-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: keymaster@town.hall.org Originator-Key-Asymmetric: MFkwCgYEVQgBAQICAgADSwAwSAJBALeWW4xDV4i7+b6+UyPn5RtObb1cJ7VkACDq pKb9/DClgTKIm08lCfoilvi9Wl4SODbR1+1waHhiGmeZO8OdgLUCAwEAAQ== MIC-Info: RSA-MD5,RSA, YQ6Bwr3HhvaivChvkanmkl5UkXwFAx9/1QsoMwMif2N3P6iRIM7pNrqoZn83euj4 xA6Q+sfXjcu/N/umGT1X2Q== 0000050104-95-000004.txt : 19950516 0000050104-95-000004.hdr.sgml : 19950516 ACCESSION NUMBER: 0000050104-95-000004 CONFORMED SUBMISSION TYPE: 10-Q PUBLIC DOCUMENT COUNT: 3 CONFORMED PERIOD OF REPORT: 19950331 FILED AS OF DATE: 19950515 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: 95539401 BUSINESS ADDRESS: STREET 1: 8700 TESORO DR CITY: SAN ANTONIO STATE: TX ZIP: 78217 BUSINESS PHONE: 2108288484 10-Q 1 10Q FOR QUARTER ENDED 3/31/95 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 March 31, 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 24,538,167 shares of the Registrant's Common Stock outstanding at April 30, 1995. TESORO PETROLEUM CORPORATION AND SUBSIDIARIES INDEX TO FORM 10-Q FOR THE QUARTERLY PERIOD ENDED MARCH 31, 1995 PART I. FINANCIAL INFORMATION Page Item 1. Financial Statements (Unaudited) Condensed Consolidated Balance Sheets - March 31, 1995 and December 31, 1994 . . . . . . . . . . . . . . . . . . . . . . . 3 Condensed Statements of Consolidated Operations - Three Months Ended March 31, 1995 and 1994. . . . . . . . . . . . . . . . . . . . . . 4 Condensed Statements of Consolidated Cash Flows - Three Months Ended March 31, 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 . . . . . . . . . . . . . . . . . . . . . . 21 Item 6. Exhibits and Reports on Form 8-K. . . . . . . . . . . . . . . 23 SIGNATURES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24 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) March 31, December 31, 1995 1994* ---- ---- ASSETS CURRENT ASSETS: Cash and cash equivalents . . . . . . . . . . . . . $ 5,550 14,018 Receivables, less allowance for doubtful accounts of $1,876 ($1,816 at December 31, 1994) . . . . . 86,376 91,140 Inventories: Crude oil and wholesale refined products, at LIFO 66,263 58,798 Merchandise and retail refined products . . . . . 5,689 5,934 Materials and supplies. . . . . . . . . . . . . . 3,774 3,570 Prepaid expenses and other. . . . . . . . . . . . . 8,256 8,648 --------- --------- Total Current Assets. . . . . . . . . . . . . . . 175,908 182,108 PROPERTY, PLANT AND EQUIPMENT, Net of Accumulated Depreciation, Depletion and Amortization of $217,699 ($205,782 at December 31, 1994) . . . . . . . . . . 280,717 273,334 INVESTMENT IN TESORO BOLIVIA PETROLEUM COMPANY . . . 11,544 10,295 OTHER ASSETS . . . . . . . . . . . . . . . . . . . . 20,864 18,623 --------- --------- TOTAL ASSETS . . . . . . . . . . . . . . . . $489,033 484,360 ========= ========= LIABILITIES AND STOCKHOLDERS' EQUITY CURRENT LIABILITIES: Accounts payable. . . . . . . . . . . . . . . . . . $ 58,509 53,573 Accrued liabilities . . . . . . . . . . . . . . . . 27,477 35,266 Current portion of long-term debt and other obligations. . . . . . . . . . . . . . . . . . . . 8,107 7,404 --------- --------- Total Current Liabilities . . . . . . . . . . . . 94,093 96,243 --------- --------- DEFERRED INCOME TAXES. . . . . . . . . . . . . . . . 4,494 4,582 --------- --------- OTHER LIABILITIES. . . . . . . . . . . . . . . . . . 36,806 30,593 --------- --------- LONG-TERM DEBT AND OTHER OBLIGATIONS, LESS CURRENT PORTION . . . . . . . . . . . . . . . . . . 189,995 192,210 --------- --------- COMMITMENTS AND CONTINGENCIES (Note 3) STOCKHOLDERS' EQUITY: Common Stock, par value $.16-2/3; authorized 50,000,000 shares; 24,538,167 shares issued and outstanding (24,389,801 in 1994). . . . . . . 4,090 4,065 Additional paid-in capital. . . . . . . . . . . . . 176,642 175,514 Accumulated deficit . . . . . . . . . . . . . . . . ( 17,087) ( 18,847) --------- --------- Total Stockholders' Equity. . . . . . . . . . . . 163,645 160,732 --------- --------- TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY . $ 489,033 484,360 ========= ========= 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 March 31, ----------------------- 1995 1994 ---- ---- REVENUES: Gross operating revenues. . . . . . . . . . . . . . $234,701 189,087 Interest income . . . . . . . . . . . . . . . . . . 236 523 Gain on sales of assets . . . . . . . . . . . . . . 7 2,680 Other . . . . . . . . . . . . . . . . . . . . . . . 81 450 --------- --------- Total Revenues. . . . . . . . . . . . . . . . . . 235,025 192,740 --------- --------- COSTS AND EXPENSES: Costs of sales and operating expenses . . . . . . . 210,611 167,605 General and administrative. . . . . . . . . . . . . 3,814 3,627 Depreciation, depletion and amortization. . . . . . 11,915 6,677 Interest expense. . . . . . . . . . . . . . . . . . 5,293 4,877 Other . . . . . . . . . . . . . . . . . . . . . . . 922 1,191 --------- --------- Total Costs and Expenses. . . . . . . . . . . . . 232,555 183,977 --------- --------- EARNINGS BEFORE INCOME TAXES AND EXTRAORDINARY LOSS ON EXTINGUISHMENT OF DEBT. . . . . . . . . . . 2,470 8,763 Income Tax Provision . . . . . . . . . . . . . . . . 710 1,561 --------- --------- EARNINGS BEFORE EXTRAORDINARY LOSS ON EXTINGUISHMENT OF DEBT. . . . . . . . . . . . . . . 1,760 7,202 Extraordinary Loss on Extinguishment of Debt . . . . - ( 4,752) --------- --------- NET EARNINGS . . . . . . . . . . . . . . . . . . . . 