2.2 shall control. For purposes of this Agreement, "Oil" shall also include natural gas liquids ("NGLs"). 1.10 "Point of Delivery" shall have the meaning set out in Article 2.6. 1.11 "Royalty Oil" means the Oil which the State may take in-kind (in amount) as its royalty under the Leases whether or not the State has elected to take or is taking that royalty in-kind except as provided in Article 2.1(b). 1.12 "Royalty Settlement Agreement" means the written royalty settlement agreements between the State and Exxon Corporation ("Exxon") dated December 31, 1991. 1.13 "Royalty Value" means the royalty value of all liquid hydrocarbons from the Prudhoe Bay Unit or the Prudhoe Bay Unit initial Participating Areas as provided in Article 2.1(b) calculated in accordance with the Royalty Settlement Agreement for West Coast placements as explained in Article 2.3. 1.14 "TAPS" means the Trans Alaska Pipeline System. 1.15 "Unit Agreement" means the Prudhoe Bay Unit Agreement effective April 1, 1977, by and between the Lessees and the State, as amended from time to time. 2 ARTICLE II SALE OF ROYALTY OIL 2.1 Quantity. 2.1(a) Prudhoe Bay Unit Quantity. The State agrees to sell to Tesoro and Tesoro agrees to buy from the State that amount of Oil equal to 30.0 percent of the Daily Royalty Oil (Maximum Quantity). At any time upon six months and ten days written notice, Tesoro may: (l) decrease the Maximum Quantity; or (2) terminate this Agreement, in which case Tesoro shall not make any payments as described in Article 2.11 . Subject to the limitations in this article, Tesoro may temporarily decrease or increase the amount of Oil to be tendered, but not the Maximum Quantity provided in this article. To increase or decrease the amount of Oil to be tendered, Tesoro must give the State at least six Months and ten Days written notice. If, however, the increase or decrease is less than ten percent of Tesoro's then current in-kind nomination, Tesoro must give at least one hundred Days written notice. In addition, he new tendering will take effect on the first Day of the Month after the applicable notice period expires. The volume of Daily Royalty Oil available to the State will vary and may be interrupted from time to time, and depends upon a variety of factors, including the rate of production from the Leases. The State disclaims and Tesoro waives any representation, covenant or warranty, expressed or implied, that a specific quantity or the total or daily, monthly, average, or aggregate volume of Royalty Oil will be sold or tendered under this Agreement. The State warrants that it has good title to the Oil tendered under this Agreement. 3 If the State underlifts or stores Royalty Oil at the Prudhoe Bay Unit, or if the State recovers underlifted or stored Royalty Oil, the quantity of Oil tendered under this Agreement shall be calculated as if no Royalty Oil were underlifted or stored or recovered. 2.1(b) Initial Participating Areas Quantity. The State may choose, in its sole discretion, to sell to Tesoro, and Tesoro agrees to buy from the state, oil that is produced solely from the initial Participating Areas of the Prudhoe Bay Unit, as defined in the Unit Agreement, rather than from all participating areas and Leases within the Prudhoe Bay Unit. If the State so elects, the Maximum Quantity of Oil shall equal 35.2 percent of the Royalty Oil produced from the initial Participating Areas in a Day. If the State so elects, the terms Daily Royalty Oil, Oil, and Royalty Oil shall have the same meaning set forth in Article I as limited in this article. 2.2 Quality. The Oil sold shall be the same quality as the Royalty Oil delivered by the Lessees to the State at the Point of Delivery from the Prudhoe Bay Unit Area. The quality of the Oil sold may vary from time to time. The State disclaims, and Tesoro waives, any guarantee, representation, or warranty, either expressed or implied, of merchantability, fitness for use, or suitability for any particular use or purpose, or otherwise, of any of the Oil delivered under this Agreement or as to any specific, average, or overall quality or characteristic of Oil to be sold or tendered under this Agreement. Tesoro expressly waives any claim that any liquid hydrocarbons made available to the State by the Lessees, including such substances as crude oil, condensate, natural gas liquids, or return oil from the Prudhoe Bay Unit Crude Oil Topping Plant, that may be blended with crude by the Lessees before the Point of Delivery and tendered as a common stream by the Lessees to the State as Royalty Oil are not Oil, for purposes of this Agreement. 4 2.3 Price of the Royalty Oil. The price each Month for Oil purchased under this Agreement shall be the Royalty Value for that Month of Oil delivered to the West Coast by Exxon from the Prudhoe Bay Unit production. The Royalty Value shall be determined according to the Royalty Value calculation stated in Article 3.2 c) of its Royalty Settlement Agreement, except that the Average Valdez Netback shall be the West Coast Valdez Netback. Exhibit A is an illustrative calculation of the price if Tesoro had purchased Oil during the Month of January, 1995. If any applicable law of the United States of America or any rule or regulation promulgated by a federal agency will, in the sole judgment of the State, operate to prohibit or prevent the State from receiving the full amount due under the above provision, Tesoro's obligation to pay the amount of the purchase price in excess of the amount permitted will be suspended or adjusted to the minimum extent required for the State to comply with that law, rule or regulation. 2.4 Reopeners. 2.4(a) Export Ban Reopener. Neither Tesoro nor the State shall have the right to reopen this Agreement, unless the export ban on Alaska North Slope crude now in effect is lifted. Anytime after the export ban is lifted, either Tesoro or the State may reopen this Agreement for purchase price only, by giving the other party one month's prior written notice. Upon issuance and receipt of a notice to reopen, Tesoro and the State will promptly commence good faith negotiations in an attempt to establish a new purchase price. If Tesoro and the State cannot agree on a price within three months after the written notice to reopen, either Tesoro or the State may terminate this Agreement upon nine months written notice to the other. The purchase price for Oil tendered during any period pending termination shall be the price in effect immediately before giving the 5 notice of intent to reopen. If a new purchase price is agreed to by Tesoro and the State, the new price shall be effective for Oil delivered in the month following the Agreement. 