1,760 2,450 Dividend Requirements on Preferred Stocks. . . . . . - 1,889 --------- --------- NET EARNINGS APPLICABLE TO COMMON STOCK. . . . . . . $ 1,760 561 ========= ========= EARNINGS (LOSS) PER PRIMARY AND FULLY DILUTED* SHARE: Earnings Before Extraordinary Loss on Extinguishment of Debt. . . . . . . . . . . . . . . $ .07 .27 Extraordinary Loss on Extinguishment of Debt. . . . - ( .24) --------- --------- Net Earnings. . . . . . . . . . . . . . . . . . . . $ .07 .03 ========= ========= AVERAGE OUTSTANDING COMMON AND COMMON EQUIVALENT SHARES . . . . . . . . . . . . . . . . . 25,119 19,455 ========= ========= *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) Three Months Ended March 31, ---------------------- 1995 1994 ---- ---- CASH FLOWS FROM (USED IN) OPERATING ACTIVITIES: Net earnings . . . . . . . . . . . . . . . . . . . $ 1,760 2,450 Adjustments to reconcile net earnings to net cash from operating activities: Depreciation, depletion and amortization. . . . . 11,915 6,677 Loss on extinguishment of debt. . . . . . . . . . - 4,752 Gain on sales of assets . . . . . . . . . . . . .( 7) ( 2,680) Amortization of deferred charges and other, net . 447 361 Changes in assets and liabilities: Receivables . . . . . . . . . . . . . . . . . . 4,764 11,151 Inventories . . . . . . . . . . . . . . . . . . ( 7,223) ( 1,217) Investment in Tesoro Bolivia Petroleum Company . ( 1,249) ( 513) Other assets . . . . . . . . . . . . . . . . . . 621 1,834 Accounts payable and other current liabilities . ( 1,417) 8,272 Obligation payments to State of Alaska . . . . . ( 629) ( 710) Other liabilities and obligations . . . . . . . 1,601 ( 118) --------- --------- Net cash from operating activities . . . . . 10,583 30,259 --------- --------- CASH FLOWS FROM (USED IN) INVESTING ACTIVITIES: Capital expenditures . . . . . . . . . . . . . . . (16,527) (18,475) Acquisition of Kenai Pipe Line Company and other. . ( 3,000) 351 Proceeds from sales of assets . . . . . . . . . . . 1,011 2,014 Sales of short-term investments . . . . . . . . . . - 5,952 --------- --------- Net cash used in investing activities . . . . (18,516) (10,158) --------- --------- CASH FLOWS FROM (USED IN) FINANCING ACTIVITIES: Repayments, net of borrowings of $52,000 in 1995 and $5,000 in 1994, under revolving credit facilities . . . . . . . . . . . . . . . . - ( 5,000) Payments of long-term debt. . . . . . . . . . . . . ( 545) ( 222) Dividends on preferred stocks . . . . . . . . . . . - ( 103) Costs of recapitalization and other. . .. . . . . . 10 ( 1,960) --------- --------- Net cash used in financing activities . . . . ( 535) ( 7,285) --------- --------- INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS ( 8,468) 12,816 CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 14,018 36,596 --------- --------- CASH AND CASH EQUIVALENTS AT END OF PERIOD . . . . . $ 5,550 49,412 ========= ========= SUPPLEMENTAL CASH FLOW DISCLOSURES: Interest paid . . . . . . . . . . . . . . . . . . . $ 5,359 7,105 ========= ========= Income taxes paid . . . . . . . . . . . . . . . . . $ 805 961 ========= ========= 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) 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 (the "Tennessee Gas Contract") which provides that the price of gas shall be the maximum price as calculated in accordance with Section 102(b)(2) (the "Contract Price") of the Natural Gas Policy Act of 1978 (the "NGPA"). 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 March 1995, the Contract Price was in excess of $8.00 per Mcf, the Section 101 price was $4.88 per Mcf and the average spot market price was $1.34 per Mcf. Tennessee Gas also claimed that the contract should be considered an "output contract" under Section 2.306 of the Texas Business and Commerce Code 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 Supreme Court of Texas heard arguments in December 1994 regarding the output contract issue and certain of the issues raised by Tennessee Gas but has not yet issued its opinion. Although the outcome of any litigation is uncertain, management, based upon advice from outside legal counsel, is confident that the decision of the trial and appellate courts will ultimately be upheld as to the validity of the Tennessee Gas Contract and the Contract Price. If the Supreme Court of Texas were to affirm the appellate court ruling, the Company believes that the only issue for trial should be whether the increases in the volumes of gas tendered to Tennessee Gas from the Company's properties were made in bad faith or were unreasonably disproportionate. The appellate court decision was the first reported decision in Texas holding that a take-or-pay contract was an output contract. As a result, it is not clear what standard the trial court would be required to apply in determining whether the increases were in bad faith or unreasonably disproportionate. The appellate court acknowledged in its opinion that the standards 6 used in evaluating other kinds of output contracts would not be appropriate in this context. The Company believes that the appropriate standard would be whether the development of the field was undertaken in a manner that a prudent operator would have undertaken in the absence of an above-market sales price. Under that standard, the Company believes that, if this issue is tried, the development of the Company's gas properties and the resulting increases in volumes tendered to Tennessee Gas will be found to have been reasonable and in good faith. Accordingly, the Company has recognized revenues, net of production taxes and marketing charges, for natural gas sales through March 31, 1995, under the Tennessee Gas Contract based on the Contract Price, which net revenues aggregated $44.3 million more than the Section 101 prices and $84.4 million in excess of the spot market prices. If Tennessee Gas were ultimately to prevail in this litigation, the Company could be required to return to Tennessee Gas $52.5 million, plus interest if awarded by the court, representing the difference between the spot market price and the Contract Price received by the Company through September 17, 1994 (the date on which the Company entered into a bond agreement discussed below). An adverse judgment in this case could have a material adverse effect on the Company. 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 ("the "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. The Company continues to recognize revenues under the Tennessee Gas Contract based on the Contract Price. At March 31, 1995, the Company had recognized cumulative revenues in excess of spot market prices (through September 17, 1994) and in excess of the Bond Price (subsequent to September 17, 1994) totaling $77.2 million. Receivables at March 31, 1995 included $26.6 million from Tennessee Gas, of which $24.7 million represented the difference between the Contract Price and the Bond Price. 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 and a drum recycling site in Grand Junction, Colorado, at which sites 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 sites, the extent of the Company's allocated financial contributions to the cleanup of these sites is expected to be limited based upon the number of companies and the volumes of waste involved. The Company believes that its liability at the Louisiana 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 believes that its liability at the Colorado site will be less than $1,500 (see Legal Proceedings in Part II, Item 1). 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 (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 7 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 proposed a penalty assessment of approximately $3.7 million. The Company is continuing to negotiate with the DOJ but cannot predict the ultimate outcome of the negotiations. At March 31, 1995, the Company's accruals for environmental matters, including the alleged violations of the Clean Air Act, amounted to $11.7 million. Also included in this amount is a $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. 8 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 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. The Company cannot predict the ultimate resolution of this matter but believes the claim is without merit. 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. The Company's average spot market sales price was $1.42 per Mcf during the three months ended March 31, 1995. 9 Item 2. TESORO PETROLEUM CORPORATION AND SUBSIDIARIES MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS RESULTS OF OPERATIONS - THREE MONTHS ENDED MARCH 31, 1995 COMPARED TO THREE MONTHS ENDED MARCH 31, 1994 A consolidated summary of the Company's operations for the three months ended March 31, 1995 and 1994 is presented below (in millions except per share amounts): Three Months Ended March 31, ------------------ 1995 1994 ---- ---- Summary of Operations Segment Operating Profit (Loss)*: Refining and Marketing. . . . . . . . . . . . . . . . . . $( 4.6) 6.4 Exploration and Production - United States. . . . . . . . 16.6 11.2 Exploration and Production - Bolivia . . . . . . . . . . 1.7 1.9 Oil Field Supply and Distribution . . . . . . . . . . . . ( 1.3) ( 1.2) --------- --------- Total Segment Operating Profit. . . . . . . . . . . . . 12.4 18.3 Corporate and Unallocated Costs: Interest expense. . . . . . . . . . . . . . . . . . . . . 5.3 4.9 Interest income . . . . . . . . . . . . . . . . . . . . . ( .2) ( .5) General and administrative expenses . . . . . . . . . . . 3.8 3.6 Other . . . . . . . . . . . . . . . . . . . . . . . . . . 1.0 1.5 --------- --------- Earnings Before Income Taxes and Extraordinary Loss. . . . 2.5 8.8 Income Tax Provision . . . . . . . . . . . . . . . . . . . .7 1.6 --------- --------- Earnings Before Extraordinary Loss . . . . . . . . . . . . 1.8 7.2 Extraordinary Loss on Extinguishment of Debt . . . . . . . - ( 4.8) --------- --------- Net Earnings . . . . . . . . . . . . . . . . . . . . . . . 1.8 2.4 Dividend Requirements on Preferred Stocks. . . . . . . . . - 1.9 --------- --------- Net Earnings Applicable to Common Stock. . . . . . . . . . $ 1.8 .5 ========= ========= Earnings (Loss) per Primary and Fully Diluted** Share: Earnings Before Extraordinary Loss. . . . . . . . . . . . $ .07 .27 Extraordinary Loss on Extinguishment of Debt. . . . . . . - ( .24) --------- --------- Net Earnings. . . . . . . . . . . . . . . . . . . . . . . $ .07 .03 ========= ========= * 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 $1.8 million, or $.07 per share, for the three months ended March 31, 1995 ("1995 quarter") compare with net earnings applicable to common stock of $.5 million, or $.03 per share, for the three months ended March 31, 1994 ("1994 quarter"). Net earnings for the 1994 quarter were reduced by $1.9 million of dividend requirements on preferred stock. Also included in the 1994 quarter was a noncash extraordinary loss of $4.8 million, or $.24 per share, attributable to the early extinguishment of debt in connection with a recapitalization in early 1994. Earnings before the extraordinary loss were $7.2 million, or $.27 per share, for the 1994 quarter. The 1994 quarter was favorably impacted by a gain of $2.8 million, or $.14 per share, from the sale of assets. When comparing the 1995 quarter to the 1994 quarter, the decrease in net earnings was primarily due to the impact of weak market conditions on the Company's refining and marketing segment and low 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. 