2.4(b) Royalty Settlement Agreement Reopener. Tesoro shall not intervene or otherwise participate in any way regarding litigation, styled ANS Royalty Litigation. Case No. 1-JU-77-847, any future royalty settlement agreements with the Lessees, or reopeners or other discussions under or pertaining to royalty settlement agreements. Any judgment resulting from the ANS Royalty Litigation, any future royalty settlement agreements, or any reopener under the Royalty Settlement Agreement shall be conclusively binding upon Tesoro whether or not Tesoro agrees with or consents to the terms of any such judgment, settlement, or reopener. Furthermore, Tesoro has no independent right to invoke any of, the provisions of the Royalty Settlement Agreement. If the Royalty Value is modified in the future as a result of a modification of the Royalty Settlement Agreement, a corresponding retroactive modification will be made to the price term of this Agreement and interest will apply to the modification, whether resulting in an overpayment or underpayment, as set forth in Article 5.6. Tesoro agrees to be conclusively bound by any such modification agreed to by the State and Exxon. Nevertheless, due to potential unpredictable increased costs to Tesoro posed by any changes to Article III of the Royalty Settlement Agreement and/or any changes made under the reopener procedures of Article IV of the Royalty Settlement Agreement, the State shall give Tesoro notice of such changes or a Notice of Reopener initiated by Exxon or the State. Such notice shall include information on the nature of such changes and/or the reopener, the requested effective date of any such changes or proposed changes, and the position taken by Exxon and the State. Any changes 6 and/or Reopener action under the Royalty Settlement Agreement will give Tesoro the right to terminate this contract upon six Months and ten Days written notice to the State. 2.5 Point and Time of Delivery. Simultaneously with receipt of its Royalty Oil from its Lessees, the State shall tender the Oil to Tesoro where the State receives the Royalty Oil from its Lessees. That point presently agreed to by the State and its Lessees in Article 2.3 of the Field Cost Agreement is the TAPS Pump Station No. 1 Prudhoe Bay Custody Transfer meter ("Transfer Meter"). 2.6 Passage of Title and Risk of Loss. Title and risk of loss to the Oil sold under this Agreement shall pass from the State to Tesoro for all purposes when the State tenders the Oil at the Point of Delivery. 2.7 Tesoro's Responsibility. Tesoro shall be responsible for the Oil after passage of title. Tesoro will indemnify and hold the State harmless from and against any and all claims, costs, damages (including reasonably foreseeable consequential damages), expenses, or causes of action arising from or in connection with any transaction or event which relates to the Oil after title has passed to Tesoro. 2.8 Transportation Arrangements. Tesoro shall make all necessary arrangements for transporting the Oil sold under this Agreement from the Point of Delivery, including satisfaction of line fill obligations and storage tank bottom requirements of the TAPS, if any. If requested by the State, Tesoro shall submit specific information concerning its arrangement for transportation of the Oil sold under this Agreement through and away from the TAPS and for the resale or other disposal of the Oil. Such information may include the specific tenders of Oil made to the TAPS and identification of tankers, if any, which will transport the Oil. In addition, Tesoro will provide the 7 State, if requested by the State, with satisfactory evidence or reasonable assurance of the existence and continuing validity of adequate arrangements for the transportation or disposal of the Oil subject to this Agreement. Failure to provide information, evidence, or assurances requested will, at the State's election by notice to Tesoro, be a material default under this Agreement. 2.9 Absolute Obligations. The obligations of Tesoro to accept, pay for, and arrange for the transportation of the Oil tendered or sold under this Agreement are absolute and will not be excused or discharged by the operation of any disability of Tesoro, event of force majeure, impracticability or performance, change in conditions, or any other reason or cause. 2.10 Date of First Delivery. The date of First Delivery will be the first Day of January 1,1996. 2.11 Performance Guaranty and Reservation Fee. If Tesoro does not take the Maximum Quantity, Tesoro shall pay to the State, in addition to the purchase price on the actual quantity taken, an amount equal to .75 percent of the purchase price per barrel per Day on the difference between the Maximum Quantity and the actual quantity tendered to and accepted by Tesoro for each Day Tesoro does not take the Maximum Quantity. 2.12 In-State Processing. Tesoro agrees to use best efforts to insure that any and all of the Royalty Oil tendered under this Agreement will be processed through Tesoro's refinery near Nikiski, Alaska, or will be exchanged for other crude oil which shall be processed at that refinery. "Process" means the manufacture of refined petroleum products. In no event, however, shall the quantity of Royalty Oil, which must be processed, be less than 80 percent of the volume of Royalty Oil tendered under this Agreement. "Exchange" means: (l) direct trades of equal volumes of crude oil; (2) trades of crude oil involving either cash or volume adjustments, or both, provided that those 8 adjustments relate solely to quality or location differences; (3) sequential transactions in which Tesoro receives back crude oil from a party other than the party which receives the Royalty Oil in a trade from Tesoro; or (4) matching purchases and sales of crude oil. The terms under which Tesoro receives crude oil in any exchange shall not differ in any significant term from the terms under which Tesoro delivered Royalty Oil except for terms which adjust for differences in quality and location. Tesoro agrees that any trade or exchange shall not reduce the price to be paid to the State and that trades or exchanges shall be at no cost or expense to the State. Tesoro's obligation to process Royalty Oil or exchanged oil in-State may only be suspended or excused under the provisions of Articles VIII and XI. The State may, in its sole discretion, waive the in-State processing requirement in whole or in part, if State is satisfied that Tesoro is using its best efforts to process the Royalty Oil tendered or the oil exchanged for Royalty Oil tendered under this Agreement at Tesoro's Alaska refinery and that the waiver would not be contrary to the underlying intent of the other provisions of this Agreement. ARTICLE III REPRESENTATION AND OBLIGATIONS OF TESORO Tesoro warrants, represents, and agrees: 3.1 Good Standing and Due Authorization. Tesoro is, and at all times during the operation of this Agreement shall remain, a corporation organized and existing under and by virtue of the laws of the United States or of any State, territory or the District of Columbia, and qualified to do business in, and in good standing with, the State of Alaska. Tesoro has all necessary corporate power 9 to enter into this Agreement and to perform the covenants and obligation under this Agreement. All necessary corporate action has been taken to authorize Tesoro to enter into this Agreement and perform its covenants and obligations under this Agreement. 3.2 Financial Condition. The financial information submitted to the State is complete and correct and fairly presents Tesoro's financial condition when the information was submitted to the State. The financial information was prepared in accordance with generally accepted accounting principles consistently applied. Since the date the information was submitted, the condition, business, and properties of Tesoro have not been materially adversely affected in any way. Tesoro agrees to inform the State immediately if there is any material adverse change in its condition, business, or properties which may have an appreciable adverse effect on its ability to perform under this Agreement. Tesoro, in addition, will immediately inform the State of any significant change in ownership of Tesoro, affiliates, parent company, and of any change in Tesoro's operations or Agreements, which may appreciably affect Tesoro's performance under this Agreement. 3.3 Financial Statements. As soon as possible after the end of the fiscal year of Tesoro, and in any event within one hundred twenty Days thereafter, Tesoro will furnish to the State, at Tesoro's sole cost and expense, a report or a complete copy of a report in a form to be prescribed from time to time by the State which will include Tesoro's balance sheet as of the close of the fiscal year and the income statement for that year, prepared in each case in accordance with generally accepted accounting principles consistently applied by certified public accountants of recognized standing. For purposes of complying with this article, Tesoro may submit, and the State will accept, the annual report of Tesoro Petroleum Corporation filed with the United States Securities and Exchange Commission pursuant to Sec. 13 or 15 (d) of the Security Exchange Act of 1934. 1O ARTICLE IV MEASUREMENTS AND TESTS The quantity and quality of Oil sold under this Agreement shall be determined at the Point of Delivery. Procedures and methods for measuring and metering the Oil sold under this Agreement shall be in accordance with the practices then in effect in the Prudhoe Bay Unit. ARTICLE V PAYMENTS AND ACCOUNTING 5.1 Initial Billing. The State will send to Tesoro, on or before the tenth business Day of each Month after delivery of Oil, an invoice statement of account of all Oil estimated to have been measured at the Transfer Meter and tendered to Tesoro under this Agreement during the immediately preceding Month according to the best information available to the State, the estimated purchase price applicable to those deliveries, and the total amount due (Initial Billing Invoice). The estimates will be made by the State according to the best information reasonably available to the State. The State may render its Initial Billing Invoice to Tesoro based in part upon information reported by the Lessees to the State, information published by the U.S. Government, and information published in Platt's Oilgram Price Report or any other publicly available report. The State shall thereafter adjust its Initial Billing Invoice under this article as soon as more accurate information concerning the quantity and purchase price of Oil delivered each Month is available. The State, however, shall not be required to adjust the Initial Billing Invoice before the sending of the next Month's invoice statement of account. 11 5.2 Initial Adjustment. After the Initial Billing Invoice under Article 5.1, the next Monthly invoice will also state the State's initial adjustments, plus interest, to be made, if any, to the Initial Billing Invoice rendered in the immediately preceding Month, in accordance with any additional or more accurate information which may have become available to the State ("Initial Adjustment Invoice"). Whether or not initial adjustments are made, however, subsequent adjustments may be made under Article 5.5. 5.3 Subsequent Adjustments. Tesoro acknowledges that after the Initial Billing and Initial Adjustment Invoices, more accurate information concerning the quantity of or purchase price for Royalty Oil tendered may become available to the State. If any such information should later become available to the State, it shall furnish a corrected invoice statement of account to Tesoro ("Subsequent Adjustment Invoice") and the State will adjust the amount previously billed; and Tesoro will pay, or the State will credit or refund, the amount of any Subsequent Adjustment Invoice plus interest. If the State should render a Subsequent Adjustment Invoice to Tesoro, any amount to be credited or refunded from the State to Tesoro or paid by Tesoro to the State will be refunded or paid within thirty Days after the date of the Subsequent Adjustment Invoice. The parties recognize that subsequent adjustments may be necessary after December 31, 1998, and, accordingly, the provisions of Article V will survive any termination of this Agreement. Any Subsequent Adjustment Invoice rendered more than six years after the date of delivery will bear interest for only six years from the date accrued as defined in Article 5.5. This limitation on interest does not apply to Subsequent Adjustment Invoices resulting from: (l) regulatory, reopener or court proceeding (including appeals) commenced during the six year period 12 whether or not the Tesoro or the State is a party and (2) bona fide audits by the State of Exxon commenced during the six year period. 5.4 Payment. Tesoro will pay the Initial Billing Invoice on the third business Day of the month following delivery or within three business Days after the date of the invoice whichever is later; and the Initial Adjustment Invoice within three business Days of the date of the invoice and on any Subsequent Adjustment Invoice within 30 Days of the date of the invoice. Payment shall be made without any deduction, set off, or withholding, by wire transfer of immediately available funds to the State's account at the following address: State Street Bank & Trust Company Boston, Massachusetts ABA #011000028 For credit to the State of Alaska General Investment Fund, AY01 Account #00657189 Attn: Kim Chan, Public Funds Payment may be made in such other manner or to such other address as the State may specify in the invoice statement of account or by other written notice. All other payments to be made under this Agreement shall be paid in the same manner. If payment is due on a Saturday, Sunday, or legal holiday of the place where payment is to be received, payment shall be made on the next following business Day. It is recognized that the State may bill, and that Tesoro will pay, amounts that are based upon confidential information held or received by the State. If confidential information is used as the basis for a billing, then the State will furnish Tesoro, upon its request, with the certified statement of the Commissioner that the amounts billed are correct based upon the best information available to the State. If a dispute concerning a bill arises, Tesoro agrees to pay the full amount billed by the State, except for obvious clerical mistakes, pending final resolution of the dispute. 