10 Refining and Marketing Three Months Ended March 31, --------------------- 1995 1994 ---- ---- (Dollars in millions except per barrel amounts) Gross Operating Revenues: Refined products. . . . . . . . . . . . . . . . . $ 153.6 119.3 Other, primarily crude oil resales and merchandise 31.5 31.0 --------- --------- Gross Operating Revenues. . . . . . . . . . . . $ 185.1 150.3 ========= ========= Operating Profit (Loss): Gross margin - refined products . . . . . . . . . $ 15.1 23.5 Gross margin - other . . . . . . . . . . . . . . 2.5 2.6 --------- --------- Gross margin. . . . . . . . . . . . . . . . . . 17.6 26.1 Operating expenses. . . . . . . . . . . . . . . . 19.2 19.9 Depreciation and amortization . . . . . . . . . . 3.0 2.6 Other, including gain on asset sales . . . . . . - ( 2.8) --------- --------- Operating Profit (Loss) . . . . . . . . . . . . $( 4.6) 6.4 ========= ========= Capital Expenditures . . . . . . . . . . . . . . . $ 2.3 6.1 ========= ========= Refining and Marketing Total Product Sales (average daily barrels)*: Gasoline. . . . . . . . . . . . . . . . . . . . . 23,328 22,570 Middle distillates. . . . . . . . . . . . . . . . 38,219 26,802 Heavy oils and residual product . . . . . . . . . 13,817 16,446 --------- --------- Total Product Sales . . . . . . . . . . . . . . 75,364 65,818 ========= ========= Refining and Marketing Product Sales Prices ($/barrel): Gasoline. . . . . . . . . . . . . . . . . . . . . $ 26.84 24.36 Middle distillates. . . . . . . . . . . . . . . . $ 23.68 23.92 Heavy oils and residual product . . . . . . . . . $ 12.65 8.22 Refining and Marketing - Gross Margins on Total Product Sales*: Average sales price . . . . . . . . . . . . . . . $ 22.63 20.15 Average cost of sales . . . . . . . . . . . . . . 20.41 16.18 --------- --------- Gross margin. . . . . . . . . . . . . . . . . . . $ 2.22 3.97 ========= ========= Refinery Operations - Throughput (average daily barrels) . . . . . . . . . . . . . . . . . . . . 45,572 45,320 ========= ========= Refinery Operations - Production (average daily barrels): Gasoline . . . . . . . . . . . . . . . . . . . . 12,770 11,977 Middle distillates. . . . . . . . . . . . . . . . 19,687 17,851 Heavy oils and residual product . . . . . . . . . 12,424 15,407 Refinery fuel . . . . . . . . . . . . . . . . . . 2,027 1,737 --------- --------- Total Refinery Production . . . . . . . . . . . 46,908 46,972 ========= ========= Refinery Operations - Product Spread ($/barrel)*: Average yield value of products produced. . . . . $ 19.70 17.35 Cost of raw materials . . . . . . . . . . . . . . 16.75 12.31 --------- --------- Spread. . . . . . . . . . . . . . . . . . . . . $ 2.95 5.04 ========= ========= 11 * 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. During the 1995 and 1994 quarters, the Company purchased for resale approximately 26,500 and 19,500 average daily barrels of refined products, respectively. Margins on refinery operations only are reflected as the product spread presented above. Refining and Marketing The unusually weak industry conditions adversely affected the results from the Company's refining and marketing segment. Increased demand for Alaska North Slope ("ANS") crude oil for use as a feedstock in West Coast refineries combined with an oversupply of products in Alaska and the West Coast resulted in higher feedstock costs for the Company relative to increases in its refined product sales prices. The Company's average feedstock costs increased to $16.75 per barrel for the 1995 quarter compared with $12.31 per barrel for the 1994 quarter, while the average yield value of the Company's refinery production increased to $19.70 per barrel for the 1995 quarter from $17.35 for the prior year quarter. As a result, the Company's refined product margins were severely depressed in the 1995 quarter 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. Although the industry conditions resulted in depressed margins for the Company, 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 lessened the impact of these industry conditions on the Company's refinery margins. Revenues from sales of refined products in the 1995 quarter were higher than the 1994 quarter due to higher sales prices and a 15% increase in sales volumes. 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. Included in the 1994 quarter was a $2.8 million gain from the sale of the Company's Valdez, Alaska terminal. 12 Exploration and Production Three Months Ended March 31, ---------------------- 1995 1994 ---- ---- (Dollars in millions except per unit amounts) United States: Gross operating revenues* . . . . . . . . . . . . $ 29.8 17.4 Lifting costs . . . . . . . . . . . . . . . . . . 4.8 2.3 Depreciation, depletion and amortization . . . . 8.6 3.8 Other . . . . . . . . . . . . . . . . . . . . . . ( .2) .1 --------- --------- Operating Profit - United States . . . . . . . 