13 5.5 Interest. The Amount of all sums, which are not paid when due under this Agreement or which are later determined to be due as an adjustment, shall bear interest from the date accrued until paid in full at the rate as provided in AS 38.05.135(d) or as that statutory provision may later be amended. Currently, that interest rate in a calendar quarter is at the rate of five percentage points above the annual rate charged member banks for advances by the 12th Federal Reserve District as of the first Day of that calendar quarter, or at the annual rate of 11 percent, whichever is greater, compounded quarterly as of the last Day of that quarter. The term "date accrued" means the date of the "Initial Billing plus three business Days." Interest shall apply to both adjustments for overpayments and underpayments. The following illustrates from what date interest will run: January 1-31,1996--Tesoro takes 1996 January production; February 9, 1996 -- State sends Tesoro the Initial Billing Invoice for 1996 January production; February 14, 1996 (Initial Billing plus three business Days) -- Tesoro must pay the Initial Billing Invoice for January 1996 production. If Tesoro does not pay on this day, the Initial Billing Invoice bears interest from this date plus a late payment penalty. March 8, 1996 -- State sends Tesoro the Initial Adjustment Invoice for January 1996 production. Tesoro owes the State an additional sum. March 13,1996 -- Tesoro must pay the Initial Adjustment Invoice plus interest from February 14, 1996 throught the payment date. 14 January 10, 1997 -- State sends Tesoro a Subsequent Adjustment Invoice for January 1996 production. Tesoro is entitled to a credit. State pays interest from February 14, 1996 through January 10, 1997. April 10, 2006 -- The State is notified by Exxon that, due to a clerical error, it has revised the Royalty Value for January 1996. April 17, 2006 -- State sends Tesoro another Subsequent Adjustment Invoice for January 1996 production after Exxon a reports a clerical error in its calculation of the Royalty Value. Tesoro owes the State an additional sum. May 17, 2006 -- Tesoro must pay the Subsequent Adjustment Invoice for January 1996 production plus interest from calculated February 14, 1996 through February 14, 2002. If Tesoro does not pay the Subsequent Adjustment Invoice on this date, interest will accrue from February 14, 1996 through the date the payment is made and Tesoro must also pay a late payment penalty. November 10, 2006 -- Court settles dispute between the TAPS carriers and shippers; Carriers are awarded a higher tariff for January 1996. November 30, 2006 -- State sends Tesoro a Subsequent Adjustment Invoice. Tesoro is entitled to a refund which includes interest calculated from February 14, 1996 through November 30, 2006. 5.6 Late Payment Penalty. If Tesoro fails to make a full payment within three business days of the date of either an Initial Billing Invoice or Initial Adjustment Invoice, or within thirty Days of the date of any Subsequent Adjustment Invoice, then in addition to the amount due 15 plus interest from the date accrued until the date of actual payment, Tesoro will pay an amount equal to five percent of the principal payment due as a late payment penalty. 5.7 Payment to Lessee. At the request of the State in the invoice statement of account or otherwise in writing, Tesoro shall pay all or any portion designated by the State of that payment required to be made to one or more of the Lessees at an address or addresses and in the manner designated by the State. The payment will be made within the time limit specified in Article V. The State may authorize and designate a third party to make the request and designate the amount, manner and place of payment under this provision. Unless otherwise specified, the balance of the payment due, if any, and payment for subsequent Months, shall be made in accordance with Article V. 5.8 Payment to Third Parties. The State may direct that Tesoro pay any amount due or which may become due directly to a third party in a manner and time as may be directed by the State in written notice to Tesoro if, in the State's sole discretion, the payment to the third party will assist the State in monitoring or enforcing this Agreement. ARTICLE VI TERM This Agreement shall become effective upon execution by the parties. The State's obligation to sell and Tesoro's obligation to buy Royalty Oil becomes effective immediately. Deliveries under this Agreement shall begin on January 1, 1996, and shall end December 31, 1998. The provisions of Article V shall survive the termination of this Agreement. 16 ARTICLE VII DEFAULT OR TERMINATION 7.1 Default. If any one or more of the following events ("Events of Default") occur, then the State, at the its sole option, may terminate or suspend its obligation to tender and sell Oil and exercise any one or more of the rights and remedies provided in this Agreement: (i) At any time, Tesoro (a) repudiates any of its covenants or obligations under this Agreement, or (b) fails, within five Days, after written request from the State to provide the State with written affirmation of this Agreement and of Tesoro's intention to perform under this Agreement (together with evidence or assurances of transportation arrangement pursuant to Article 2.8 reasonably satisfactory to the State); (ii) Tesoro does not pay in full any sum owed under this Agreement at the time when payment is due; (iii) Tesoro fails to observe or perform any of its other covenants and obligations under Article II; (iv) Tesoro does not perform any act required or contemplated under this Agreement and: (a) the non-performance cannot be cured; (b) the nonperformance continues for more than thirty Days after the State has notified Tesoro of its nonperformance; or (c) Tesoro has failed to perform the same or any other act required or contemplated under this Agreement; 17 (v) There is a material adverse change in Tesoro's condition, business, or property which may appreciably affect its ability to perform any of its obligations under this Agreement and Tesoro is unable or unwilling to give the State adequate assurance of continued performance either within five Days of a request for such an assurance or within such other shorter time period as the State may request under the circumstances; (vi) Any representation or warranty made by Tesoro in this Agreement was materially false or incorrect when made; or (vii) Tesoro's failure or inability for any reason (including reasons beyond Tesoro's control) to maintain the Security described in Article XV, notwithstanding Tesoro's continuing willingness and ability to perform its other obligations and covenants under the Agreement. 7.2 Failure to Pay Debts. If Tesoro becomes unable to pay any of its debts when due, or should otherwise become insolvent (regardless how that insolvency may be evidenced), Tesoro will immediately give written notice of that fact to the State. Whether that notice is given, if Tesoro becomes unable to pay any of its debts when due or should otherwise become insolvent, the State's obligation to tender and sell Oil will automatically and immediately terminate without any requirement of notice or other action by the State; however, Tesoro will nevertheless be and remain liable for payment and performance of all of its obligations and covenants under this Agreement regarding Oil actually tendered by the State to and after any such termination. Within thirty Days after receipt of Tesoro's notice or, if no notice is given, after the State otherwise becomes aware (as 18 determined in the State's sole discretion) of Tesoro's insolvency, the State will have the right, upon written notice to Tesoro, to reinstate all of the State's and Tesoro's obligations under this Agreement retroactively to the date of termination. 7.3 State's Remedies. If any Event of Default occurs or if the State's obligation to tender and sell Oil under this Agreement is terminated or suspended, all of Tesoro's obligations accrued but not otherwise due and payable under this Agreement will immediately be due and payable in full. In addition, Tesoro will indemnify and hold the State harmless from and against all other liability, damages (including reasonably foreseeable consequential damages), costs, losses and expenses (including reasonable attorney's fees and disbursements) incurred by the State and arising out of the Event of Default, termination, or suspension. The State shall have the right cumulatively to exercise any and all other rights and remedies and to obtain all other relief available under applicable law or at equity, including mandatory injunction and specific performance. Additionally, in its sole discretion, the State, upon occurrence of any Event of Default: (1) may dispose to third parties any or all Royalty Oil to be tendered and sold under this Agreement and (2) may release Tesoro from the in-state processing obligations set forth in Article 2.12 until the Event of Default no longer exists or the obligation of Tesoro to take Oil under this Agreement expires. If the State disposes of Oil to third parties, or if Tesoro is released from Article 2.12, whether or not this Agreement is terminated, Tesoro will nevertheless remain liable for the difference between the purchase price for that Oil under this Agreement and the price received by the State by disposition, including all of the expenses (including reasonable attorneys' fees and costs), and losses incurred by the State arising out of the Event of Default or disposition. 19 7.4 Tesoro's Exclusive Remedies. Upon any breach of, or default in performance of any of the State's covenants or obligations under this Agreement, Tesoro agrees that its remedies will not include a temporary restraining order or preliminary injunction preventing the State from taking any action regarding the Royalty Oil which is the subject of this Agreement. ARTICLE VIII DISPOSITION OF OIL 8.1 Disposition of Oil Upon Default or Termination. Tesoro recognizes that the State may be required to give up to six Months notice to the Lessees (or ninety Days if the amount of increase or decrease is less than ten percent of the then current nominations or marine transportation is available) to increase or decrease the amount of Daily Royalty Oil to be taken in-kind. Tesoro agrees that the State's electing to invoke its rights to return to taking its Royalty Oil in-value on less than six Month's prior notice, or to attempt to secure a waiver of any condition or requirement, is at the State's sole discretion. Notwithstanding termination of this Agreement for any reason, Tesoro shall continue to take and purchase the State's Royalty Oil in the amount and for the price set forth in this Agreement for up to six Months following termination if the State, in its sole discretion, so requires. 8.2 Inability to Receive Oil. If for any reason, Tesoro is unable or refuses to accept or receive any Oil tendered under this Agreement, Tesoro shall nevertheless be and remain responsible for the disposal of that Oil and for paying the State for the Oil as though it had been received and accepted by Tesoro unless the State, in its sole discretion, elects to waive this requirement. To secure Tesoro's obligations under Article 8.2 and Article 2.9, Tesoro shall, if the State requests, assign or otherwise transfer to the State or its designee all or part right, title and interest 20 of Tesoro under any nominations, Leases, agreements, contracts, charter parties and other arrangements for the transportation of the Oil sold under this Agreement through and away from the TAPS; provided, that the State shall not have any liability or obligations under any such nominations, Leases, agreements, contracts, charter parties or other arrangement unless, and to the extent that, the State shall actually exercise its rights to succeed to Tesoro's interest under them and shall obtain the benefits of them. 8.3 No Right to Storage or Underlift. Tesoro waives and disclaims any interest or right that it may assert to storage of Royalty Oil, including by underlift or other means, to which the State is or may become to be entitled under the Leases or any other agreement. ARTICLE IX WAIVER The failure of either party to insist upon strict performance of any provision of this Agreement shall not constitute a waiver of, or estoppel against, asserting the right to require that performance in the future. A waiver or estoppel in any one instance shall not constitute a waiver or estoppel with respect to a later breach of a similar nature or otherwise. A course of performance established by a party shall also not estop the other party from complaining of a later breach similar in nature. 21 ARTICLE X VALIDlTY If any provision or clause of this Agreement or application of this Agreement is held invalid, that invalidity shall not affect other provisions or application of this Agreement which can be given effect without the invalid provision or application. If, however, an invalidity should operate to impair any material right or remedy of a party to this Agreement, that party may terminate this Agreement by notice to the other. ARTICLE XI FORCE MAJEURE AND CHANGE IN CONDITION 11.1 Effect of Force Majeure. Except for Tesoro's obligations to pay for Oil tendered and to accept and dispose of Royalty Oil, neither party shall be liable for any failure to perform when performance is prevented, in whole or in substantial part, by force majeure after good faith efforts to perform. The term 'force majeure" shall mean an event or condition not within the reasonable control of the party claiming the benefit of this excuse. If, however, any material obligation of Tesoro is excused or suspended by a force majeure for sixty successive Days or more, the State will have the right to terminate this Agreement. Before the State exercises its right to terminate, Tesoro and the State shall in good faith negotiate to restore the benefits and obligations of the force majeure condition. 