16.6 11.2 --------- --------- Bolivia: Gross operating revenues . . . . . . . . . . . . 2.6 2.8 Lifting costs . . . . . . . . . . . . . . . . . . .2 .2 Other . . . . . . . . . . . . . . . . . . . . . . .7 .7 --------- --------- Operating Profit - Bolivia . . . . . . . . . . 1.7 1.9 --------- --------- Total Operating Profit - Exploration and Production . . . . . . . . . . . . . . . . . . . $ 18.3 13.1 ========= ========= United States: Capital expenditures. . . . . . . . . . . . . . . $ 14.0 11.7 ========= ========= Net natural gas production (average daily Mcf) - Spot market and other . . . . . . . . . . . . . 80,275 32,817 Tennessee Gas Contract* . . . . . . . . . . . . 25,603 16,181 --------- --------- Total production . . . . . . . . . . . . . . . 105,878 48,998 ========= ========= Average natural gas sales price per Mcf - Spot market . . . . . . . . . . . . . . . . . . $ 1.42 2.01 Tennessee Gas Contract* . . . . . . . . . . . . $ 8.32 7.80 Average . . . . . . . . . . . . . . . . . . . . $ 3.09 3.92 Average lifting costs per Mcf** . . . . . . . . . $ .51 .53 Depletion per Mcf . . . . . . . . . . . . . . . . $ .90 .85 Bolivia: Net natural gas production (average daily Mcf). . 16,912 19,137 Average natural gas sales price per Mcf . . . . . $ 1.25 1.23 Net crude oil (condensate) production (average daily barrels) . . . . . . . . . . . . . . . . 552 662 Average crude oil price per barrel . . . . . . . $ 14.70 11.48 Average lifting costs per net equivalent Mcf. . . $ .09 .11 * 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 3 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 $.41 and $.44 for the 1995 and 1994 quarters, respectively. 13 Exploration and Production United States. Successful development drilling in the Bob West Field in South Texas was the primary contributing factor to this segment's improvement when comparing the 1995 quarter with the 1994 quarter. The number of producing wells in South Texas in which the Company has a working interest increased to 54 wells at the end of the 1995 quarter, compared with 33 wells at the end of the 1994 quarter. The Company's 1995 quarter results included a 116% increase in U.S. natural gas production with a $12.4 million increase in revenues. Revenues for natural gas sales during the 1995 quarter, however, were adversely affected by a 21% decline in the Company's weighted average sales price, which included a 29% drop in spot market prices. In response to the depressed spot market prices, during the 1995 quarter 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 have resumed at higher rates, approximating 137 Mmcf per day. 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 quarter, compared with the 1994 quarter, due to the increased production level, but were relatively unchanged 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 3 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. The Company's average spot market sales price was $1.42 per Mcf during the three months ended March 31, 1995. Bolivia. Results from the Company's Bolivian operations decreased by $.2 million during the 1995 quarter primarily due to a 12% decline in average daily natural gas production. During the 1994 quarter, the Company benefited from higher levels of production due to the inability of another producer to satisfy gas supply requirements. Partially offsetting the production decline was a $3.22 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 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, but with a small decrease in price. The Company's contract for the sale of natural gas to YPFB expired in 1994. Although the Company's contract with YPFB is subject to renegotiation, the Company is currently selling its natural gas production to YPFB based on the pricing terms in the contract between YPFB and YPF. 14 Oil Field Supply and Distribution Three Months Ended March 31, ---------------------- 1995 1994 ---- ---- (Dollars in millions) Gross Operating Revenues . . . . . . . . . . . . . . . $ 17.2 18.6 Costs of Sales . . . . . . . . . . . . . . . . . . . . 15.1 15.9 ------- ------- Gross Margin. . . . . . . . . . . . . . . . . . . . . 2.1 2.7 Operating Expenses and Other . . . . . . . . . . . . . 3.3 3.8 Depreciation and Amortization. . . . . . . . . . . . . .1 .1 ------- ------- Operating Loss. . . . . . . . . . . . . . . . . . . . $( 1.3) ( 1.2) ======= ======= Refined Product Sales (average daily barrels). . . . . 6,930 7,424 ======= ======= Refined product sales prices and gross margins during the 1995 quarter continued to be impacted by strong competition in an oversupplied market. Included in operating expenses in the 1994 quarter were charges of $.9 million for discontinuing the Company's environmental products marketing operations. Interest Expense Interest expense of $5.3 million in the 1995 quarter compares with $4.9 million in the 1994 quarter. The increase was primarily due to interest on the vacuum unit financing and cash borrowings under the Revolving Credit Facility. Income Taxes Income taxes of $.7 million in the 1995 quarter compare with $1.6 million in the 1994 quarter. The decrease was primarily due to lower federal and state income taxes on the Company's decreased 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. 