11.2 Responsibility. If a party believes that force majeure has occurred, the party shall immediately notify the other party of its claim of force majeure. If force majeure occurs, that occurrence shall, so far as possible, be remedied with reasonable diligence. Except for Tesoro's 22 obligations to pay for Oil tendered and to accept and dispose of Oil, the disabled party's obligations to perform that are affected by the force majeure shall be suspended from the time that notification occurs until the disability should have been remedied with reasonable diligence, and for no longer. ARTICLE XII NOTICES 12.1 Method. All notices, requests, demands or statements shall be in writing, and may be delivered personally, telecopied, or sent by registered or certified United States mail, postage prepaid, with a return receipt requested, to the party to be notified. Notice deposited in the mail in this manner shall be effective upon the expiration of seven Days after it is so deposited or upon the date of receipt, whichever is earlier. Notice given in any other manner shall be effective only if and when received by the addressee. For the purposes of notice, the address of the parties shall be as follows: If to the State: State of Alaska Commissioner of Natural Resources 400 Willoughby Avenue Juneau,Alaska 99801 and Director, Division of Oil and Gas P. 0. Box 107034 Anchorage, Alaska 99510-0734 Telecopy Number: (907)562-3852 If to Tesoro: Gaylon H. Simmons Tesoro Alaska Petroleum Company 8700 Tesoro Drive San Antonio, Texas 78217 Telecopy Number: (210) 283-2031 23 12.2 Change of Address. Each party may change its address for notice by giving written notice of the change. ARTICLE XIII RULES AND REGULATIONS This Agreement is subject to all present and future valid laws, orders, rules and regulations of the United States, the State of Alaska, and any duly constituted agency of the State of Alaska. ARTICLE XIV SOVEREIGN POWER OF THE STATE This Agreement shall not be interpreted as a limit on the State of Alaska's exercise of any of its sovereign or regulatory powers, whether conferred by constitution, statute or regulation, including, but not limited to, its regulatory power over the Leases. Its exercise of any sovereign or regulatory power will not operate or be deemed to enlarge any rights of Tesoro or to limit or impair any obligations or liability of Tesoro under this Agreement. ARTICLE XV SECURITY 15.1 Letter of Credit. Seventy five Days before the Date of First Delivery, Tesoro shall cause to be issued and delivered to the State an irrevocable stand-by letter of credit, with an effective date no later than the Date of First Delivery, issued for the benefit of the State by a State or 24 national banking institution of the United States ("Issuer"), which is insured by the Federal Deposit Insurance Corporation and has an aggregate capital and surplus of not less than One Hundred Million Dollars ($100,000,000), or other banking institution acceptable to the State in its sole discretion. The principal face amount of such letter of credit shall be a sum estimated by the Commissioner, in his sole discretion, to be equal to the aggregate purchase price for the approximate total amount of Oil to be tendered by the State to Tesoro during the first seventy five Days following the Date of First Delivery. The letter of credit shall be in a form satisfactory to the Commissioner, but in any event shall not require any documents to be submitted in support of drafts drawn against this letter of credit other than the certified statement of the Commissioner or his designee and the Attorney General of the State of Alaska or his designee that Tesoro is liable to the State for a sum equal to the amount of such draft, and that sum is due and payable in full and has not been timely paid. The letter of credit must be renewed seventy five Days before its expiration so that a letter of credit is continuously valid for seventy five Days after the date of the last delivery of Royalty Oil. If a replacement letter of credit, in a form satisfactory to the Commissioner in his sole discretion, is not received seventy five Days before the expiration of the existing letter of credit, then Tesoro shall be deemed to have materially breached this Agreement, there shall have occurred an event of default under Article 7.1, and all obligations of Tesoro accrued, but not otherwise due and payable under this Agreement, will immediately become due and payable in full. If the State has reasonable grounds for asserting any claims against Tesoro and does assert those claims in an aggregate amount in excess of the aggregate principal face amount of the letter of credit then in effect, Tesoro shall, upon the State's request (whether or not Tesoro may deny, reject or otherwise resist such claims), cause the principal face amount to be increased by an amount 25 equal to the excess. Tesoro shall also automatically increase the principal face amount, without request from the State, whenever the face amount is less than the expected purchase price of seventy five Days of Oil tenders, to an amount equal to the expected purchase price of seventy five Days of Oil tenders. Upon approval of the State in its sole discretion, Tesoro may decrease the principal face amount if the face amount is more than the expected purchase price of seventy five Days of Oil tenders to an amount equal to the expected purchase price of seventy five Days of Oil tenders. The letter of credit must allow drafts to be drawn and presented to the Issuer up to and including the 75th Day after the last delivery of Royalty Oil to Tesoro under this Agreement. The Commissioner may accept such other or additional security as he, in his sole discretion, considers adequate to protect the State. 15.2 Reduction of Term. The term of the letter of credit required under Article XV shall be reduced from seventy five Days to sixty Days, if Tesoro and the State can reach an agreement regarding the transportation of Oil if Tesoro defaults under this Agreement. If the parties cannot reach an agreement, then the letter of credit shall remain at seventy five Days or Tesoro shall have the right, in its sole discretion, to terminate this Agreement as provided in Article 2.1. ARTICLE XVI PREFERENTIAL HIRING AND NON-DISCRIMINATION Tesoro agrees to employ Alaska residents and Alaska companies to the extent they are available, willing and qualified for all work performed in Alaska in connection with the Agreement. "Alaska resident" means an individual who has resided in Alaska for one year at the time of 26 employment and "Alaska companies" means companies incorporated in Alaska or whose principal place of business is in Alaska. If this provision is determined to be unconstitutional, then Tesoro agrees to employ Alaska residents and Alaska companies to the extent such preferential hiring is determined to be constitutional. ARTICLE XVII APPLICABLE LAW 17.1 Alaska Law. This Agreement shall be governed by and construed in accordance with the laws of the State of Alaska. 17.2 Submission to Jurisdiction. Any legal action or proceeding arising out of or relating to this Agreement or for the enforcement of the covenants or obligations of either party must be instituted in a State court of general jurisdiction sitting in the State of Alaska, and Tesoro hereby irrevocably submits to the jurisdiction of that court in any such action or proceeding. ARTICLE XVIII WARRANTIES The purchase and sale of Royalty Oil are subject only to the warranties of the State expressly set forth in this Agreement and the State disclaims and Tesoro waives all other warranties, express or implied in law, whatsoever. 27 ARTICLE XIX AMENDMENT This Agreement may be supplemented, amended, or modified only by written instrument duly executed by the parties. ARTICLE XX SUCCESSORS AND ASSIGNS No assignment, pledge, or encumbrance of this Agreement shall be made by either party without the written consent of the other party. The Commissioner or the Commissioner's designee may grant or deny such consent. Subject to the above requirements in this article, this Agreement will be binding upon and inure to the benefit of each of the parties and its successors and permitted assignees. ARTICLE XXI HEADINGS Headings used in this Agreement are for convenience only and shall not affect its construction. ARTICLE XXII RECORDS 22.1 Preservation of Records. Tesoro will preserve and maintain all books, accounts, and records relating to or arising out of the performance of this Agreement including, but 28 not limited to, the purchase or sale of Royalty Oil and its refined products, for a period of no less than six years from the date of transaction or last adjustment relating to the transaction. Tesoro will also maintain and preserve all similar books, accounts, and records of which it has possession belonging to those third parties with whom it contracts for the performance of various parts of this Agreement. Neither Tesoro nor the State shall be required to retain any records for more than six years unless retention of such records is specifically required by applicable law or regulation, or this Agreement. Tesoro shall either maintain its records within the State of Alaska or make such records available to the State at Tesoro's principal office in the State of Alaska within thirty Days after written request by the State. 22.2 Inspection of Records of Parties. Tesoro and the State will accord to each other and to their authorized agents, attorneys, and auditors during reasonable business hours access to any and all property, records, books, documents, and indices directly related to Tesoro's or the State's performance of this Agreement and which are under the control of the party from which access is desired so that the other party may inspect, photograph and make copies of that property, records, books, documents and indices. The State shall not be required to disclose any information, data, or records which are required to be held confidential by State or federal law or regulation, or by agreement. If the information obtained by the State may be held confidential under State or federal law or regulation, Tesoro may request that information be held confidential by the State and the State will keep this information confidential. 29 ARTICLE XXIII INTERPRETATION OF TERMS AND CONDITIONS Any disagreement about the meaning or application of a word, term, or condition in this Agreement will be decided according to the dispute resolution procedure set forth in this article. Either party may give the other written notice of a disagreement. Within 60 days after written notice, Tesoro must present any argument and evidence supporting its view in writing to the Commissioner for consideration. Tesoro shall not have the right to civil litigation-type discovery or a civil litigation-type trial with the right to call or cross-examine witnesses unless granted by the Commissioner in his sole discretion. The Commissioner will subsequently issue a finding on the meaning or application of the disputed word, term, or condition, setting forth the basis for the conclusions. Tesoro agrees to accept findings by the Commissioner under this article which are supported by substantial evidence. ARTICLE XXIV COUNTERPARTS This Agreement may be executed in multiple counterparts, the parties need not sign the same counterpart. Each counterpart shall be deemed to be an original and all of which taken together shall be one and the same instrument. 30 SIGNATURES the State: THE STATE OF ALASKA /s/ John T. Shively Commissioner Department of Natural Resources Date: April 21, 1995 Tesoro Alaska Petroleum Company: TESORO ALASKA PETROLEUM COMPANY By: /s/ Gaylon H. Simmons Its: Executive Vice President Date: April 20, 1995 Tesoro Petroleum Company: TESORO PETROLEUM COMPANY By: /s/ Gaylon H. Simmons Its: Executive Vice President Date: April 20, 1995 31 ACKNOWLEDGEMENT State of Alaska ) ) ss. Third Judicial District ) THIS IS TO CERTIFY that on the 21 day of April, 1995, before me, appeared John T. Shively, the commissioner, Department of Natural Resources, State of Alaska; that Harry A. Noah executed that document under legal authority and with knowledge of its contents; and that this act was performed freely and voluntarily upon the premises and for the purposes stated in the document. Witness my hand and official seal the day and year in this agreement first above written. /s/ Sharon Fromming Notary Public in and for Alaska My commission expires: 5-24-95 32 ACKNOWLEDGEMENT State of Texas ) ) ss. County of Bexar) THIS IS TO CERTIFY that on the 20th day of April, 1995, before me, appeared Gaylon H. Simmons of Tesoro Alaska Petroleum Company, San Antonio, Texas; that Gaylon H. Simmons executed that document under legal authority and with knowledge of its contents; and that this act was performed freely and voluntarily upon the premises and for the purposes stated in the document. Witness my hand and official seal the day and year in this agreement first above written. /s/ Linda Iden My commission expires: March 27, 1999 33 ACKNOWLEDGEMENT State of Texas ) ) ss. County of Bexar) THIS IS TO CERTIFY that on the 20th day of April, 1995, before me, appeared Gaylon H. Simmons of Tesoro Petroleum Company, San Antonio, Texas; that Gaylon H. Simmons executed that document under legal authority and with knowledge of its contents; and that this act was performed freely and voluntarily upon the premises and for the purposes stated in the document. Witness my hand and official seal the day and year in this agreement first above written. /s/ Linda Iden My commission expires: March 27, 1999 34 EXHIBIT A CALCULATION OF ROYALTY VALUE This exhibit shows the mechanics of the price calculation and data sources. Exxon's Royalty Value for the Prudhoe Bay Unit lessees are taken from its Royalty Report. Royalty Value currently is taken from Column H of these reports. An example calculation using the information for January 1995 and a hypothetical RIK volume sold to Tesoro is shown below. Attached are the Royalty Report Summaries for the Prudhoe Bay Unit. Exxon's Production Royalty Value Product of Volume Times from the Prudhoe from Column H Royalty Value Bay Unit of the Oil Royalty Report Summary Lisburne Production 1,762,900.13 x $11.050 = $19,480,406.44 Center Prudhoe Bay IPA 8,807,215.20 x $11.110 = $97,848,160.87 ------------- --------------- Total 10,570,115.33 $117,328,207.31 Exxon's Royalty Value = $117,328,207.31 - 10,570,115.33 = $11.09999 Should Article 2.1(b) apply, the Royalty Value will be calculated using the Royalty Value and production volumes for only the initial Participating Areas. CALCULATION OF INTEREST Numbers in these examples are illustrative. They do not represent accurate values that may have existed in the past or are forecasted for any time in the future. Mechanics of the calculations include: 1. The annual interest rate specified in legislation is converted to a daily rate for calculations. 