15 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 the Company's natural gas or refined products and the resulting future impact on earnings and cash flows. Due to the effect of depressed market conditions, the Company's operations 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 while at the same time reduce the asset concentration associated with the Bob West Field. In these regards, the Company is currently evaluating the potential benefits of selling or exchanging approximately 30% of its proved reserves in the Bob West Field. The reserves being evaluated do not include acreage covered by the Tennessee Gas Contract. At the completion of the evaluation phase, the Company will decide whether to continue to pursue a sale or exchange, but a final decision could take several months. The Company is uncertain as to the impact of these initiatives upon its capital resources and liquidity, if any. 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 March 31, 1995, the borrowing base of approximately $116 million included a domestic oil and gas reserve component of $45 million. At March 31, 1995, the Company had outstanding letters of credit under the Revolving Credit Facility of approximately $47 million with no cash borrowings outstanding. Although at March 31, 1995, there were no cash borrowings outstanding under the Revolving Credit Facility, the Company from time to time borrowed under this facility during the 1995 quarter 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 March 31, 1995, the Company was in compliance with all of the covenants under the Revolving Credit Facility. Future compliance with certain financial covenants under the Revolving Credit Facility is primarily dependent on the Company's cash flows from operations, capital expenditures, levels of borrowings and the value of the Company's domestic oil and gas reserves. Based upon current depressed refinery margins, the Company anticipates that it will be required to seek a waiver or amendment from 16 its banks with respect to its refinery cash flow requirement, possibly as early as June 30, 1995. If such an event occurs, 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. Debt Obligations The Company's funded debt obligations as of March 31, 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. Reductions in long-term interest rates and increases in market capacity, along with any further improvements in the Company's credit rating, may increase the likelihood of refinancing all or a portion of the Company's public debt. A resolution of the Tennessee Gas litigation could materially affect the Company's credit rating. There can be no assurance whether or when the Company would propose a refinancing, if any. Capital Expenditures Capital spending for 1995 is expected to be financed through a combination of cash flows from operations and borrowings under the Revolving Credit Facility. For the year 1995, the Company has under consideration total capital expenditures of approximately $60 million. 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. Cash Flows At March 31, 1995, the Company's net working capital totaled $81.8 million, which included $5.6 million of cash. Components of the Company's cash flows are set forth below (in millions): Three Months Ended March 31, --------------------- 1995 1994 ---- ---- Cash Flows From (Used In): Operating Activities. . . . . . . . . . . . . . . . $ 10.6 30.3 Investing Activities. . . . . . . . . . . . . . . . ( 18.5) ( 10.2) Financing Activities. . . . . . . . . . . . . . . . ( .6) ( 7.3) -------- -------- Increase (Decrease) in Cash and Cash Equivalents . . $ ( 8.5) 12.8 ======== ======== 17 Net cash from operating activities of $10.6 million during the 1995 quarter compares to $30.3 million for the 1994 quarter. Although natural gas production from the Bob West Field increased during the 1995 quarter, lower prices received for sales of natural gas and reduced cash flows from the refining and marketing operations adversely affected the Company's cash flows from operations. 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 3 of Notes to Condensed Consolidated Financial Statements. Net cash used in investing activities of $18.5 million included $16.5 million of capital expenditures and $3.0 million for acquisition of the Kenai Pipe Line Company. Capital expenditures for the 1995 quarter included $14.0 million for the Company's exploration and production activities in South Texas, primarily for completion of five natural gas development wells. Net cash used in financing activities of $.5 million during the 1995 quarter was primarily related to payments of long-term debt. The Company's gross borrowings and repayments under its Revolving Credit Facility totaled $52.0 million during the 1995 quarter. 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 (the "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"). 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 March 1995, the Contract Price was in excess of $8.00 per Mcf, the Section 101 price was $4.88 per Mcf and the average spot market price was $1.34 per Mcf. Tennessee Gas also claimed that the contract should be considered an "output contract" under Section 2.306 of the Texas Business and Commerce Code 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 Supreme Court of Texas heard arguments in December 1994 regarding the output contract issue and certain of the issues raised by Tennessee Gas but has not yet issued its opinion. Although the outcome of any litigation is uncertain, management, based upon advice from outside legal counsel, is confident that the decision of the trial and appellate courts will ultimately be upheld as to the validity of the Tennessee Gas Contract and the Contract Price. If the Supreme Court of Texas were to affirm the appellate court ruling, the Company believes that the only issue for trial should be whether the increases in the volumes of gas tendered to Tennessee Gas from the Company's properties were made in bad faith or were unreasonably disproportionate. The appellate court decision was the first reported decision in Texas holding that a take-or-pay contract was an output contract. As a result, it is not clear what standard the trial court would be required to apply in determining whether the increases were in bad faith or unreasonably disproportionate. The appellate court acknowledged in its opinion that the standards used in evaluating other kinds of output contracts would not be appropriate in this context. The Company believes that the appropriate standard would be whether the development of the field was undertaken in 18 a manner that a prudent operator would have undertaken in the absence of an above-market sales price. Under that standard, the Company believes that, if this issue is tried, the development of the Company's gas properties and the resulting increases in volumes tendered to Tennessee Gas will be found to have been reasonable and in good faith. Accordingly, the Company has recognized revenues, net of production taxes and marketing charges, for natural gas sales through March 31, 1995, under the Tennessee Gas Contract based on the Contract Price, which net revenues aggregated $44.3 million more than the Section 101 prices and $84.4 million in excess of the spot market prices. If Tennessee Gas were ultimately to prevail in this litigation, the Company could be required to return to Tennessee Gas $52.5 million, plus interest if awarded by the court, representing the difference between the spot market price and the Contract Price received by the Company through September 17, 1994 (the date on which the Company entered into a bond agreement discussed below). In addition, the Company's calculation of the standardized measure of discounted future net cash flows relating to proved reserves in the United States at December 31, 1994 of $127 million was determined in part using the Contract Price as compared with $73 million at spot market prices. An adverse judgment in this case could have a material adverse effect on the Company. 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. The Company continues to recognize revenues under the Tennessee Gas Contract based on the Contract Price. At March 31, 1995, the Company had recognized cumulative revenues in excess of spot market prices (through September 17, 1994) and in excess of the Bond Price (subsequent to September 17, 1994) totaling $77.2 million. Receivables at March 31, 1995, included $26.6 million from Tennessee Gas, of which $24.7 million represented the difference between the Contract Price and the Bond Price. For further information regarding the Tennessee Gas Contract, see "Legal Proceedings - -- Tennessee Gas Contract" and Note 3 of Notes to Condensed Consolidated Financial Statements. 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 March 31, 1995 the Company's accruals for environmental matters, including the alleged violations of the Clean Air Act, amounted to $11.7 million. Also included in this amount is a $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 19 cannot currently be determined by the Company. For further information on environmental contingencies, see Note 3 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 3 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. 20 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 (the "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"). 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 March 1995, the Contract Price was in excess of $8.00 per Mcf, the Section 101 price was $4.88 per Mcf and the average spot market price was $1.34 per Mcf. Tennessee Gas also claimed that the contract should be considered an "output contract" under Section 2.306 of the Texas Business and Commerce Code 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 Supreme Court of Texas heard arguments in December 1994 regarding the output contract issue and certain of the issues raised by Tennessee Gas but has not yet issued its opinion. Although the outcome of any litigation is uncertain, management, based upon advice from outside legal counsel, is confident that the decision of the trial and appellate courts will ultimately be upheld as to the validity of the Tennessee Gas Contract and the Contract Price. If the Supreme Court of Texas were to affirm the appellate court ruling, the Company believes that the only issue for trial should be whether the increases in the volumes of gas tendered to Tennessee Gas from the Company's properties were made in bad faith or were unreasonably disproportionate. The appellate court decision was the first reported decision in Texas holding that a take-or-pay contract was an output contract. As a result, it is not clear what standard the trial court would be required to apply in determining whether the increases were in bad faith or unreasonably disproportionate. The appellate court acknowledged in its opinion that the standards used in evaluating other kinds of output contracts would not be appropriate in this context. The Company believes that the appropriate standard