2. Credits are applied to the next monthly payment. Payment for an underpayment is due (a) within 3 business of the date the bill is sent for Initial Billings and initial adjustment or (b) within 30 days of the time the bill is sent for subsequent adjustments. Interest on overpayments stops accruing on the date of the invoice. 35 Example 1: Initial Billing Assumptions: 1. Month is February. 2. Royalty Oil delivered to Tesoro in January = 1,240,000 barrels. 3. Royalty Value for January, from Column H of Exxon's Oil Royalty Report Summaries (attached) = $11.09999. 4. Bill sent to Tesoro on February 1st; Payment due to State by February 6th (Initial Billing date plus three business days. Method for calculating Tesoro's initial invoice for January deliveries: Volume x Price = Initial Billing 1,240,000 x $11.09999 = $13,763,987.60 Note: The lessees are required to submit their royalty reports to the State for January's production by the last day in February. For this reason the State will bill Tesoro for January production based on the December Royalty Value. This is an interim value and is subject to revision, since the Agreement requires that Tesoro pay the Monthly Price for the same production month. The revised price is incorporated in the invoice submitted the following month (March). 36 Example 2: Initial Adjustment Assumptions: 1. Month is March. 2. Royalty Oil delivered to Tesoro in January = 1,240,000 barrels. 3. Revised Monthly Price for January = $11.00000. 4. Annual interest rate charged member banks for advances by 12th Federal Reserve District as of January 1st is three percent. Annual rate for contract = 11 percent. 5. Date of Initial Adjustment is March 1st. Method for calculating Tesoro's revised invoice for January deliveries: Volume x Price = Revised Billing 1,240,000 x $11.00000 = $13,640,000.00 Amount Paid by Tesoro for January deliveries (calculated in Example 1): $13,763,987.60 -------------- Overpayment for January: ($123,987.60) Difference between Initial Adjustment date (March 1st) and original accrual date (February 6th) = 23 days. Interest due = $123,987.60 x (11%/365) x 23 = ($859.42) -------------- Credit due Tesoro for next month's billing = ($124,847.02) 37 Example 3: Subsequent Adjustment This adjustment is assumed to occur after true-up of BP transportation costs, a reopener for one of the Royalty Settlement Agreements, or for some other reason. It is assumed to occur June 5th. Assumptions: 1. Month is June. 2. Royalty Oil delivered to Tesoro in January = 1,240,000 barrels. 3. Adjusted Monthly Price for January = $11.11000. 4. Annual interest rate charged member banks for advances by 12th Federal Reserve District as of January 1 assumed to be three percent; as of April 1 and through the third quarter, seven percent. Annual interest rate for contract = 11 percent for the first quarter; 12 percent for the second and third quarter. 5. Tesoro is sent notice of underpayment on June 5th. 6. Tesoro's payment is received on July 5th. Method for calculating Tesoro's revised invoice for January deliveries: Volume x Price = Revised Billing 1,240,000 x $11.11000 = $13,776,400.00 Amount Paid by Tesoro for January deliveries (calculated in Example 2): $13,640,000.00 -------------- Underpayment for January deliveries: $136,400.00 Days of interest in first quarter (Initial Billing date plus 3 business days through March 3 1st)=53 Days of interest in second quarter (April 1 through June 30th)=91 Days of interest in third quarter (July 1 through July 5)=5 Interest for first quarter = $136,400.00 x (11%/365) x 53 = $2,178.66 Interest for second quarter = ($136,400.00 + $2,178.66) x (12%/365) x 91 = $4,145.97 Interest for third quarter =($136,400.00 + $2,178.66 + $4,145.97) x (12%/365) x 5 = $234.62 Payment from Tesoro due to the State within 30 days of invoice date = $142,959.25 If payment in full not received by or on July 5th then additional interest will accrue from July 6th through the payment receipt date, plus a late payment penalty will be assessed. 38 The items omitted are a seven page sample summary report which gives examples of the calculations referred to above. EX-11 4 EARNINGS PER SHARE COMPUTATIONS Exhibit 11 TESORO PETROLEUM CORPORATION AND SUBSIDIARIES INFORMATION SUPPORTING EARNINGS (LOSS) PER SHARE COMPUTATIONS (Unaudited) (In thousands except per share amounts)
Three Months Ended Six Months Ended June 30, June 30, ------------------ ---------------- 1995 1994 1995 1994 ---- ---- ---- ---- PRIMARY EARNINGS (LOSS) PER SHARE COMPUTATION: Earnings before extraordinary item. . . . $ 7,456 1,230 9,216 8,432 Extraordinary loss on extinguishment of debt . . . - - - ( 4,752) --------- --------- --------- --------- Net earnings . . . . . . . . . 7,456 1,230 9,216 3,680 Less dividend requirements on preferred stocks . . - 791 - 2,680 --------- --------- --------- --------- Net earnings applicable to common stock $ 7,456 439 9,216 1,000 ========= ========= ========= ========= Average outstanding common shares. 24,538 22,525 24,525 20,688 Average outstanding common equivalent shares . . . 668 697 638 662 --------- --------- --------- --------- Average outstanding common and common equivalent shares . . . . . 25,206 23,222 25,163 21,350 ========= ========= ========= ========= Primary Earnings (Loss) Per Share: Earnings before extraordinary item. . . $ .30 .02 .37 .27 Extraordinary loss on extinguishment of debt . . - - ( .22) --------- --------- --------- --------- Net earnings . . . . . . . $ .30 .02 .37 .05 ========= ========= ========= ========= FULLY DILUTED EARNINGS (LOSS) PER SHARE COMPUTATION: Net earnings applicable to common stock . $ 7,456 439 9,216 1,000 Add dividend requirements on preferred stocks. . . - 791 - 2,680 --------- --------- --------- --------- Net earnings applicable to common stock - fully diluted . . $ 7,456 1,230 9,216 3,680 ========= ========= ========= ========= Average outstanding common and common equivalent shares . . . . . . 25,206 23,222 25,163 21,350 Shares issuable on conversion of preferred shares. - 2,473 - 2,976 --------- --------- --------- --------- Fully diluted shares. . . . . 25,206 25,695 25,163 24,326 ========= ========= ========= ========= Fully Diluted Earnings Per Share - Anti-dilutive$ .30 .02 .37 .05 ========= ========= ========= ========= This calculation is submitted in accordance with paragraph 601(b)(11) of Regulation S-K although it is not required by APB Opinion No. 15 because it produces an anti-dilutive result.
EX-27 5 FINANCIAL DATA SCHEDULE
5 THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM TESORO PETROLEUM CORPORATION'S FINANCIAL STATEMENTS AS OF AND FOR THE SIX MONTH PERIOD ENDED JUNE 30, 1995, AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL STATEMENTS. 1,000 6-MOS DEC-31-1995 JUN-30-1995 7,356 0 101,832 1,962 62,357 183,244 514,331 228,708 502,602 100,293 189,096 0 0 4,090 167,027 502,602 499,830 500,039 445,112 445,112 23,327 0 10,661 11,349 2,133 9,216 0 0 0 9,216 .37 .37