would be whether the development of the field was undertaken in a manner that a prudent operator would have undertaken in the absence of an above-market sales price. Under that standard, the Company believes that, if this issue is tried, the development of the Company's gas properties and the resulting increases in volumes tendered to Tennessee Gas will be found to have been reasonable and in good faith. Accordingly, the Company has recognized revenues, net of production taxes and marketing charges, for natural gas sales through March 31, 1995, under the Tennessee Gas Contract based on the Contract Price, which net revenues aggregated $44.3 million more than the Section 101 prices and $84.4 million in excess of the spot market prices. If Tennessee Gas were ultimately to prevail in this litigation, the Company could be required to return to Tennessee Gas $52.5 million, plus interest if awarded by the court, representing the difference between the spot market price and the Contract Price received by the Company through September 17, 1994 (the date on which the Company entered into a bond agreement discussed below). In addition, the Company's calculation of the standardized measure of discounted future net cash flows relating to proved reserves in the United States at December 31, 1994 of $127 million was determined in part using the Contract Price as compared with $73 million at spot market prices. An adverse judgment in this case could have a material adverse effect on the Company. 21 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. The Company continues to recognize revenues under the Tennessee Gas Contract based on the Contract Price. At March 31, 1995, the Company had recognized cumulative revenues in excess of spot market prices (through September 17, 1994) and in excess of the Bond Price (subsequent to September 17, 1994) totaling $77.2 million. Receivables at March 31, 1995, included $26.6 million from Tennessee Gas, of which $24.7 million represented the difference between the Contract Price and the Bond Price. For further information regarding the Tennessee Gas Contract, see Note 3 of Notes to Condensed Consolidated Financial Statements. Environmental Matters. 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 EPA has offered an Administrative Order on Consent for De Minimis Settlement to those PRP's who each contributed less than 2% of the total contamination at the Site. The Company is eligible for a de minimis settlement at the Site, and believes that its total liability for settlement will be less than $1,500. 22 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. 23 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: May 15, 1995 /s/ Michael D. Burke Michael D. Burke President and Chief Executive Officer Date: May 15, 1995 /s/ Bruce A. Smith Bruce A. Smith Executive Vice President and Chief Financial Officer 24 EXHIBIT INDEX Exhibit Number - ------- 11 Information Supporting Earnings (Loss) Per Share Computations. 27 Financial Data Schedule. 25 EX-11 2 INFORMATION SUPPORTING EARNINGS (LOSS) 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 March 31, ------------------- 1995 1994 ---- ---- PRIMARY EARNINGS (LOSS) PER SHARE COMPUTATION: Earnings before extraordinary item. . . . . . . . . . . $ 1,760 7,202 Extraordinary loss on extinguishment of debt. . . . . . - ( 4,752) -------- -------- Net earnings . . . . . . . . . . . . . . . . . . . . . 1,760 2,450 Less dividend requirements on preferred stocks. . . . . - 1,889 -------- -------- Net earnings applicable to common stock . . . . . . . $ 1,760 561 ======== ======== Average outstanding common shares . . . . . . . . . . . 24,512 18,830 Average outstanding common equivalent shares. . . . . . 607 625 -------- -------- Average outstanding common and common equivalent shares. . . . . . . . . . . . . . . . . . . . . . . 25,119 19,455 ======== ======== Primary Earnings (Loss) Per Share: Earnings before extraordinary item. . . . . . . . . . $ .07 .27 Extraordinary loss on extinguishment of debt. . . . . - ( .24) -------- -------- Net earnings . . . . . . . . . . . . . . . . . . . . $ .07 .03 ======== ======== FULLY DILUTED EARNINGS (LOSS) PER SHARE COMPUTATION: Net earnings applicable to common stock . . . . . . . . $ 1,760 561 Add dividend requirements on preferred stocks . . . . . - 1,889 -------- -------- Net earnings (loss) applicable to common stock - fully diluted . . . . . . . . . . . . . . . . . . . $ 1,760 2,450 ======== ======== Average outstanding common and common equivalent shares 25,119 19,455 Shares issuable on conversion of preferred shares . . . - 3,486 Other . . . . . . . . . . . . . . . . . . . . . . . . . - 77 -------- -------- Fully diluted shares. . . . . . . . . . . . . . . . . 25,119 23,018 ======== ======== Fully Diluted Earnings Per Share - Anti-dilutive* . . . $ .07 .03 ======== ======== * 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. 26 EX-27 3 FINANCIAL DATA SCHEDULE
5 THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM TESORO PETROLEUM CORPORATION'S FINANCIAL STATEMENTS AS OF AND FOR THE THREE MONTH PERIOD ENDED MARCH 31, 1995, AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL STATEMENTS. 1,000 3-MOS DEC-31-1995 MAR-31-1995 5,550 0 88,252 1,876 75,726 175,908 498,416 217,699 489,033 94,093 189,995 0 0 4,090 159,555 489,033 234,701 234,789 210,611 210,611 11,915 0 5,293 2,470 710 1,760 0 0 0 1,760 .07 .07
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